Energy & Power

From traditional oil and gas operations to emerging alternative and renewable platforms, Mercer Capital provides independent valuation and financial advisory services across the Energy sector

The energy and power sector encompasses companies involved in the production, transportation, generation, and distribution of energy across traditional and emerging sources. Mercer Capital provides energy and power companies with independent valuation, transaction advisory, litigation support, and related advisory services for engagements involving transactions, planning, financial reporting, and dispute-related matters.

Our professionals have experience valuing energy and power businesses across oil and gas and alternative energy markets. We understand commodity exposure, capital intensity, regulatory frameworks, and evolving market dynamics, delivering independent, well-supported analyses that inform decision-making and withstand scrutiny from stakeholders.

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Oil & Gas

Mercer Capital provides oil & gas companies, oil & gas servicers, and mineral & royalty owners with corporate valuation, litigation support, transaction advisory, and other related services.

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Mercer Capital provides renewable energy companies, energy-transition technology firms, and alternative fuel producers with corporate valuation and other financial advisory services.

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Thought leadership that informs better decisions — articles,  whitepapers, research, webinars, and more from the Mercer Capital team.

Defying the Cycle: Haynesville Production Strength in a Shifting Gas Market
Defying the Cycle: Haynesville Production Strength in a Shifting Gas Market
Haynesville shale production defied broader market softness in 2025, leading major U.S. basins with double-digit year-over-year growth despite heightened volatility and sub-cycle drilling activity. Efficiency gains, DUC drawdowns, and Gulf Coast demand dynamics allowed operators to sustain output even as natural gas prices fluctuated sharply.
Haynesville Shale M&A Update: 2025 in Review
Haynesville Shale M&A Update: 2025 in Review
Key TakeawaysHaynesville remains a strategic LNG-linked basin. 2025 transactions emphasized long-duration natural gas exposure and proximity to Gulf Coast export infrastructure, reinforcing the basin’s importance in meeting global LNG demand.International utilities drove much of the activity. Japanese power and gas companies pursued direct upstream ownership, signaling a shift from traditional offtake agreements toward greater control over U.S. gas supply.M&A was selective but meaningful in scale and intent. While overall deal volume was limited, announced transactions and reported negotiations reflected deliberate, long-term positioning rather than opportunistic shale consolidation.OverviewM&A activity in the Haynesville Shale during 2025 was marked by strategic, LNG-linked transactions and renewed international investor interest in U.S. natural gas assets. While investors remained selective relative to prior shale upcycles, transactions that did occur reflected a clear pattern: buyers focused on long-duration gas exposure, scale, and proximity to Gulf Coast export markets rather than short-term development upside.Producers and capital providers increasingly refocused efforts on the Haynesville basin during the year, including raising capital to acquire both operating assets and mineral positions. This renewed attention followed a period of subdued transaction activity and underscored the basin’s continued relevance within global natural gas portfolios.Although the Haynesville did not experience the breadth of consolidation seen in some oil-weighted plays, the size, counterparties, and strategic motivations behind 2025 transactions reinforced the basin’s role as a long-term supply source for LNG-linked demand.Announced Upstream TransactionsTokyo Gas (TG Natural Resources) / ChevronIn April 2025, Tokyo Gas Co., through its U.S. joint venture TG Natural Resources, entered into an agreement to acquire a 70% interest in Chevron’s East Texas natural gas assets for $525 million. The assets include significant Haynesville exposure and were acquired through a combination of cash consideration and capital commitments.The transaction was characterized as part of Tokyo Gas’s broader strategy to secure long-term U.S. natural gas supply and expand its upstream footprint. The deal reflects a growing trend among international utilities to obtain direct exposure to U.S. shale gas through ownership interests rather than relying solely on long-term offtake contracts or third-party supply arrangements.From an M&A perspective, the transaction highlights continued willingness among major operators to monetize non-core or minority positions while retaining operational involvement, and it underscores the Haynesville’s attractiveness to buyers with a long-term, strategic view of gas demand.JERA / Williams & GEP Haynesville IIIn October 2025, JERA Co., Japan’s largest power generator, announced an agreement to acquire Haynesville shale gas production assets from Williams Companies and GEP Haynesville II, a joint venture between GeoSouthern Energy and Blackstone. The transaction was valued at approximately $1.5 billion.This acquisition marked JERA’s first direct investment in U.S. shale gas production, representing a notable expansion of the company’s upstream exposure and reinforcing JERA’s interest in securing supply from regions with strong connectivity to U.S. LNG export infrastructure.This transaction further illustrates the appeal of the Haynesville to international buyers seeking stable, scalable gas assets and highlights the role of upstream M&A as a tool for portfolio diversification among global utilities and energy companies.Reported Negotiations (Not Announced)Mitsubishi / Aethon Energy ManagementIn June 2025, Reuters reported that Mitsubishi Corp. was in discussions to acquire Aethon Energy Management, a privately held operator with substantial Haynesville production and midstream assets. The potential transaction was reported to be valued at approximately $8 billion, though Reuters emphasized that talks were ongoing and that no deal had been finalized at the time.While the transaction was not announced during 2025, the reported discussions were notable for both their scale and the identity of the potential buyer. Aethon has long been viewed as one of the largest private platforms in the Haynesville, and any transaction involving the company would represent a significant consolidation event within the basin.The reported talks underscored the depth of international interest in Haynesville-oriented platforms and highlighted the potential for large-scale transactions even in an otherwise measured M&A environment.ConclusionWhile overall deal volume remained selective, the transactions and reported negotiations in 2025 reflected sustained global interest in U.S. natural gas assets with long-term relevance. Collectively, the transactions and negotiations discussed above point to a Haynesville M&A landscape driven less by opportunistic consolidation and more by deliberate, long-term positioning. As global energy portfolios continue to evolve, the Haynesville basin remains a focal point for strategic investment, particularly for buyers seeking exposure tied to U.S. natural gas supply and LNG export linkages.
Top 10 Oil & Gas Blog Posts of 2025
Top 10 Oil & Gas Blog Posts of 2025
Year-end 2025 is quickly approaching so that means it’s time to take a look back at the year. Here are the top ten posts for the year measured by readership.
Themes from Q3 2025 Earnings Calls
Themes from Q3 2025 Earnings Calls
Third-quarter commentary from E&P and oilfield service companies highlighted a cautious near-term outlook paired with growing confidence in long-term demand. While operators remain in “maintenance mode,” structural growth themes—LNG, data centers, offshore development, and water midstream—continue to shape strategy. Despite softer activity, companies emphasized free cash flow, efficiency, and positioning for stronger demand later in the decade.
Mineral Aggregator Valuation Multiples Study Released-Data as of 12-04-2025
Mineral Aggregator Valuation Multiples Study Released

With Market Data as of December 4, 2025

Mercer Capital has thoughtfully analyzed the corporate and capital structures of the publicly traded mineral aggregators to derive meaningful indications of enterprise value. We have also calculated valuation multiples based on a variety of metrics, including distributions and reserves, as well as earnings and production on both a historical and forward-looking basis.
Just Released: Q3 2025 Oil & Gas Industry Newsletter
Just Released: Q3 2025 Oil & Gas Industry Newsletter

Region Focus: Appalachia

Overall, the Appalachian basin enters late-2025 on firmer footing than a year ago, characterized by stable production, recovering equity performance, and improving infrastructure fundamentals. Continued progress on export capacity and incremental LNG demand should provide a constructive backdrop for basin economics heading into 2026.
Oil vs. Gas: Diverging Valuations in the Energy Patch Persist
Oil vs. Gas: Diverging Valuations in the Energy Patch Persist

U.S. Upstream Producers Are Closing 2025 with Sharply Different Stories Depending on the Molecules They Sell

2025 continues some of the same valuation trends that I have written about earlier this year. As U.S. oil producers battle with middling prices, emerging breakeven cost issues, and shrinking Tier 1 acreage, gas investors are foreseeing growth and future profitability. Investors are rewarding future demand visibility over near-term cash generation, a rare reversal in a sector long dominated by oil.
The Evolving Economics of Oilfield Water
The Evolving Economics of Oilfield Water

From Breakevens to Data Centers

The oilfield water sector continues to mature as one of the more strategically significant and rapidly changing segments of the energy value chain. At the recent 7th Annual Oilfield Water Industry Update, executives and analysts from across the industry discussed how water management is no longer a secondary operational consideration but a primary driver of production economics, infrastructure planning, and even cross-industry innovation.
Now Available: Mercer Capital’s 2025 Energy Purchase Price Allocation Study
Now Available: Mercer Capital’s 2025 Energy Purchase Price Allocation Study
The 2025 Energy Purchase Price Allocation Study provides a detailed analysis and overview of valuation and accounting trends in these sub-sectors of the energy space. This study also enables key users and preparers of financial statements to better understand the asset mix, valuation methods, and useful life trends in the energy space as they pertain to business combinations under ASC 805 and GAAP fair value standards under ASC 820. We utilized transactions that reported their purchase allocation data in calendar year 2024 and not reported in previous annual filings.
Mercer Capital’s Energy Purchase Price Allocation Study
STUDY | Mercer Capital’s Energy Purchase Price Allocation Study
This study researches and observes publicly available purchase price allocation data from companies primarily contained in one of the four sub-sectors of the energy industry: (i) exploration & production; (ii) oilfield services; (iii) midstream; and (iv) downstream. This study is unlike any other in terms of energy industry specificity and depth.The Energy Purchase Price Allocation Study provides a detailed analysis and overview of valuation and accounting trends in these sub-sectors of the energy space. This study also enables key users and preparers of financial statements to better understand the asset mix, valuation methods, and useful life trends in the energy space as they pertain to business combinations under ASC 805 and GAAP fair value standards under ASC 820. We utilized transactions that reported their purchase allocation data in calendar year 2024 and not reported in previous annual filings.This study is a useful tool for management teams, investors, auditors, and even insurance underwriters as market participants grapple with ever-increasing market complexity. It provides data and analytics for readers seeking to understand undergirding economics and deal rationale for individual transactions. The study also assists in risk assessment and underwriting of assets involved in these sectors. Further, it helps readers to better comprehend financial statement impacts of business combinations.
Whitepaper: How to Value Your Exploration and Production Company
Whitepaper: How to Value Your Exploration and Production Company
For this week’s post, we’re highlighting our whitepaper, How to Value Your Exploration and Production Company. The piece provides a comprehensive overview of the key factors that drive value in the upstream oil and gas sector, offering readers a clear framework for understanding how operational performance, reserve economics, and commodity pricing influence company worth. It also explores core energy valuation methodologies—including cash flow analysis, reserve-based approaches, and market benchmarking—to help executives, investors, and advisors navigate the complexities of assessing value in a constantly evolving energy market.
Appalachian Basin Finds Its Footing
Appalachian Basin Finds Its Footing
The economics of oil and gas production vary by region. Mercer Capital focuses on trends in the Eagle Ford, Permian, Haynesville, and Appalachian plays. The cost of producing oil and gas depends on the geological makeup of the reserve, the depth of the reserve, and the cost to transport production to market. These factors drive meaningful differences in costs across regions. This quarter, we take a closer look at the Appalachian.
Appalachian Basin M&A Update: October 2024 to September 2025
Appalachian Basin M&A Update: October 2024 to September 2025

A Quiet Consolidation Phase

Over the October 2024 through September 2025 timeframe, merger and acquisition activity in the Appalachian Basin (Marcellus / Utica / associated plays) has been relatively muted, reflecting constrained upstream deal flow across the U.S. At the same time, selective bolt-ons, midstream consolidations, and creative capital structures have surfaced where synergies and niche value remain. In this post, we examine the notable transactions and thematic drivers emerging from this period.
Upstream Valuation Through a Lender’s Lens
Upstream Valuation Through a Lender’s Lens

What Credit Analysts See

Credit analysis offers a different lens on upstream performance—one centered on sustainability rather than growth alone. Scale and production mix drive efficiency and resilience, while cost structure and netbacks expose the true quality of assets. Reserve life and replacement efficiency underpin long-term viability, and strong liquidity, hedging, and leverage discipline ultimately determine access to capital and enterprise value.
Hart Energy’s A&D Strategies and Opportunities Conference Recap
Hart Energy’s A&D Strategies and Opportunities Conference Recap
At Hart Energy’s 2025 A&D Strategies and Opportunities Conference in Dallas, two central themes emerged: the maturation of Tier 1 U.S. shale inventory and diverging dynamics between private and public players in dealmaking. The conference highlighted the evolving dynamics of the U.S. upstream oil and gas market. With Tier 1 shale assets maturing, private and public participants are behaving differently, and deal strategies have become more selective.
The One Big Beautiful Bill Act: Implications for U.S. Oil & Gas Valuations
The One Big Beautiful Bill Act: Implications for U.S. Oil & Gas Valuations
The OBBB represents a significant shift in the U.S. oil and gas industry and is a key component of the Trump Administration’s agenda for U.S. energy dominance. The BBB represents a significant shift in how public lands are managed and how our government supports energy development.
Mineral Aggregator Valuation Multiples Study Released-Data as of 08-26-2025
Mineral Aggregator Valuation Multiples Study Released

With Market Data as of August 26, 2025

Mercer Capital has thoughtfully analyzed the corporate and capital structures of the publicly traded mineral aggregators to derive meaningful indications of enterprise value. We have also calculated valuation multiples based on a variety of metrics, including distributions and reserves, as well as earnings and production on both a historical and forward-looking basis.
Mineral Aggregator Valuation Multiples Study Released-Data as of 06-11-2025
Mineral Aggregator Valuation Multiples Study Released

With Market Data as of June 11, 2025

Mercer Capital has thoughtfully analyzed the corporate and capital structures of the publicly traded mineral aggregators to derive meaningful indications of enterprise value. We have also calculated valuation multiples based on a variety of metrics, including distributions and reserves, as well as earnings and production on both a historical and forward-looking basis.
Themes from Q2 2025 Earnings Calls
Themes from Q2 2025 Earnings Calls

Disciplined Capital Allocation Meets International Opportunity Amid Domestic Uncertainty

The second quarter of 2025 brought no shortage of talking points across both oilfield services (“OFS”) providers and exploration and production (“E&P”) companies. Management teams faced questions on market softness, capital discipline, and whether the long-awaited offshore and international upcycle has truly taken hold. Some leaned into shareholder returns and consolidation, others stressed patience in a choppy pricing environment, and nearly all pointed to selective opportunities abroad as a counterweight to domestic headwinds.
Why E&P Companies Need a Quality of Earnings Analysis
Why E&P Companies Need a Quality of Earnings Analysis
The purpose of a QofE analysis is to translate historical reported (GAAP) earnings into a relevant picture of earnings and cash flow that is useful in developing credible forward-looking estimates.
Change in Republicans’ Thinking Shifts Policy Support in Renewables
Change in Republicans’ Thinking Shifts Policy Support in Renewables
While the battle continues for the hearts and minds of Americans over the debate between fossil fuels and renewables, the current Trump administration appears to be responsive to this shift by setting priorities for the development of fossil fuels.
Just Released: Q2 2025 Oil & Gas Industry Newsletter
Just Released: Q2 2025 Oil & Gas Industry Newsletter
Regional Focus: Permian Despite a late-period decline in rig counts, Permian production continued upward over the latest year. However, geopolitical forces and international trade matters pushed oil prices lower, resulting in the Permian producer stock prices being battered since June 2024, particularly in the first quarter and early second quarter of 2025.
Permian Producer Stocks Pummeled
Permian Producer Stocks Pummeled
Despite a late-period decline in rig counts, Permian production continued upward over the latest year. However, geopolitical forces and international trade matters pushed oil prices lower, resulting in the Permian producer stock prices being battered since June 2024, particularly in the first quarter and early second quarter of 2025.
Royalty Consolidation Accelerates Amid Broader E&P M&A Wave
Royalty Consolidation Accelerates Amid Broader E&P M&A Wave
The mineral and royalty sector remains active beneath the surface of headline E&P consolidation. Public mineral aggregators are executing both asset-level and corporate-scale transactions, using a disciplined mix of equity, credit, and structured consideration.
Understanding the EV/Production Multiple
Understanding the EV/Production Multiple
Multiples such as EV/Production can provide context for market pricing in the form of a range. Relying solely on a single market multiple as an indication of value can be limiting, especially when valuing a privately held company.
Viper-Sitio Transaction Signals Strategic Shift in U.S. Royalty Landscape
Viper-Sitio Transaction Signals Strategic Shift in U.S. Royalty Landscape
The Viper-Sitio merger represents a notable shift in strategy within a traditionally fragmented sector. It signals a move toward greater scale, operational leverage, and investor confidence in the royalty business model.
Capital Shifts and LNG Lifts
Capital Shifts and LNG Lifts

Takeaways from the 2025 Hart Energy Capital Conference

The energy industry is at a critical point, where producers must not only meet the ever-growing global energy demand resulting from population growth, industrialization, and the increasing electrification of uses, but also adapt to ever-changing environmental regulations and shifting societal expectations related to sustainable practices.
Upstream Natural Gas Valuations: A Big Year
Upstream Natural Gas Valuations: A Big Year
Cash flows are seen to pick up significantly in the future for upstream natural gas producers.
Should You Choose an Industry or Valuation Expert?
Should You Choose an Industry or Valuation Expert?
In the complex world of the oil & gas industry, a nuanced understanding of industry intricacies and valuation principles is vital. While it's common to find specialists in either industry knowledge or valuation methods, a complete solution requires a synergy of both these domains. In this post, we explore the unique benefits of both industry and valuation experts before delving into why a firm with expertise in both these areas is the best choice for oil & gas industry companies.
Oilfield Services Companies and How To Value Them
Oilfield Services Companies and How To Value Them
Understanding the value of an oilfield services (OFS) company is by its very nature a complex matter. As participants in the greater energy industry, situated between the exploration and production (E&P) companies and midstream companies, the OFS sub-sector is quite broad and includes a wide variety of businesses.
Oilfield Services Update for 2025
Oilfield Services Update for 2025
In this post, we focus on the Oilfield Services (OFS) industry. In particular, we cover changes related to the recent recovery in activity level, the influences of technological advances, the push for energy independence, and expectations going forward.
Just Released: Q1 2025 Oil & Gas Industry Newsletter
Just Released: Q1 2025 Oil & Gas Industry Newsletter

Regional Focus: Eagle Ford

Mercer Capital’s Value Focus: Exploration & Production newsletter provides an overview of the industry through supply and demand analysis, commodity pricing, and public market performance. In this quarter’s issue, we focus on the Eagle Ford.
Uncertainty Rules the Day
Uncertainty Rules the Day

Oil Markets Bewildered as World Trade Patterns Shift

Oil markets and energy companies are wrestling with understanding changes in domestic and international energy markets. As company outlooks become cloudier, uncertainty is on the rise. This has been developing for several weeks now, with some early indications showing that executives and investors don’t quite know how to respond yet.
Eagle Ford Production Edges Downward Again on Reduced Drilling
Eagle Ford Production Edges Downward Again on Reduced Drilling
The economics of oil & gas production vary by region. Mercer Capital focuses on trends in several plays including the Eagle Ford, Permian, Haynesville, and Marcellus and Utica. This quarter we take a closer look at the Eagle Ford.
Where Have All the Eagle Ford Deals Gone?
Where Have All the Eagle Ford Deals Gone?
Over the past 12 months, deal activity in the Eagle Ford remained stagnant, with only two pure Eagle Ford Shale deals closing compared to two transactions closed in the prior 12-month period, according to Shale Experts.
Challenges for U.S. Drilling Amid Tariff Uncertainties
Challenges for U.S. Drilling Amid Tariff Uncertainties
Natural gas producers have continued to reduce costs and refrain from increasing production despite strong fourth-quarter earnings that surpassed consensus expectations.
EP Third Quarter 2025 Appalachia
E&P Third Quarter 2025

Region Focus: Appalachia

Appalachia // The Appalachian basin enters late-2025 on firmer footing than a year ago, characterized by stable production, recovering equity performance, and improving infrastructure fundamentals
EP Second Quarter 2025 Permian
E&P Second Quarter 2025

Region Focus: Permian

Permian // The Permian basin continues to serve as the centerpiece of the U.S. shale revolution.
Key Components in a Typical Oil & Gas Lease
Key Components in a Typical Oil & Gas Lease
When negotiating and drafting oil and gas leases, understanding the basic framework that governs these agreements is essential. While there is no true “standard” lease, the primary areas and considerations of an oil and gas lease are discussed in this post.
U.S. LNG in 2025
U.S. LNG in 2025

The Future is Bright, Though with Potential Headwinds

Expectations for the LNG industry in 2025 were modestly positive before the November 2024 U.S. elections but are notably more robust with the transition from the decidedly pro-green/renewable, anti-carbon energy Biden administration to the decidedly pro-American energy dominance Trump administration. However, as always true of domestic commodity markets subject to international market influences, the outlook for the U.S. LNG industry in 2025 is tempered by a number of potential domestic, international, and geopolitical pressures that could hamper actual results relative to expectations.
Mineral Aggregator Valuation Multiples Study Released-Data as of 03-12-2025
Mineral Aggregator Valuation Multiples Study Released

With Market Data as of March 12, 2025

Mercer Capital has thoughtfully analyzed the corporate and capital structures of the publicly traded mineral aggregators to derive meaningful indications of enterprise value. We have also calculated valuation multiples based on a variety of metrics, including distributions and reserves, as well as earnings and production on both a historical and forward-looking basis.
How to Understand Your Mineral Interests
How to Understand Your Mineral Interests
Because of the popularity of this post, we revisit it this week. Originally published in 2019, this post is as a guide for mineral owners who are seeking to learn more about what they own.
Themes from Q4 Earnings Calls
Themes from Q4 2024 Earnings Calls

Upstream (E&P) and Oilfield Service (“OFS”) Companies

Companies are evaluating the trade-offs between optimizing existing assets and pursuing mergers and acquisitions. Capital allocation remains a focal point, with an emphasis on debt reduction and shareholder returns. Additionally, firms are positioning themselves to navigate evolving market conditions, ready to capitalize on emerging opportunities. This analysis offers valuable insight into the strategies industry leaders are employing for the future.
Asset Retirement Obligations in Oil & Gas
Asset Retirement Obligations in Oil & Gas

Their Impact on Valuation & Transactions

An asset retirement obligation (ARO) in oil and gas refers to the legal or regulatory requirement for a company to dismantle, remove, and restore a site once an asset (such as an oil well, offshore platform, or pipeline) reaches the end of its useful life. These obligations arise due to environmental laws and lease agreements requiring companies to clean up and restore the land or seabed. Typical costs include plugging and abandonment, reclamation, and remediation.
The Oil & Gas Industry is Pumped Up
The Oil & Gas Industry is Pumped Up

NAPE 2025 Recap

Mercer Capital’s Bryce Erickson and Andy Frew insights from the NAPE (North American Prospect Expo) summit on February 5th and 6th, 2025 in Houston, Texas.
The Uinta Basin Resurgence
The Uinta Basin Resurgence
The Uinta Basin has gained renewed relevance due to advancements in fracking and horizontal drilling and is increasing in significance as oil and gas companies are priced out of the Permian. While transportation challenges remain due to the unique properties of the basin's waxy crude oil, the region's potential is attracting significant attention, especially as companies seek acreage outside the increasingly competitive and expensive Permian Basin. With renewed investment and interest from both public and private operators, the Uinta Basin is poised to play a growing role in U.S. oil production.
The Latest in Natural Gas Valuations
The Latest in Natural Gas Valuations

Continued Optimism for Global Demand Buoys Multiples

The world is getting more direct access to LNG than ever before. Natural gas is becoming more globally portable. Going forward, it will help stabilize regional prices and market volatilities, which, in turn, will help U.S. producers that have more gas than the U.S. needs. Investors are optimistic that as more global portability of gas becomes available, more opportunities await to maximize potential in U.S. gas plays.
Just Released: Q4 2024 Oil & Gas Industry Newsletter
Just Released: Q4 2024 Oil & Gas Industry Newsletter

Regional Focus: Bakken, DJ Basin, Woodford Shale, Uinta, and the SCOOP/STACK

Mercer Capital’s Value Focus: Exploration & Production newsletter provides an overview of the industry through supply and demand analysis, commodity pricing, and public market performance. In addition, this quarterly issue focuses on the Bakken, DJ Basin, and Woodford Shale, along with the Uinta Basin and the SCOOP/STACK.
2025 U.S. Oil Outlook
2025 U.S. Oil Outlook

Don’t Count On A "Drill Baby Drill" Mentality

The November election brought optimism to many oil producers who felt hamstrung by the Biden Administration’s policies. Even Biden’s ban on offshore drilling is expected to be challenged or changed when Trump is sworn in. However, administrations can only do so much when it comes to global supply and demand dynamics. In fact, they can usually do little in the big picture; and the big picture is that there is probably going to be more supply coming online in 2025 than demand to meet it. Therefore, U.S. upstream producers are not planning on blowing their budget on aggressive drilling plans, no matter what Trump says, especially considering the lukewarm pricing environment that the market foresees. In addition, the U.S.’ shale dominance may be headed towards inevitable decline. There’s a lot to consider, so let us jump in.
Examining Bakken, DJ Basin, and Woodford Shale Production and Activity
Examining Bakken, DJ Basin, and Woodford Shale Production and Activity
The economics of oil & gas production vary by region. Mercer Capital regularly covers trends in the Eagle Ford, Permian, and Appalachian plays. The cost of producing oil and gas depends on the geological makeup of the reserve, its depth, and the cost of transporting raw crude to market. These factors lead to varying production costs across regions. This quarter, we depart from our regular coverage and take a closer look at the Bakken, DJ Basin, and Woodford Shale.
Shining Some Light on Four Overshadowed Oil and Gas Plays
Shining Some Light on Four Overshadowed Oil and Gas Plays

Uinta Basin, Bakken Shale, DJ Basin, and SCOOP/STACK

The Mercer Capital Oil and Gas industry team covers merger and acquisition activity as well as provides an economic profile for four primary oil and gas plays: Permian Basin, Eagle Ford Shale, Haynesville Shale, and Marcellus & Utica Shale. This week's blog offers economic and M&A snapshots into four more plays: Uinta Basin, Bakken Shale, DJ Basin, and SCOOP/STACK.
EP First Quarter 2025 Eagle Ford
E&P First Quarter 2025

Region Focus: Eagle Ford

Eagle Ford // Despite a notable rig count decline, Eagle Ford production generally remained about flat over the twelve months ended March 2025.
Top 10 Oil & Gas Blog Posts of 2024
Top 10 Oil & Gas Blog Posts of 2024
Year-end 2024 is quickly approaching so that means it's time to take a look back at the year. Here are the top ten posts for the year measured by readership. Click on any of the post titles to revisit the post.
Mineral Aggregator Valuation Multiples Study Released-Data as of 12-03-2024
Mineral Aggregator Valuation Multiples Study Released

With Market Data as of December 3, 2024

Mercer Capital has thoughtfully analyzed the corporate and capital structures of the publicly traded mineral aggregators to derive meaningful indications of enterprise value. We have also calculated valuation multiples based on a variety of metrics, including distributions and reserves, as well as earnings and production on both a historical and forward-looking basis.
Themes from Q3 2024 Energy Earnings Calls
Themes from Q3 2024 Energy Earnings Calls

Upstream (E&P) and Oilfield Service (“OFS”) Companies

The earnings calls from the third quarter focused on technological efficiency, optimized capital allocation, and expectations for natural gas demand in the long term.
Is There a Ticking Time Bomb Lurking in Your Buy-Sell Agreement?
Is There a Ticking Time Bomb Lurking in Your Buy-Sell Agreement?
Buy-sell agreements don’t matter until they do. When written well and understood by all the parties, buy-sell agreements can minimize headaches when a company hits one of life’s inevitable potholes. But far too many are written poorly and/or misunderstood. Directors are always eager to discuss best practices for buy-sell agreements. In this week's post, Travis Harms, President of Mercer Capital, talks to our founder and author of four books on buy-sell agreements, Chris Mercer, and asks, “Is there a ticking time bomb lurking in your business?”
National Association of Royalty Owners (NARO) National Convention
National Association of Royalty Owners (NARO) National Convention
This year’s National Association of Royalty Owners (NARO) National Convention was held in Houston and Mercer Capital’s Bryce Erickson, ASA, MRICS and David Smith, CFA, ASA had the privilege of attending. NARO has represented the interests of oil and gas royalty owners for over 40 years, seeking to support, advocate and educate for the empowerment of mineral and royalty owners.
D CEO's 2024 Energy Awards
D CEO's 2024 Energy Awards
This year, Mercer Capital had the privilege to sponsor and attend the 2024 D CEO Energy Awards, an event that celebrates the energy sector and honors leadership and companies from across the value chain that impact the Dallas-Fort Worth metroplex.
Now Available: Mercer Capital’s 2024 Energy Purchase Price Allocation Study
Now Available: Mercer Capital’s 2024 Energy Purchase Price Allocation Study
Mercer Capital is pleased to announce the release of the 2024 Energy Purchase Price Allocation Study.This study researches and observes publicly available purchase price allocation data from companies primarily contained in one of the four sub-sectors of the energy industry: (i) exploration & production; (ii) oilfield services; (iii) midstream; and (iv) downstream. This study is unlike any other in terms of energy industry specificity and depth.The 2024 Energy Purchase Price Allocation Study provides a detailed analysis and overview of valuation and accounting trends in these sub-sectors of the energy space. This study also enables key users and preparers of financial statements to better understand the asset mix, valuation methods, and useful life trends in the energy space as they pertain to business combinations under ASC 805 and GAAP fair value standards under ASC 820. We utilized transactions that reported their purchase allocation data in calendar year 2023 and not reported in previous annual filings.This study is a useful tool for management teams, investors, auditors, and even insurance underwriters as market participants grapple with ever-increasing market complexity. It provides data and analytics for readers seeking to understand undergirding economics and deal rationale for individual transactions. The study also assists in risk assessment and underwriting of assets involved in these sectors. Further, it helps readers to better comprehend financial statement impacts of business combinations.DOWNLOAD THE STUDY
"Hayne" in There, Haynesville!
"Hayne" in There, Haynesville!
The Haynesville/Bossier Shale was discovered in 2008 in East Texas and Western Louisiana. As a play, it differs from other reserves. The reservoirs are highly pressured and deeper than most other reservoirs. The average hydrocarbon reservoir in Haynesville is almost 12,000 feet deep, far exceeding the average depth of 6,000 feet (per the most recently available data from the EIA). This extra depth can make drilling activities more expensive. This is not just because of the additional pipe length. Temperatures at such great depths can be extremely high, so the equipment to drill wells must be able to withstand particularly high temperatures. Such equipment typically costs more than standard drilling equipment. Additionally, Haynesville is saturated with smaller independent operators compared to plays like the Eagle Ford and the Permian over the last decade. The greater share of independent operators can lead to relatively higher average drilling costs from smaller average contract sizes.Source: Family Tree Oil & Gas CorporationDespite these challenges, Haynesville has a number of advantages over other basins. While the equipment required to complete projects is more expensive, Haynesville is located extremely close to the Gulf of Mexico and its LNG export terminals, especially compared with the Marcellus in Appalachia. While the Marcellus may have cheaper operating costs at the well level because it is not as deep as the Haynesville, the long transportation distance required for its reserves to be exported eats away at its natural price advantage. The Permian is relatively close to export terminals and has cheaper operation costs, but the gas there has faced transmission problems.TransactionsHaynesville has seen unsteady transaction activity over the last ten years. The chart below shows that M&A has been sporadic, with most activity in the last five years occurring in 2021 and additional smaller closings in 2Q 2022 and 3Q 2023. M&A activity in 2024 has been relatively limited per Shale Experts, likely because of the harsh operating conditions for gas-forward plays.The most notable Haynesville transaction in the Shale Experts data occurred in the second quarter of 2018 when B.P. America Production Company (a subsidiary of B.P.) acquired the assets of Petrohawk Energy Corporation, (at the time) a wholly owned subsidiary of BHP Billiton Petroleum (North America) Inc. The total value of the transaction was $10 billion. Notably, the Petrohawk assets included were not just in Haynesville but also in the Eagle Ford and the Permian Basins. As such, it is not strictly comparable with the other transactions shown in the chart. A specific breakout of the value per basin is unavailable, but the transaction’s press release did include the information summarized in the table below the chart. Data per Shale Experts Notably excluded from the Shale Experts data is Chesapeake Energy’s acquisition of Southwestern Energy in January 2024 (which we have written about previously). The resulting entity, known as Expand Energy, involves a total consideration of $7.4 billion. Through the deal, Chesapeake acquired 7.9 bcf/d from Southwestern’s assets in the Appalachian and Haynesville. In recent news, word has spread that Chevron Corporation (CVX) is discussing selling its Haynesville assets with Tokyo Gas. Chevron’s portfolio includes 72 thousand acres of undeveloped land. In the same publication, the author speculates that the potential transaction could be worth up to $1 billion. Tokyo Gas’s interest in the Haynesville assets may be related to Japan’s reliance on imported fossil fuels. Before its conversations with Chevron, Tokyo Gas had also completed an acquisition of Rockcliff Energy for $2.7 billion. As of the writing of this post, the Rockcliff assets contribute as much as 1.3 bcf of gas per day to Tokyo Gas.ActivityIn the last twelve months, Shale Experts shows that there have been 232 total deals completed in Haynesville. These completions have been heavily concentrated among a few operators, as shown above. The top eight operators have a total of 216 completions, representing 93% of all completed deals since the start of 3Q 2023. The chart below shows that transactions have been trending downward since the second quarter of 2023. [caption id="" align="alignnone" width="1072"]Data per Shale Experts[/caption] Since it is overwhelmingly a gas-focused basin, Haynesville producers have been hit hard by declining natural gas prices. As of February 2024, S&P estimated that the average breakeven price for efficient operators in the Haynesville Shale was $2.67/MMBtu. For less efficient operators, wellhead clearing prices are well above $3.00/MMbtu. For context, the most recent natural gas weekly update from the EIA places the Henry Hub spot price at $2.42/MMbtu. At current prices, there simply is no incentive for new completions in Haynesville despite its large reserves and convenient geography. The Biden Administration’s pause on new LNG export approvals has had a brutal impact on the Haynesville Shale. Companies have hesitated to commit to new projects without the certainty of being able to export LNG. As of the writing of this post, the pause is still in place. In the longer term, things look much more positive. There are already indications that LNG demand is rising faster than previously expected. Shale operators across the board are looking to lower their capital expenditures without negatively impacting production, and the data shows that they have been very successful in the Haynesville Basin. Over the twelve months leading up to September 2024, rig counts decreased by 15.4% YoY, while production only decreased by 10.1% over the same period (for additional detail, see Mercer Capital’s 3Q 2024 E&P Newsletter). If this trend continues, the decreased clearing price for natural gas operators in Haynesville will cause operations in that area to be economical once again. In December 2023, Hart Energy published a report predicting that U.S. LNG capacity will increase from 13 Bcf/d in 2024 to 25 Bcf/d by 2030. Per Hart Energy, Haynesville will be a critical provider of this additional capacity, as the Haynesville is expected to provide 13Bcf/d of that additional demand, making it the dominant provider of a massively ballooning market. One can see the gap between short-term and long-term expectations by comparing the production numbers above with the changes in capacity shown in the graph below (courtesy of Enverus Intelligence). While current production is low, companies are making significant investments in expanding their LNG export capacity. Naturally, a large portion of these exports will be occurring in the Haynesville Basin. But put simply, there are good times ahead. Mercer Capital has assisted many clients with various valuation needs in the oil and gas industry in North America and globally. In addition to our corporate valuation services, Mercer Capital provides investment banking and transaction advisory services to a broad range of public and private companies and financial institutions. We have relevant experience working with companies in the oil and gas space and can leverage our historical valuation and investment banking experience to help you navigate a critical transaction, providing timely, accurate, and reliable results. Contact a Mercer Capital professional to discuss your needs in confidence.Additional Sources:Assorted data from Shale ExpertsAssorted data from the U.S. Energy Information Administration“Haynesville/Bossier Shale Information & Statistics”“Haynesville Region Drilling Productivity Report”
Just Released: 3Q24 Exploration & Production Newsletter
Just Released: 3Q24 Exploration & Production Newsletter
Mercer Capital’s Value Focus: Exploration & Production newsletter provides an overview of the industry through supply and demand analysis, commodity pricing, and public market performance. In addition, each issue of this quarterly newsletter focuses on a region, including Eagle Ford, Permian, Appalachia, and Haynesville, examining general economic and industry trends. In this quarter's issue, we focus on the Appalachian basin.
Should Appalachian Natural Gas Producers’ Stock Price Resiliency Be Surprising?
Should Appalachian Natural Gas Producers’ Stock Price Resiliency Be Surprising?
In a year where natural gas prices have spent almost the entire year under $3.00 per mcf, including a few months under $2.00, the stock prices of publicly traded Appalachian gas producers have remained remarkably stable. In fact, Antero Resources’ price is up this year and Range Resources is basically flat for the year so far. Others such as EQT and Coterra Energy are down only marginally. This could come across as surprising. Appalachia has some disadvantages to other US gas producing basins, such as takeaway capacity, logistics, and longer distances to major LNG production facilities. However, since 2022 the stock market has held steady for these companies; of which this confidence has outlasted commodity price and earnings declines over the past two years.
EP Fourth Quarter 2024 Bakken DJ Basin Woodford Shale
E&P Fourth Quarter 2024

Bakken, DJ Basin, and Woodford Shale

Bakken, DJ Basin, and Woodford Shale // As a supplement to our usual regional coverage, this quarter we take a closer look at the Bakken, DJ Basin, and Woodford Shale. On an oil equivalent basis, the DJ Basin ended the review period 2% below production levels from a year earlier, while the Bakken ended at nearly 5% lower. Only the Woodford Shale ended the review period at a level above its November 2023 production, though at a negligible 0.1% higher.
New Book: "Buy-Sell Agreements: Valuation Handbook for Attorneys"
New Book: "Buy-Sell Agreements: Valuation Handbook for Attorneys"
We are excited to share the release of our latest book Buy-Sell Agreements: Valuation Handbook for Attorneys authored by Z. Christopher Mercer, FASA, CFA, ASA and published by the American Bar Association. This week, we share an excerpt from the book that discusses what you can expect to find in the full copy. Whether you are an attorney who advises clients on their buy-sell agreements or are a party to a buy-sell agreement, you will find important information in this book.
Navigating Challenges in Appalachian Production
Navigating Challenges in Appalachian Production
The economics of oil & gas production vary by region. Mercer Capital focuses on trends in the Eagle Ford, Permian, Haynesville, and Marcellus and Utica plays. The cost of producing oil and gas depends on the geological makeup of the reserve, depth of the reserve, and cost to transport the raw crude to market. We can observe different costs in different regions depending on these factors. This quarter, we take a closer look at the Marcellus and Utica shales.
Observing the Negotiations of the Chesapeake - Southwestern Merger
Observing the Negotiations of the Chesapeake - Southwestern Merger

A Marcellus and Utica Shale M&A Update

M&A activity among upstream participants in the Marcellus and Utica Shales has been sparse in recent years, with Shale Experts reporting only one transaction since November 2022. In a departure from our typical analysis and discussion of recent deals in the upstream oil and gas industry, this week’s Energy Valuation Insights blog takes a break from deal multiples and observes the negotiations of the $7.4 billion merger between Chesapeake Energy Corp. (“Chesapeake”) and Southwestern Energy Co. (“Southwestern”), a significant player in the Marcellus Shale.
Mineral Aggregator Valuation Multiples Study Released-Data as of 09-03-2024
Mineral Aggregator Valuation Multiples Study Released

With Market Data as of September 3, 2024

Mercer Capital has thoughtfully analyzed the corporate and capital structures of the publicly traded mineral aggregators to derive meaningful indications of enterprise value. We have also calculated valuation multiples based on a variety of metrics, including distributions and reserves, as well as earnings and production on both a historical and forward-looking basis.
Themes from Q2 2024 Energy Earnings Calls
Themes from Q2 2024 Energy Earnings Calls

Upstream (E&P) and Oilfield Service (“OFS”) Companies

In our prior earnings call post, Themes from Q1 2024 Energy Earnings Calls, we touched on how the Upstream (“E&P”) and Oilfield Services (“OFS”) segments emphasized their dividend and share buyback programs and the industry’s response to depressed natural gas prices. This week, we explore the Q2 2024 earnings calls of Upstream and OFS companies, highlighting the significance of this quarter’s themes across the entire sector.
Unlocking Value in the Oil & Gas Industry
Unlocking Value in the Oil & Gas Industry
The oil and gas industry is constantly changing, with a lot of moving parts and financial complexities. Accurate valuation of assets within this sector is critical for making informed strategic decisions. At Mercer Capital, we have cultivated a deep understanding of the oil and gas industry through decades of experience. To share our knowledge and insights, we have produced three complimentary whitepapers for our blog readers.How to Value Your Exploration & Production CompanyThe valuation of exploration and production (E&P) companies is a complex process influenced by a multitude of factors, including price volatility, technology, regulation, and different drilling economies depending on the play. Our updated whitepaper provides insights into the financial considerations and key valuation methodologies for E&P companies. By understanding the drivers of value, companies can optimize their strategic direction and financial performance. Download hereUnderstanding Oilfield Services Companies & How to Value ThemThe oilfield services (OFS) industry is characterized by its cyclical nature. The unpredictable cyclicality of the OFS industry requires careful consideration of many industry-wide and company-specific factors in developing a reasonable forecast of future operating results. Our whitepaper describes the key drivers and indicators of the OFS industry, as well as the key valuation methodologies of an OFS company. By understanding the key factors that impact the value of OFS companies, industry participants can make informed decisions about mergers, acquisitions, and capital allocation. Download hereHow to Value an Oil & Gas Royalty InterestA lack of knowledge regarding the worth of a royalty interest could be very costly. This can manifest itself in a number of ways. A shrewd buyer may offer a bid far below the interest’s fair market value; opportunities for successful liquidity may be missed; or estate planning could be incorrectly implemented based on misunderstandings about value. Understanding how royalty interests are properly appraised will ensure that you maximize the value of your royalty, whenever and however you decide to transfer it. Download hereConclusionAt Mercer Capital, we are committed to providing valuable insights and resources to the oil and gas industry. Our whitepapers on E&P companies, OFS companies, and valuing royalty interests offer a comprehensive understanding of the valuation complexities within this sector. We hope you find them helpful.
What Does the Valuation Process Entail for an Oil and Gas Royalty Interest?
What Does the Valuation Process Entail for an Oil and Gas Royalty Interest?
A lack of knowledge regarding the worth of a royalty interest could be very costly. This can manifest itself in a number of ways. A shrewd buyer may offer a bid far below the interest’s fair market value; opportunities for successful liquidity may be missed; or estate planning could be incorrectly implemented based on misunderstandings about value. Understanding how royalty interests are properly appraised will ensure that you maximize the value of your royalty, whenever and however you decide to transfer it.
What Does the Valuation Process Entail for an E&P Company?
What Does the Valuation Process Entail for an E&P Company?
A lack of knowledge regarding the value of your business could be very costly. Opportunities for successful liquidity may be missed or estate planning could be incorrectly implemented based on misunderstandings about value. In addition, understanding how exploration and production companies are valued may help you consider how to grow the value of your business and maximize your return when it comes time to sell.
Premiums for Inventory Scale
Premiums for Inventory Scale
In the last year, M&A activity in the upstream area of the oil and gas industry has increasingly become top-heavy, characterized by several headline deals. While the broader North American E&P deal count has been shrinking since 2022, a handful of major acquisitions in the last year have led to a spike in upstream M&A spending.
What’s “Play”-ing in the DJ Basin?
What’s “Play”-ing in the DJ Basin?

An Introduction to the Denver-Julesburg Basin

The Denver-Julesburg (“DJ”) Basin is a vast and geologically complex basin marked by sedimentary layering, tectonic shifts, and hydrocarbon generation. Encompassing an area of approximately 20,000 square miles, it stretches across regions of Colorado, Wyoming, Nebraska, and Kansas. Notable within the basin are various fields and geological formations, including the Wattenberg Field, Niobrara, Codell, Greenhorn, Adena Field, Hereford area, and the Redtail Field area.
Just Released | 2Q24 Exploration & Production Newsletter
Just Released | 2Q24 Exploration & Production Newsletter

Region Focus: Permian

Mercer Capital’s Value Focus: Exploration & Production newsletter provides an overview of the industry through supply and demand analysis, commodity pricing, and public market performance. In addition, each issue of this quarterly newsletter focuses on a region, including Eagle Ford, Permian, Appalachia, and Haynesville, examining general economic and industry trends. In this quarter's issue, we focus on the Permian.
EP Third Quarter 2024 Appalachian Basin
E&P Third Quarter 2024

Appalachian Basin

Appalachian Basin // Appalachian production declined over the last twelve months due to reduced drilling activity, driven by low natural gas prices and high storage inventory.
Acquisition Premiums Return to the Oil Patch
Acquisition Premiums Return to the Oil Patch
The shale industry is showing signs of maturity. Some acquisition trends appear to be burgeoning, such as acquisition premiums, more debt, and looser hedging requirements. These portend higher values and perhaps more of an emphasis on longer-term drilling inventory as opposed to nearer-term production metrics. Let us take a quick look at them.
Permian Production Growth Stands Alone
Permian Production Growth Stands Alone
The economics of Oil & Gas production vary by region. Mercer Capital focuses on trends in the Permian, Eagle Ford, Haynesville, and Marcellus and Utica plays. The cost of producing oil and gas depends on the geological makeup of the reserve, the depth of the reserve, and the cost of transporting the raw crude to market. We can observe different costs in different regions depending on these factors. In this post, we take a closer look at the Permian.
Large Acquisitions Dominate the Permian M&A Landscape
Large Acquisitions Dominate the Permian M&A Landscape
Transaction activity in the Permian Basin declined over the past 12 months, with the transaction count decreasing 53% to nine deals, a decline from the 19 deals that occurred over the prior 12-month period. This level is also well below the 21 deals that occurred in the 12-month period ended mid-June 2022 and the 27 transactions that closed during the same time period in 2021.
Mineral Aggregator Valuation Multiples Study Released-Data as of 06-03-2024
Mineral Aggregator Valuation Multiples Study Released

With Market Data as of June 3, 2024

Mercer Capital has thoughtfully analyzed the corporate and capital structures of the publicly traded mineral aggregators to derive meaningful indications of enterprise value. We have also calculated valuation multiples based on a variety of metrics, including distributions and reserves, as well as earnings and production on both a historical and forward-looking basis.
Themes from Q1 2024 Energy Earnings Calls
Themes from Q1 2024 Energy Earnings Calls

Upstream (E&P) and Oilfield Service (“OFS”) Companies

In our prior earnings call post, Themes from Q4 2023 Energy Earnings Calls, we touched on the global focus that both the Upstream and OFS segments had focused on and the persistent drive to optimize efficiency in well operations and services with technological advancements, durable inventory, and more. This week, we explore the Q1 2024 earnings calls of upstream and OFS companies, highlighting the appearance of this quarter’s themes across the entire sector.
Oilfield Water Industry Update, Trends, and the Future
Oilfield Water Industry Update, Trends, and the Future
The oilfield water industry (OFW, or midstream water) continues to grow in importance within the general upstream energy industry. So much so that while historically considered part of the Oilfield Services Industry (OFS), midstream water is now considered its own industry within the upstream space, separate from the more general OFS. In this week’s Energy Valuation Insights blog, we explore the current status, trends, and expectations for the future of midstream water.
SilverBow’s Shareholder Brawl
SilverBow’s Shareholder Brawl
It is an election year, and the battle is on. SilverBow Resources, a publicly traded oil and gas company operating in South Texas’ Eagle Ford shale, is wrapped up in a big conflict with some of its own shareholders. Kimmeridge Energy Management, both a large shareholder and a rival operator in the Eagle Ford, has proposed a merger (which it, at least temporarily, withdrew last month), and now is proposing several new board members in a proxy battle. The primary question centers on the direction of SilverBow’s value enhancement strategy. However, it appears this strategy hinges, in part, on its debt position, and dividend policy. Management has one idea on how this should go; Kimmeridge clearly has another.This clash has arisen from a myriad of circumstances, but it could reasonably be condensed down to two dynamics: leveraged acquisitions in the past few years and the drop in gas prices from their highs in 2022. Since 2021 SilverBow has made several acquisitions. These acquisitions, highlighted by its purchase of Sundance Energy in 2022 and most recently Chesapeake’s Eagle Ford portfolio in the second half of 2023, can be broadly characterized by three things: (i) mostly oil and liquids production driven (a change from their more historically gas heavy portfolio), (ii) purchased at opportunistic prices (SilverBow’s blended acquisition price to flowing barrel metric was approximately $25,000 for its eight deals since the second half of 2021 compared to other publicly traded oil and liquids tilted Eagle Ford producers such as Magnolia and SM Energy who both trade for over $40,000 per flowing barrel), and (iii) mostly funded with debt.The good news for SilverBow is that oil and natural gas liquids tend to be higher-margin products than gas right now, and SilverBow’s EBITDA margin was relatively high (79%) to show for it. By contrast, Comstock Resources, a pure-play gas producer in the Haynesville Shale, has had its margin battered by low gas prices in 2023. Through these acquisitions, SilverBow has shifted its production mix significantly and it creates optionality to drill for oil and liquids during periods of low gas prices. Although SilverBow is still producing relatively more gas than its Eagle Ford peers such as SM Energy, Magnolia, or EOG it is now much more liquids-driven than in recent years. In addition, funding with debt is usually cheaper than equity, so it offers a leveraged return opportunity for shareholders. However, the trade-off is that too much debt can be risky. SilverBow used to be Swift Energy but filed bankruptcy in 2015 and restructured after the collapse of oil prices, so it has a history of too much debt in the capital structure at the wrong time. This is worrisome to investors and it can tamp down on equity value. Equity markets for the upstream sector have frowned on heavy debt loads for several years now in the wake of bankruptcies after 2014.How Much Debt Is Too Much Debt?What defines a heavy debt load? It depends. The ratio of debt to EBITDA is cited often in the industry. These days at or below a 1.0x ratio is what companies frequently aim for, SilverBow included. However, there is not a definitive answer to the question. From a capital structure perspective, SilverBow has a higher debt-to-equity market capitalization percentage than the companies listed below that have varying similarities to SilverBow: Kimmeridge has criticized SilverBow for taking on this much debt and offered to inject cash to pay it down in its now-abandoned merger proposal. Management has countered with its position that the value and optionality it received in its acquisitions will allow the company to reap high margins and cash flow to accelerate debt repayment and eventually get to that 1.0x debt ratio by the end of 2025. Kimmeridge seems to believe that if SilverBow de-levers more quickly, then the stock price will rise more quickly. This is logical, but that would require selling equity or assets or both.Dividends MatterDividends have been a big trend in the oil and gas industry. Investors have pined for oil and gas companies to pay dividends for many years now. Growth and reinvestment have been curtailed in favor of direct shareholder returns in the form of stock buybacks and more importantly, dividends. SilverBow does not pay a dividend. Most publicly traded peers do. Companies that pay a dividend tend to have higher multiples as well. Kimmeridge has pointed this out and also proposed a dividend in their merger proposal. However, adding a dividend is not a guarantee of a value boost. Comstock Resources suspended its dividend early in 2024, and its stock has gone up significantly since then. However, it is also a gas producer only, which has hamstrung it in a cash burn position so far in 2024. SilverBow’s shift towards liquids has buoyed its cash flow.Value Now Or Value Later?The market has shown skepticism from a valuation standpoint of SilverBow’s acquisition appetite over the past few years. As such its valuation metrics lag almost everyone in this group in a meaningful way:It is notable that although SilverBow is increasingly liquids-driven and has excellent margins, its valuation multiples still lag this group. Even Vital Energy, which also has a lot of debt and doesn’t pay a dividend either, has superior metrics. If SilverBow lowers risk by de-levering to industry norms, the equity value may be rewarded. But when? It may be over a year before that happens. A lot can happen between now and then. Kimmeridge does not want to wait. It wants policy changes now. Management has pointed to strong cash flow and results above expectations so far in 2024 as proof that its strategy is working. Management is skeptical of Kimmeridge’s intentions. They believe Kimmeridge’s end game is to force a dilutive transaction with Kimmeridge Texas Gas. Both sides want a higher stock price. Which one presents the better path to get there remains to be seen and will come down to what the shareholders decide.Originally appeared on Forbes.com.
The Inside “SCOOP”
The Inside “SCOOP”
The SCOOP/STACK is a significant oil and gas play found in the Anadarko Basin of Oklahoma. The “SCOOP” part of the name refers to “South Central Oklahoma Oil Province,” and “STACK” is an abbreviated geographic description: the Sooner Trend oil field, the Anadarko basin, and the Canadian and Kingfisher counties.
The Beginning of a Bakken Behemoth
The Beginning of a Bakken Behemoth

Chord Energy and Enerplus

In a significant development for the energy industry, on February 21, 2024, Chord Energy Corporation and Enerplus Corporation announced a definitive agreement to merge. This strategic combination aims to create a powerhouse in the Williston Basin, leveraging their complementary strengths and operational expertise.
Just Released | 1Q24 Exploration & Production Newsletter
Just Released | 1Q24 Exploration & Production Newsletter

Region Focus: Eagle Ford

Mercer Capital’s Value Focus: Exploration & Production newsletter provides an overview of the industry through supply and demand analysis, commodity pricing, and public market performance. In addition, each issue of this quarterly newsletter focuses on a region, including Eagle Ford, Permian, Appalachia, and Haynesville, examining general economic and industry trends. In this quarter's issue, we focus on the Eagle Ford.
Oil & Gas Roadblocks: Prices, Production, and People Holding Sway
Oil & Gas Roadblocks: Prices, Production, and People Holding Sway
There are always going to be barriers to success in an industry. Barriers to entry, barriers to growth, barriers to profitability, and barriers to progress can lurk to name a few. The upstream industry has its share. For gas, its own oversupply and low prices are an issue. For oil, capital constraints are reining in investment. Both commodities also thirst for quality labor to fuel growth and longer-term underlying optimism, but that workforce does not exist right now and may take a while to develop.
5 Reasons Upstream Sellers Need  a Quality of Earnings Report
5 Reasons Upstream Sellers Need a Quality of Earnings Report
Apart from a number of headline deals, M&A activity was sidelined for much of 2022 and 2023. But needing to replenish a depleting asset base with quality mineral acreage, stabilizing interest rates, and pent-up M&A demand are expected to compel buyers and sellers to renew their efforts in 2024 and beyond.As deal activity recovers, sellers need to be prepared to present their value proposition in a compelling manner.  For many sellers, an independent Quality of Earnings (“QofE”) analysis and report are vital to advancing and defending their asset’s value in the marketplace.  And it can be critical to the ensuing due diligence processes buyers apply to targets.The scope of a QofE engagement can be tailored to the needs of the seller.  Functionally, a QofE provider examines and assesses the relevant historical and prospective performance of a business.  The process can encompass both the financial and operational attributes of the business model.In this article, we review five reasons sellers benefit from a QofE report when responding to an acquisition offer or preparing to take their businesses or assets to market.1. Maximize value by revealing adjusted and future sustainable profitability.Sellers should leave no stone unturned when it comes to identifying the maximum achievable cash flow and profitability of their assets.  Every dollar affirmed brings value to sellers at the market multiple.  Few investments yield as handsomely and as quickly as a thorough QofE report.  A lack of preparation or confused responses to a buyer’s due diligence will assuredly compromise the outcome of a transaction.  The QofE process includes examining the relevant historical period (say two or three years) to adjust for discretionary and non-recurring income and expense events, as well as depicting the future (pro forma) financial potential from the perspective of likely buyers.  The QofE process addresses the questions of why, when, and how future cash flow can benefit sellers and buyers.  Sellers need this vital information for clear decision-making, fostering transparency, and instilling trust and credibility with their prospective buyers.2. Promote command and control of transaction negotiations and deal terms.Sellers who understand their objective historical performance and future prospects are better prepared to communicate and achieve their expectations during the transaction process.  A robust QofE analysis can filter out bottom-dwelling opportunists while establishing the readiness of the seller to engage in efficient, meaningful negotiations on pricing and terms with qualified buyers.  After core pricing is determined, other features of the transaction, such as working capital, assumption of asset retirement obligations, thresholds for contingent consideration, and other important deal parameters, are established.  These seemingly lower-priority details can have a meaningful effect on closing cash and escrow requirements.  The QofE process assists sellers and their advisors in building the high road and keeping the deal within its guardrails.3. Cover the bases for board members, owners, and the advisory team and optimize their ability to contribute to the best outcome.The financial and fiduciary risk of being underinformed in the transaction process is difficult to overcome and can have real consequences.  Businesses can be lovingly nurtured with operating excellence, sometimes over generations of ownership, only to suffer from a lack of preparation, underperformance from stakeholders who lack transactional expertise, and underrepresentation when it most matters.  The QofE process is like training camp for athletes — it measures in realistic terms what the numbers and the key metrics are and helps sellers amplify strengths and mitigate weaknesses.  Without proper preparation, sellers can falter when countering an offer, placing the optimal outcome at risk.  In short, a QofE report helps position the seller’s board members, managers, and external advisors to achieve the best outcome for shareholders.4. Financial statements and tax returns are insufficient for sophisticated buyers.Time and timing matter.  A QofE report improves the efficiency of the transaction process for buyers and sellers.  It provides a transparent platform for defining and addressing significant reporting and compliance issues.  There is no better way to build a data set for all advisors and prospective buyers than the process of a properly administered QofE engagement.  This can be particularly important for sellers whose level of financial reporting has been lacking, changing, outmoded due to growth, or contains intricacies that are easily misunderstood.For sellers content to work their own deals with their neighbors and friendly rivals, a QofE engagement can provide some of the disciplines and organization typically delivered by a side-side representative.  While we hesitate to promote a DIY process in this increasingly complicated world, a QofE process can touch on many of the points that are required to negotiate a deal.  Sellers who are busy running their businesses rarely have the turnkey skills to conduct an optimum exit process.  A QofE engagement can be a powerful supporting tool.5. In one form or another, buyers are going to conduct a QofE process – what about sellers?Buyers are remarkably efficient at finding cracks in the financial facades of targets.  Most QofE work is performed as part of the buy-side due diligence process and is often used by buyers to adjust their offering price (post-LOI) and design their terms.  It is also used to facilitate their financing and satisfy the scrutiny of underlying financial and strategic investors.  In the increasing arms race of the transaction environment, sellers need to equip themselves with a counteroffensive tool to stake their claim and defend their ground.  If a buyer’s LOI is “non-binding” and subject to change upon the completion of due diligence, sellers need to equip themselves with information to advance and hold their position.ConclusionThe stakes are high in the transaction arena.  Whether embarking on a sale process or responding to an unsolicited inquiry, sellers have precious few opportunities to set the tone.  A QofE process equips sellers with the confidence of understanding their own position while engaging the buy-side with awareness and transparency that promotes a more efficient negotiating process and the best opportunity for a favorable outcome.  If you are considering a sale, give one of our senior professionals a call to discuss how our QofE team can help maximize your results.
EP Second Quarter 2024 Permian
E&P Second Quarter 2024

Permian

Permian // Permian production growth over the past year was a positive outlier among the four basins covered in our analysis, with Eagle Ford, Appalachia, and Haynesville all posting production declines (albeit Appalachia’s decline being insignificant at 0.3%).
The Benefits of a Quality of Earnings Analysis for E&P Companies
The Benefits of a Quality of Earnings Analysis for E&P Companies
For buyers and sellers, the stakes in a transaction are high. A QofE analysis is an essential step in getting the transaction right.
Eagle Ford Production Edges Down on Sharply Reduced Drilling
Eagle Ford Production Edges Down on Sharply Reduced Drilling
The economics of oil & gas production vary by region. Mercer Capital focuses on trends in the Eagle Ford, Permian, Haynesville, and Marcellus and Utica plays. This quarter we take a closer look at Eagle Ford.
Eagle Ford M&A Update
Eagle Ford M&A Update

Transaction Activity Plummets Over the Past 4 Quarters

Over the past twelve months, deal activity in the Eagle Ford has fallen off a cliff, with only two deals closing compared to 13 transactions closed in the prior twelve-month period. Significant volumes of wet gas, NGLs, and rich condensate combined with the proximity to the Port of Corpus Christi fueled deal momentum in the twelve months ended February 28, 2023. So why did this momentum come to a screeching halt during the remainder of 2023 and into the first two months of 2024?According to a report from Deloitte, M&A activity declined as E&P companies committed themselves to capital discipline. Free cash flows were diverted away from investing, acquiring for growth, and increasing market share toward paying dividends and share buybacks. The old drivers of M&A activity seem to have been replaced by new drivers.Recent Transactions in the Eagle FordDuring the twelve months ended February 29, 2024, Silverbow Resources purchased 42,000 acres from Chesapeake Energy for $700 million, while Crescent Energy purchased 75,000 acres from Mesquite Energy for $600 million. The total deal value of the two deals, $1.3 billion, equals the median deal value of the 13 deals for the twelve months ended February 28, 2023. A table detailing these two transactions is shown below.Click here to expand the image aboveChesapeake’s sale to Silverbow Resources is an extension of Chesapeake’s sell-off during the twelve months ended February 28, 2023 (see table below), during which Chesapeake sold a combined 549,000 acres over two deals. On the flip side, Silverbow Resources has continued its buying binge by purchasing assets from Chesapeake, adding to the four purchases it made during the twelve months ended February 28, 2023 (see table below). Silverbow Resources spent $547 million on these four purchases, adding 76,000 acres to its portfolio at $7,197/acre.Click here to expand the image aboveRock, Returns, and Runway: Why Chesapeake is a SellerChesapeake announced the sale of its remaining Eagle Ford shale assets to Silverbow Resources on August 14, 2023. The sale of these assets affirmed Chesapeake’s commitment to the Marcellus and Haynesville shales, noting that the Eagle Ford was no longer core to its strategy. Further, Chesapeake’s activist investor Kimmeridge Energy Management, had urged a shift toward solely natural gas production. The Marcellus and Haynesville shales are both natural gas-rich formations. We note that the shift out of the Eagle Ford shale preceded Chesapeake’s merger with Southwestern Energy, which was announced on January 11, 2024. As Chesapeake’s CEO Nick Dell'Osso noted, the divestiture of the remaining Eagle Ford assets allows Chesapeake “to focus our capital and team on the premium rock, returns, and runway” of its assets within the Marcellus and Haynesville shales.Scale, Capital Efficiency, and Commodity Exposure: Why Silverbow Is BuyingWhile Chesapeake has completely exited the Eagle Ford, Silverbow Resources is the other side of the coin. The acquisition of the Chesapeake assets has propelled the company into the largest public pure-play Eagle Ford operator.Silverbow Resources CEO Sean Woolverton noted “We are excited to close the Chesapeake transaction, which materially increases our scale in South Texas…Our differentiated growth and acquisition strategy has positioned us with … a portfolio of locations across a single, geographically advantaged basin. The acquired Chesapeake assets further enhance our optionality to continue allocating capital to our highest return projects and will immediately compete for capital.”ConclusionM&A activity in the Eagle Ford has plummeted over the last twelve months, with only two deals announced, one of which portrays two very different attitudes towards the Eagle Ford. However, according to Enverus Intelligence Research, the Eagle Ford shale is one of a few areas that can expect an uptick in M&A activity in 2024 as the list of attractive targets in the Permian Basin has dwindled due to heavy M&A activity in that play in 2023. Enverus also notes that “The core of the Eagle Ford is the gift that keeps giving for operators with the best acreage.”  Despite denser development, recoveries remain high in these core areas of the Eagle Ford.Mercer Capital has assisted many clients with various valuation needs in the upstream oil and gas industry in North America and around the world. In addition to corporate valuation services, Mercer Capital provides investment banking and transaction advisory services to a broad range of public and private companies and financial institutions. We have relevant experience working with companies in the oil and gas space. We can leverage our historical valuation and investment banking experience to help you navigate a critical transaction, providing timely, accurate, and reliable results. Contact a Mercer Capital professional to discuss your needs in confidence.
Mineral Aggregator Valuation Multiples Study Released-Data as of 03-04-2024
Mineral Aggregator Valuation Multiples Study Released

With Market Data as of March 4, 2024

Mercer Capital has thoughtfully analyzed the corporate and capital structures of the publicly traded mineral aggregators to derive meaningful indications of enterprise value. We have also calculated valuation multiples based on a variety of metrics, including distributions and reserves, as well as earnings and production on both a historical and forward-looking basis.
Themes from Q4 2023 Energy Earnings Calls
Themes from Q4 2023 Energy Earnings Calls

Upstream (E&P) and Oilfield Service (“OFS”) Companies

This week, we delve into the Q4 2023 earnings calls of upstream and OFS companies, underscoring the consistent emergence of these themes across the entire sector.
Texas Statewide Rule 8 Overhaul
Texas Statewide Rule 8 Overhaul

What's in Store for Texas Oilfield Waste Disposal Operators?

In October 2023, the Railroad Commission of Texas (the "RRC," or the "Commission") announced that for the first time in nearly 40 years, 16 Texas Administrative Code (TAC) §3.8 (relating to Water Protection), also known as Statewide Rule 8 ("Rule 8"), would undergo a significant overhaul. We discuss that in this post.
Non-Operating Working Interests in Oil & Gas-Part II
Non-Operating Working Interests in Oil & Gas: Part II

Markets and Valuation Characteristics of Non-Op Working Interests

As we continue our discussion on non-op working interests from Part I of this series, we turn to how the markets and valuation parameters are structured.
Just Released | 4Q23 Exploration & Production Newsletter
Just Released | 4Q23 Exploration & Production Newsletter

Regional Focus: Haynesville Shale

Mercer Capital’s Value Focus: Exploration & Production newsletter provides an overview of the industry through supply and demand analysis, commodity pricing, and public market performance. In addition, each issue of this quarterly newsletter focuses on a region, including Eagle Ford, Permian, Appalachia, and Haynesville, examining general economic and industry trends. In this quarter's issue, we focus on the Haynesville Shale.
Non-Operating Working Interests in Oil & Gas-Part I
Non-Operating Working Interests in Oil & Gas: Part I

Characteristics of Non-Op Working Interests, the Risks, and the Benefits

The economics between an operating interest and a non-op interest can sometimes differ significantly in certain circumstances.
2024 Oil and Gas Outlook
2024 Oil and Gas Outlook

A Year Of Divergence

When it comes to the oil and natural gas upstream markets, it appears each commodity and their producers are heading to different places in 2024. We can see it through market sentiment, prices, production, and corporate actions such as mergers.
The Chesapeake and Southwestern Merger
The Chesapeake and Southwestern Merger

Reshaping U.S. Natural Gas

On January 11th, 2024, Chesapeake Energy Corporation and Southwestern Energy Company announced that they would be merging, with the resulting (currently unnamed) company becoming the largest natural gas producer in the country.
Haynesville DUCs Buoy Production Despite Rig Count Decline
Haynesville DUCs Buoy Production Despite Rig Count Decline
The economics of oil & gas production vary by region. This quarter, we take a closer look at the Haynesville shale.
Initiating Coverage of the Haynesville Shale
Initiating Coverage of the Haynesville Shale
We’re starting 2024 with coverage of the Haynesville shale. The Haynesville shale is one of the top natural gas plays in the U.S., particularly when factoring in its geographic location, pipeline and infrastructure capacity, and deliverability of gas to the Gulf Coast industrial complex and liquified natural gas (LNG) export facilities.
EP First Quarter 2024 Eagle Ford
E&P First Quarter 2024

Eagle Ford

Eagle Ford // Despite significant rig-count declines, Eagle Ford production declined only modestly over the twelve months ended March 2024, aided by a significant number of DUCs going into production.
Top 10 Energy Valuation Insights Blog Posts of 2023
Top 10 Blog Posts of 2023
Year-end 2023 is quickly approaching so that means it's time to take a look back at the year. Here are the top ten posts for the year measured by readership. Click on any of the post titles to revisit the post.
Remembering Charlie Munger: His Investment Wisdom and Legacy
Remembering Charlie Munger

His Investment Wisdom and Legacy

Mr. Buffet took this one step further – “I will confidently wager that no computer will ever replicate Charlie.” Unfortunately, he was probably right.
Mineral Aggregator Valuation Multiples Study Released-Data as of 11-17-2023
Mineral Aggregator Valuation Multiples Study Released

With Market Data as of November 17, 2023

Mercer Capital has thoughtfully analyzed the corporate and capital structures of the publicly traded mineral aggregators to derive meaningful indications of enterprise value. We have also calculated valuation multiples based on a variety of metrics, including distributions and reserves, as well as earnings and production on both a historical and forward-looking basis.
Themes from Q3 Energy Earnings Calls-Part 2: Oilfield Service Companies
Themes from Q3 2023 Energy Earnings Calls

Part 2: Oilfield Service (“OFS”) Companies

In our most recent earnings call blog post, Themes from Q3 2023 Earnings Calls, Part 1 Upstream, prevalent themes from E&P companies included discussions about consolidation in the industry, a focus on efficiency of operations, and strong production volumes throughout 2023. This week, we focus on the key takeaways from OFS operators’ Q3 2023 earnings call.
Themes from Q3 2023 Energy Earnings Calls-Part 1: Upstream
Themes from Q3 2023 Energy Earnings Calls

Part 1: Upstream

In Themes from Q2 2023 Energy Earnings Calls, we noted E&P operators’ search for ways to maintain production levels, expectations for low crude oil inventories, and decreased activity in the Haynesville shale region. This week, we focus on the key takeaways from Upstream Q3 2023 earnings calls.
D CEO's 2023 Energy Awards
D CEO's 2023 Energy Awards
This past week, Mercer Capital was a part of D CEO’s 2023 Energy Awards—a fantastic event that celebrates the energy industry, transactions, and individuals that impact the Dallas Fort Worth Metroplex. Major players such as Energy Transfer Partners, Exxon, and Denbury were honored or noted. However, broader reaches of the industry were also recognized, such as private equity and royalty companies.
Energy Newsletter Release: 3Q 2023
Just Released | 3Q23 Exploration & Production Newsletter

Third Quarter 2023 | Regional Focus: Appalachian Basin

Mercer Capital’s Value Focus: Exploration & Production newsletter provides an overview of the industry through supply and demand analysis, commodity pricing, and public market performance. In addition, each issue of this quarterly newsletter focuses on a region, including Eagle Ford, Permian, Bakken, and Appalachia, examining general economic and industry trends. Appalachian production fared well over the last year, particularly considering the sharp decline in the Henry Hub price. Despite the Henry Hub decline, the Appalachian rig count decline was less than that of two of the three oil-rich basins presented, largely due to Appalachia’s higher production declines, which require a higher rig count to maintain production levels.Exploration & ProductionThird Quarter 2023Region Focus: Appalachian BasinDownload Newsletter
Energy Values Take Hits….And Keep Moving Forward
Energy Values Take Hits….And Keep Moving Forward
The famous philosopher Rocky Balboa once said: “It ain’t about how hard you can hit. It’s about how hard you can get hit and keep moving forward.”Amid mixed signals, Middle East conflict, rising inflation, rising interest rates, political and regulatory headwinds, and other factors the oil and gas industry continues to perform and cycle upwards. For the year to date, the S&P Oil and Gas Exploration & Production Select Industry Index has gone up over 7%. For the past three years, the index has had an annualized return of over 48%. TheS&P 500 has only a 7% annualized return itself over the past three years. It’s a marked change from the decade-long dry spell the industry had, particularly in 2014 and 2015. In a time where numerous things could dampen demand, prices, profits, and valuations the industry continues an upward trend. In addition, some defensive posturing that the industry has taken in recent years may pay off in ways that were not immediately obvious. Capital discipline, low debt, and improved technology have helped set the stage for the current conditions which should allow oil and gas producers to keep moving forward.Capital Discipline & DeleveragingOil prices have continued to be relatively strong for nearly two years now, rarely dropping below $70, sometimes topping $100, and averaging closer to $80. This is a far cry from the years and years of $50 oil (or less). More on that later. However, amid that strength of sustained higher commodity prices and the corresponding profitable drilling locations, rig counts have dropped year over year according to Baker HughesBHI0.0%. My Forbes colleague David Blackmon wrote about this a few weeks ago. The urge to drill with every available resource remains constrained, which is not how operators behaved in past cycles. The focus on returns and value creation appears to have overruled growth, and in addition, some of this may be coming from the continually rising costs to drill and complete wells according to the latest Dallas Fed Energy Survey, alongside a tight labor market. Additionally, technology continues to incrementally improve and increase efficiency of recovery at the well level, which helps productivity per rig.Another form of capital discipline has been the continual deleveraging trend. I have written on this before, but not in this interest rate environment. As the cost of debt capital goes up, the industry’s deleveraging will have another silver lining: directing more operating profits to shareholders instead of bankers. Operating decisions at many companies will be less immune to upward interest rate pressures or refinancing risks. On top of that – bankers often require companies to hedge large portions of their production to ensure downside protection for their debt. However, the trade-off companies make is that they also often give away some (or a lot) of upside commodity price potential. This is less of a problem when debt loads are low. Lastly, on this front, bankers are not the only capital source that has been reticent to supply new money to the industry. Equity investors have desired to do more harvesting than planting in the oil and gas sector, thus there has been less capital available to aggressively pursue drilling plans.Higher Forecasts For Commodity PricesThat’s not to say that drilling plans do not look good right now. They do. Not only are oil prices above $80 now, but the tail of the futures curve suggests prices above $60 as far out as 2029. Fed Energy Survey participants agree — prices should be buoyant into the intermediate future. This is arguably more important to management teams as they marshal resources for long-term projects. Dan Pickering of Pickering Energy Partners thinks oil will be around $80 in 2027 and that the upcycle will be continuing. Part of this is fueled by prior and continuing investments in oil and gas pipelines in the past several years and LNG infrastructure. The cheaper access to markets has helped to manage constrained or stranded supply (particularly gas). At the same time, the conceptual rationale for pricing is particularly circular. Constrained capital discipline will slow supply growth to match demand and vice versa, but there are other factors as well – more global ones on the supply-demand seesaw.Global ProductionThe global market is a little more unstable, but events more recent in Israel and in the Russian/Ukrainian war have had more muted effects on the global supply of oil than otherwise might be thought. While European sanctions on Russian gas appear to have been effective, Russian oil has found its way to other markets. This has helped to limit price shocks. (Side question: what might happen if Venezuela remounted its petroleum horse again?)However, as the shale revolution matures and Tier 1 drilling locations shrink, it will get harder to maintain and grow supply compared to demand. Now this could balance out in future years as demographics age and world population potentially slows and shifts. Nonetheless, one factor that could change the equation back to a more aggressive drilling posture is that oil will probably peak again in the next 20 years. As such, exploration will come back into the conversation as fields mature and declines increase. Even the Biden Administration relented on some offshore drilling leases, albeit minimally.What this means for energy valuations is that the upswing over the past few years does not appear to be peaking anytime soon. While there will be winners (most likely larger operators) and losers (most likely smaller operators), the sector’s overall value continues to move forward.Originally appeared on Forbes.com.
Now Available: Mercer Capital's 2023 Energy Purchase Price Allocation Study
Now Available: Mercer Capital's 2023 Energy Purchase Price Allocation Study
The 2023 Energy Purchase Price Allocation Study provides a detailed analysis and overview of valuation and accounting trends in these sub-sectors of the energy space. This study also enables key users and preparers of financial statements to better understand the asset mix, valuation methods, and useful life trends in the energy space as they pertain to business combinations under ASC 805 and GAAP fair value standards under ASC 820. We utilized transactions that closed and reported their purchase allocation data in calendar year 2022.
Leading America Toward Energy Independence
Leading America Toward Energy Independence

Hart Energy LIVE’s America’s Natural Gas Conference 2023

Last week, I attended Hart Energy LIVE’s second annual America’s Natural Gas conference in Houston. The speaker roster included CEOs of companies operating in the Utica (Encino Energy) and Haynesville shales (Rockcliff Energy) and Green River basin (PureWest Energy), investment bankers, private equity investors, and consultants, among others. CO2 emissions reduction, demand for LNG exports despite inadequate transportation and storage infrastructure, and the energy transition were three of the more prevalent themes discussed. Below are a few highlights I would like to share with you.
EP Fourth Quarter 2023 Haynesville
E&P Fourth Quarter 2023

Haynesville

Haynesville // Haynesville production held-up reasonably well during the 2023 review period, particularly considering the sharp fall-off in the basin’s rig count.
Appalachian Production Marches on Despite Henry Hub Plunge
Appalachian Production Marches on Despite Henry Hub Plunge
The economics of oil & gas production vary by region. Mercer Capital focuses on trends in the Eagle Ford, Permian, Bakken, and Marcellus and Utica plays. The cost of producing oil and gas depends on the geological makeup of the reserve, depth of reserve, and cost to transport the raw crude to market. We can observe different costs in different regions depending on these factors. This quarter, we take a closer look at the Marcellus and Utica shales.
Inside the Board Rooms of a $5.4 Billion Oil and Gas Merger
Inside the Board Rooms of a $5.4 Billion Oil and Gas Merger
In a departure from our typical analysis and discussion of recent deals, this week’s Energy Valuation Insights blog takes a break from deal multiples and observes the negotiations of the $5.4 billion merger between Sitio Royalties Corp. (“Sitio”), a player in the Marcellus Shale, and Brigham Minerals, Inc. (“Brigham”).
Themes from Q2 2023 Energy Earnings Calls-Part 2: Oilfield Service Companies
Themes from Q2 2023 Earnings Calls

Part 2: Oilfield Service (“OFS”) Companies

This week, we focus on the key takeaways from OFS operators’ Q2 2023 earnings call.
Mineral Aggregator Valuation Multiples Study Released-Data as of 08-21-2023
Mineral Aggregator Valuation Multiples Study Released

With Market Data as of August 21, 2023

Mercer Capital has its finger on the pulse of the minerals market.  An important trend has been the rise of mineral aggregators, which have largely supplanted the trusts as the primary method of publicly traded minerals ownership.Due to a variety of corporate structures (including master limited partnerships and Up-Cs) and complex capital structures (including preferred equity and non-traded common units), mineral aggregator enterprise values pulled from databases are often missing meaningful components of value, leading to skewed valuation multiples.Mercer Capital has thoughtfully analyzed the corporate and capital structures of the publicly traded mineral aggregators to derive meaningful indications of enterprise value.  We have also calculated valuation multiples based on a variety of metrics, including distributions and reserves, as well as earnings and production on both a historical and forward-looking basis.Mineral Aggregator Valuation Multiples StudyMarket Data as of August 21, 2023Download Study
Themes from Q2 2023 Energy Earnings Calls-Part 1: Upstream
Themes from Q2 2023 Earnings Calls

Part 1: Upstream

In Part 1: Upstream themes from Q1 2023 Earnings Calls, notable themes included a divide on whether dividends or buybacks are the best means to return capital to shareholders and management’s reactions to a decline in strip prices, as well as highlighting inventory in the favorable Permian and Eagle Ford plays. This week, we focus on the key takeaways from Upstream Q2 2023 earnings calls.
Industry Expert vs. Valuation Expert: Which Should You Choose?
Industry Expert vs. Valuation Expert: Which Should You Choose?
In the complex world of the oil & gas industry, a nuanced understanding of industry intricacies and valuation principles is vital. While it's common to find specialists in either industry knowledge or valuation methods, a complete solution requires a synergy of both these domains. In this article, we explore the unique benefits of both industry and valuation experts before delving into why a firm with expertise in both these areas is the best choice for oil & gas industry companies.The Case for an Industry ExpertChoosing an industry expert to value your oil & gas company has several distinct benefits that stem from a deep understanding of the sector's unique dynamics, trends, and complexities. Here's a breakdown of some of the key advantages.Long-Time Analysts of the Oil & Gas IndustryIndustry experts are veterans in analyzing the oil & gas sector, employing years of observation and insight to interpret trends and make accurate predictions. They have an intimate understanding of the factors affecting the oil & gas sector, including regulatory changes, technological advancements, market demand, geopolitical influences, and environmental considerations. Industry experts are often well-versed in current market trends, including supply and demand dynamics, price fluctuations, and competitor strategies.Understanding of Industry Concepts and TerminologyTheir grasp of specific oil & gas terminology and concepts ensures that the valuation process is more tailored and precise. They know what factors to consider and how these factors interplay within the context of the industry.Writing/Speaking about Industry TrendsWith a thorough knowledge of the industry's evolution, these experts can provide invaluable insights and analysis on emerging trends.Transaction ExperienceIndustry experts have hands-on experience in dealing with transactions within the oil & gas sector, including with upstream E&Ps, JVs, Partnerships, and LLCs.Advisory ServicesIndustry experts are often sought to provide advisory services and are attuned to the market as typical acquirers and divestors of assets, entities, and interests in the oil & gas industry.Enhanced CredibilityFinally, an industry expert's valuation may carry more weight with stakeholders and regulatory authorities due to their specialized knowledge and experience in the oil & gas field. It reflects a deep understanding of the unique attributes of the industry.The Case for a Valuation ExpertSelecting a valuation expert to assess your oil & gas company brings a distinct set of advantages rooted in their specialized training, adherence to recognized standards, and a focused approach to valuation. Here are the key benefits.Training, Professional Designations, and Valuation StandardsWith specialized training and professional certifications, valuation experts bring credibility and expertise to the valuation process, adding confidence for stakeholders, investors, and regulators. In addition, valuation experts are trained in internationally recognized standards and methodologies. This ensures that the valuation is consistent, transparent, and in compliance with legal and regulatory requirements.Objective PerspectiveValuation experts approach the market as hypothetical buyers and sellers, providing an unbiased and objective perspective. This helps in creating a fair and neutral valuation that can withstand scrutiny.Expertise in Valuing Minority InterestsValuation experts have specialized skills in valuing minority interests, ensuring a fair and comprehensive understanding of all ownership stakes within the company.Advising on Buy-Sell AgreementsValuation experts can provide critical insights into contractual agreements that dictate the buying and selling of ownership interests.Defense in Litigated MattersValuation experts have experience in defending their work in litigated matters. If the valuation were ever challenged in court, their expertise could be instrumental in upholding the assessment.Handle Recurring Tax and/or Valuation WorkValuation experts can handle regular tax and valuation work, providing consistency and continuity, and ensuring ongoing compliance with tax laws and regulations.Cross-Industry KnowledgeValuation experts often have experience across various industries, allowing them to bring a broader perspective to the valuation. They can apply lessons and insights from other sectors to the unique context of the oil & gas industry.Why You Need BothThe best solution for an oil & gas company is to employ a firm that combines the experience and insights of both an industry and valuation expert. While industry experts bring the contextual understanding and transaction experience, valuation experts provide the specialized valuation skills that ensure accuracy and compliance with legal standards.The Mercer Capital ExampleMercer Capital, organized according to industry specialization, stands as a prime example of a firm embracing both these crucial elements:Industry Specialization: Our energy team has an extensive specialty oil & gas background, experience, and training. We've worked with operating entities, assets, and joint ventures throughout all phases of commodity price cycles.Recognition: Writing and speaking regularly on industry topics through channels like Forbes.com & Hart Energy, Mercer Capital has gained a reputation as a thought leader.Expert Valuations: Our firm has provided expert valuation opinions to over 15,000 clients across the globe, upheld by court jurisdictions and regulatory bodies like the IRS & PCAOB.Leadership: Actively leading in the valuation profession, Mercer Capital offers training to other professionals within the valuation, accounting, and legal communities.Global Reach: Our international experience spans Europe, the Middle East, South America, and nearly every major domestic basin and play. Through a unique combination of industry expertise and valuation specialization, Mercer Capital offers a holistic approach that caters to the multifaceted needs of the oil & gas sector, positioning itself as a preferred partner in this dynamic industry. Contact one of our professionals to discuss your valuation issue in confidence.
Energy Newsletter Release: 2Q 2023
Value Focus | Exploration & Production

Second Quarter 2023 | Region Focus: Permian

Mercer Capital’s Value Focus: Exploration & Production newsletter provides an overview of the industry through supply and demand analysis, commodity pricing, and public market performance. In addition, each issue of this quarterly newsletter focuses on a region, including Eagle Ford, Permian, Bakken, and Appalachia, examining general economic and industry trends. In this quarter's newsletter we focus on the Permian. Production growth over the past year continued to run well in the Permian, ahead of growth in the Eagle Ford, Appalachian, and Bakken, as the Permian basin remains one of the most economic regions for U.S. energy production. With the decline in commodity prices over the past year, rig counts fell, with the most significant decline occurring in May. With E&P firms expecting continued cost increases through the remainder of 2023, the Permian’s existing cost advantage will contribute to its continued dominance over the major U.S. basins.Exploration & ProductionSecond Quarter 2023Region Focus: PermianDownload Newsletter
Exxon’s Acquisition of Denbury
Exxon’s Acquisition of Denbury

A Tale of Two Businesses, and Neither One Is Worth $4.9 Billion

ExxonMobil made waves in the energy M&A markets by announcing its acquisition of Denbury, Inc. Exxon paid somewhere between Denbury’s stock price and a slight premium depending on the timing and stock price fluctuations. In total, the headline value was around $4.9 billion, according to Exxon’s news release.However, while Denbury is an energy company on the whole, it is made up of two main segments that have very different economics. First, its carbon capture utilization and storage segment (CCUS). Second, its upstream enhanced oil recovery segment. These two businesses, in many ways, represent Denbury’s journey over the last several years that have one foot in the carbon future and one foot in the oily past. Neither of their business segments appears to be worth the $4.9 billion price tag. So what did Exxon buy exactly, and how might one value it?A quick look at some of the overall implied metrics related to the deal reveals some oddities compared to pure-play oil companies. As to CCUS transactions, there really have not been many to compare to, and certainly not at the scale that Denbury has achieved thus far. The table below was compiled based on figures from the announcement and Capital IQ data. Just looking at the implied values relating to upstream multiples, the flowing barrel metric jumps out as high compared to most operators, especially with an EBITDA margin below 55%. This implies a higher multiple than much larger global companies such as BP, ConocoPhillips, and Occidental Petroleum—which does not make intuitive sense. On the other side of the equation, the value per mile of pipeline appears relatively high at first glance. This is considering management’s recent earnings call comments about construction costs being between $2 to $4 million per mile, coupled with the fact that the pipelines are not fully utilized yet. There clearly is a mix of segment-made contributions that drive different elements of the overall transaction price.Denbury’s CCUS business represents the future of Denbury and embodies the key rationale for Exxon’s interest. Denbury has touted this segment, and most of its marketing, to investors centers on this aspect of its business. Its enthusiasm is apparent as its annual report spent almost all its focus on this area of the business. CCUS does represent a synergistic operational advantage for the company because Denbury has been one of the few upstream companies focusing on older, depleted fields that have lost what the industry calls “natural drive” and thus require incremental efforts to bring oil to the surface. Denbury’s solution to this challenge for a long time has been to inject its CO2 into the fields to create pressure and stimulate oil production.However, the business model for a standalone CCUS business model is still relatively nascent, requiring hundreds of millions of dollars of investment and years before it could potentially reach cash flow sustainability separate from oil production activities. There’s already much in place now with 1,300 miles of pipeline and ten onshore sequestration sites, which was attractive to Exxon. However, things like the growth of offtake agreements, Section 45Q tax incentives (which I wrote about last year), and carbon storage contracts are not expected to generate net positive income for Denbury until several years in the future. Nonetheless, this developmental potential and strategic location in the Gulf region have significantly contributed to Denbury’s stock price and Exxon’s interest. How much the CCUS is contributing to Denbury’s value is uncertain. But in an interesting article published a few days ago, Hart Energy interviewed Andrew Dittmar, a Director at Enverus, who estimated that (effectively) about 62% of Denbury’s value was based on their CCUS business. In the meantime, Denbury’s upstream enhanced oil recovery (EOR) business has been pulling the income statement’s performance along. Nearly all profits for Denbury are generated through this business line. However, compared to other public upstream companies, Denbury’s profitability is comparably lower, production is smaller, and production costs are higher. This is not a recipe for high comparative valuations, certainly not over $100 thousand per flowing barrel, which only the likes of Exxon and Chevron imply. (While we’re on the topic of segments, it is not a clean comparison either since Exxon and Chevron are two integrated companies with many segments that contribute to their values too). Denbury is primarily a regional oil producer with less than 50 thousand barrels per day of production and EBITDA margins lower than many public oil companies. To its credit, Denbury does have lower decline rates than other companies due to the maturity of the fields they produce from. However, the flip side is that it costs $35-$39 per barrel to produce. Those are expensive lease operating costs when many companies operate somewhere in the teens per barrel. All that said, Enverus’s estimate in their Hart Energy interview was that the EOR business contributed about 38% of Denbury’s value. So, if Enverus’s analysis is to be applied here, that would put an adjusted value on Denbury’s production at around $39,000 per barrel and an adjusted value per pipeline mile of around $2.3 million. Take a look at these “adjusted” figures:Under this scenario, Denbury’s upstream business would potentially be slotted in with public regional upstream producers with characteristics closer to: (i) under 200 thousand barrels per day of production and (ii) EBITDAX margins under 60%. Companies like Chord Energy (a Bakken-focused producer), Callon Petroleum (a smaller Permian operator), or maybe even Enerplus (another Bakken-focused producer) come to mind. Additionally, the value per mile of pipeline drifts down to the lower end of the construction estimate range, which also appears to be more realistic. Of course, this value depends on commodity expectations, regulatory stability, and execution of Denbury’s plan. Exxon appears to be optimistic about it. Whether or not Denbury’s shareholders will be remains to be seen.Originally appeared on Forbes.com.
Permian Production Growth Holds
Permian Production Growth Holds
The economics of Oil & Gas production vary by region. Mercer Capital focuses on trends in the Eagle Ford, Permian, Bakken, and Marcellus and Utica plays. The cost of producing oil and gas depends on the geological makeup of the reserve, the depth of the reserve, and the cost of transporting the raw crude to market. We can observe different costs in different regions depending on these factors. In this post, we take a closer look at the Permian.
EP Third Quarter 2023 Appalachian Basin
E&P Third Quarter 2023

Appalachian Basin

Appalachian Basin // Appalachian production fared well over the last year, particularly considering the sharp decline in the Henry Hub price.
M&A in the Permian-Acquisition Growth Flat Ahead of Expected Surge
M&A in the Permian

Acquisition Growth Flat Ahead of Expected Surge

Transaction activity in the Permian Basin remained flat over the past 12 months. The transaction count decreased slightly to 19 deals, a decline of two from the 21 deals that occurred over the prior 12-month period.
Mineral Aggregator Valuation Multiples Study Released-Data as of 06-19-2023
Mineral Aggregator Valuation Multiples Study Released

With Market Data as of June 19, 2023

Mercer Capital has thoughtfully analyzed the corporate and capital structures of the publicly traded mineral aggregators to derive meaningful indications of enterprise value. We have also calculated valuation multiples based on a variety of metrics, including distributions and reserves, as well as earnings and production on both a historical and forward-looking basis.
Lessons from the Oracle of Omaha
Lessons from the Oracle of Omaha
Can you guess who said the following? “[M]y long-time partner, and I have the job of managing the savings of a great number of individuals. We are grateful for their enduring trust, a relationship that often spans much of their adult lifetime. It is those dedicated savers that are forefront in my mind as I write this letter.”
Themes from Q1 2023 Energy Earnings Calls-Part 1: Upstream
Themes from Q1 2023 Earnings Calls

Part 1: Upstream

Despite the strength of the Eagle Ford, attention and resources were increasingly directed towards the Permian Basin, where operators aimed to capitalize on improving well economics, flexibility in project scheduling, and cost savings to drive enhanced free cash flow.
Is TXO's Strategy Paying Off?
Is TXO's Strategy Paying Off?

The TXO Energy Partners IPO

As our colleague Bryce Erickson said in a recent post, uncertainty rules the day in the upstream world despite strong demand for oil and elevated commodity prices. The war in Ukraine has contributed to this, but there is no way of knowing when or if it will wind down. Interest rates continue to rise, and recession fears loom. We believe the recent initial public offering (IPO) of TXO Energy Partners LP offers an interesting case study of how investors are responding to these mixed signals. In the early 2010s, upstream IPOs were at a peak. In 2011, there were no fewer than 20 IPO announcements, and the average targeted capital raises for IPOs climbed to well over $550 million by 2013. Things went sour from there. Since 2015, there have only been 22 IPOs announced. Due in part to the pandemic, average IPO targets for upstream firms have sunk to $15 million. Despite the vital role of oil and gas in the US economy, the market for public equity in upstream firms can certainly be described as underweight due to few publicly available investments in the sector and, thus, fewer opportunities for investment. Despite this, 2022 featured more IPO announcements than any year since 2016. Soaring commodity prices are bringing back interest in upstream investments. Upstream managers are confronting investor uncertainty by strengthening their balance sheets, using their historically high revenue to continue ramping production, and making generous distributions to shareholders. Click here to expand the image aboveValuation ConsiderationsTXO Energy Partners LP, formerly MorningStar Partners LP, is an E&P firm that IPO’d on the New York Stock Exchange on January 26, 2023, under the ticker TXO. The Partnership is focused on plays in the Permian and San Juan Basins within Texas, New Mexico, and Colorado. TXO offered five million common shares with a target price of approximately $20 per share (which would raise about $100 million). The IPO also allowed underwriters to purchase another 750,000 common shares at the IPO price net of discounts and commissions.One of the most important factors when considering TXO’s fundamentals is its recent acquisitions. In late 2021, they purchased 24,052 leasehold acres, a CO2 plant in the Permian Basin, and additional CO2 assets in Colorado (these assets are referred to as the “Vacuum Properties”). Within just a month, they also acquired an additional 21,112 gross leasehold acres in the Permian (the “Andrew Parker Acquisition”). Finally, they increased their interest in the Vacuum Properties in August 2022. Every transaction involved proven producing wells.Further, these wells have an average decline rate of just 7% (compared to a 9% projected decline rate across all TXO’s assets). By making such acquisitions, TXO noticed a short-term impact on its income statement but has ultimately set itself up for reliable, comparatively non-risky cash flows. The table below summarizes TXO’s developed and undeveloped acreage as of December 31, 2022.  One observation immediately jumps off the page: despite the recent Permian Basin acquisitions discussed above, TXO’s acreage is heavily weighted towards developed acreage in the San Juan Basin. Questions arise from this observation: Is TXO indicating a shift in priorities from the San Juan Basin to the Permian Basin? Will the company sell some of its San Juan Basin assets and use the proceeds to purchase more developed acreage in the Permian Basin after 2023? At the very least, the company’s focus is clearly on developed acreage rather than undeveloped acreage (see below for management’s immediate investment plans).In its S-1 statement, TXO reported PV-10 as of year-end 2021 of $986.6 million, compared to established firms like Diamondback Energy ($21.8 billion) and Black Stone Minerals ($972.1 million). A summary of TXO’s reserves per its most recent 10-K is shown below.Despite its comparatively small war chest of reserves (per the table above this paragraph showing the company’s reserve portfolio as of December 31, 2022), management has indicated that they anticipate most of their 2023 expenditures will go towards optimizing existing wells rather than continuing to make acquisitions to grow the wells in their portfolio.In the nine-month period ended September 30, 2022, revenues for TXO were $204.0 million, as opposed to $138.9 million for the same period in the prior year. TXO’s Vacuum and Andrews Parker acquisitions helped boost production volumes by almost 1,200 Mboe. Higher commodity prices also provided a significant boost, with realized prices for both oil and gas over 50% higher than in 2021. TXO reported net income of $14.6 million for the nine-month period ended September 30, 2022, compared to $25.2 million for the nine months ended September 30, 2021 ($0.58 per unit and $1.01 per unit for each respective year). The year-over-year decrease in net income was primarily attributable to higher production expenses in 2022 as well as transportation and tax expenses. On a year-over-year basis, production expenses climbed 105% as of September 30, 2022, while taxes and transportation expenses climbed 92%. Management stated that both items increased due to the two Vacuum and Andrews Parker property acquisitions. The higher production cost is a function of the acquired properties’ strong focus on oil production, which is typically more expensive on a Boe basis than natural gas production. The increase in taxes and transportation expenses was caused by rising commodity prices and changes in the Partnership’s production mix.In its S1, TXO portrays itself as holding a conservative balance sheet. Per Capital IQ, at the end of 4Q 2022, their largest liability was a credit facility with a balance of $113 million. Paying this debt down was the primary reason for their IPO. TXO has one of the smallest debt-to-capital ratios among its peers, as shown below. With less leverage, TXO is a comparatively less risky investment, all else being equal. This makes it particularly attractive to investors preparing for a potential downturn in the larger economy or upstream space.What is interesting about these financials is that despite tailwinds from commodity prices and growth from new acquisitions, YTD EPS shrank by 50%, yet TXO filed for an IPO anyway. Why? First, the EPS shrinkage is related to their acquisitions. Second, TXO’s stated strategy plays to the current desires of the market. As mentioned earlier, TXO is spending most of its money optimizing existing wells. Despite this, they still have plans to identify new opportunities. When describing how they are going to go about spending the portion of their capital dedicated to development, TXO stated that “over the next 24 months we anticipate that approximately half of our development activity will be focused on drilling new wells, virtually all of which we expect to be conventional, vertical wells.”Additionally, 97% of TXO’s current wells are conventional plays rather than more risky shale operations. By focusing on conventional plays, TXO can take advantage of slower production volume decline rates and earn steady cash flows to pay out dividends. The Partnership clearly had a distribution-focused plan in mind setting up their firm, as their Partnership Agreement specifies that every quarter it must pay out virtually all cash available for distributions. At one point, the S1 directly states that “our primary goal is to maximize investor returns through cash distributions and flat to low production and reserves growth over time.” At the time of this blog post, TXO has yet to make its first distribution since its IPO. How it sets its policy relative to other smaller upstream companies will be an interesting phenomenon to watch.The market does not currently seem to be valuing aggressive growth programs. Instead, investors are looking for companies like TXO with conservative balance sheets, large amounts of distributable cash, comparatively non-risky reserves, and steady, stable growth.All of this naturally begs the question of whether TXO’s strategy is paying off. Between TXO’s IPO date and May 4, the market price of the Standard and Poor’s Exploration & Production Select Industry Index has decreased by about 19%. On the other hand, TXO’s share price has only decreased by just under 2%.With such a high degree of uncertainty in the market, investors are bracing themselves for Murphy’s Law to take effect. They are seeking shelter in stable growth, safe balance sheets, and frequent dividend payments. TXO offered that, so investors have rewarded it.Mercer Capital has its finger on the pulse of the energy industry. As the oil and gas industry evolves through these pivotal times, we take a holistic perspective to bring you thoughtful analysis and commentary regarding the full hydrocarbon stream, including the E&P operators and mineral aggregators comprising the upstream space. For a more targeted energy sector analysis that meets your valuation needs, please contact a member of the Mercer Capital Oil & Gas Team.
IRS Valuation Guidance
IRS Valuation Guidance

Mines, Oil and Gas Wells, & Other Natural Deposits

In this blog post, we discuss portions of Treasury Regulation 1.611 and its additional guidance when determining the fair market value of mineral properties.
Energy Newsletter Release: 1Q 2023
Value Focus | Exploration & Production

First Quarter 2023 | Region Focus: Eagle Ford

Mercer Capital’s Value Focus: Exploration & Production newsletter provides an overview of the industry through supply and demand analysis, commodity pricing, and public market performance. In addition, each issue of this quarterly newsletter focuses on a region, including Eagle Ford, Permian, Bakken, and Appalachia, examining general economic and industry trends. In this quarter’s newsletter, we focus on the Eagle Ford. Strong rig-count growth spurred an Eagle Ford production increase that was second only to the Permian.However, production improvement was offset by commodity price easing in the latter half of 2022 and early 2023, resulting in Eagle Ford comp group stock price declines over the last year.Despite those dynamics, interest in the Eagle Ford remains high, with Devon doubling its presence in the basin in late 2022 and SilverBow making significant acquisitions (SandPoint and Sundance) last year.Exploration & ProductionFirst Quarter 2023Region Focus: Eagle FordDownload Newsletter
Earnings Stability and Geopolitical Volatility
Earnings Stability and Geopolitical Volatility

Two Foes Are Battling Once More

In the mire of much of the chaotic goings-on of the world energy markets over the past year, a lot of things have changed. A lot of other things have not gone according to predictions or plans. War in Ukraine remains. Interest rates have gone up. Recession questions haunt the market: are we close to one or already in one? Uncertainty has ruled the day.
EP Second Quarter 2023 Permian
E&P Second Quarter 2023

Permian

Permian // Permian production growth over the past year continued to run well ahead of growth in the Eagle Ford, Appalachian, and Bakken, as the Permian basin remains one of the most economic regions for U.S. energy production.
Corporate Finance in 30 Minutes-Updated Whitepaper
Corporate Finance in 30 Minutes

Updated Whitepaper

In this updated whitepaper, we distill the fundamental principles of corporate finance into an accessible and non-technical primer.
Eagle Ford Activity and Production Grow, Despite Price Easing
Eagle Ford Activity and Production Grow, Despite Price Easing
The economics of oil & gas production vary by region. Mercer Capital focuses on trends in the Eagle Ford, Permian, Bakken, and Marcellus and Utica plays. This quarter we take a closer look at Eagle Ford.
Eagle Ford M&A-Transaction Activity Picks Over the Past 4 Quarters
Eagle Ford M&A

Transaction Activity Picks Over the Past 4 Quarters

Deal activity in the Eagle Ford has increased over the past 12 months, with 13 deals closed compared to 10 that closed in the prior year. What is fueling Eagle Ford's M&A momentum?
Mineral Aggregator Valuation Multiples Study Released-Data as of 03-03-2023
Mineral Aggregator Valuation Multiples Study Released

With Market Data as of March 3, 2023

Mercer Capital has thoughtfully analyzed the corporate and capital structures of the publicly traded mineral aggregators to derive meaningful indications of enterprise value. We have also calculated valuation multiples based on a variety of metrics, including distributions and reserves, as well as earnings and production on both a historical and forward-looking basis.
Themes from Q4 2022 Energy Earnings Calls-Part 2: Oilfield Service Companies
Themes from Q4 2022 Earnings Calls

Part 2: Oilfield Service Companies

The common themes among E&P operators and mineral aggregators’ in the Q3 2022 upstream earning calls included expanding business segments internationally, long-term sustainable growth for OFS, and production growth plans. In our most recent blog post, Themes from Q4 2022 Earnings Calls, Part 1 Upstream, prevalent themes from E&P companies included dividend distribution, organic growth, and management optimism regardless of upcoming economic challenges. This week we focus on the key takeaways from oilfield service operators’ Q4 2022 earnings call.
Themes from Q4 2022 Energy Earnings Calls-Part 1: Upstream
Themes from Q4 2022 Earnings Calls

Part 1: Upstream

The common themes among E&P operators and mineral aggregators' in the Q3 2022 upstream earning calls included continued share buybacks, growth in production levels, and inflation’s impact on limiting growth. This week we focus on the key takeaways from the Upstream Q4 2022 earnings calls.
NAPE 2023: Europe’s Post-Russian Energy Strategy & A 2023 Merger Outlook
NAPE 2023: Europe’s Post-Russian Energy Strategy & A 2023 Merger Outlook
Earlier this month, the NAPE Expo in Houston, TX, was once again at the center of the oil and gas industry. Every February, NAPE’s Global Business Conference provides insight from multiple perspectives in the industry. This year it included, among other topics, discussions of energy policy around the globe. Additionally, TPH&Co. provided a review of 2022 and an outlook on the merger and acquisition market in 2023.
Mailbox Money: Mineral Rights & Other Alternative Assets
Mailbox Money: Mineral Rights & Other Alternative Assets
In this 5-minute video, originally recorded for Mercer Capital’s Family Business On-Demand Resource Center, Bryce Erickson addresses the topic of oil and gas mineral/royalty rights. He explains what they are and what they aren’t, the basic framework and investment processes, and key drivers and risks associated with value.Click here to watch the video (you will be redirected to www.familybusinessondemand.com) In addition to the video, we have included additional resources on this topic that might be helpful to you.The Family Business On Demand Resource Center is a one-stop shop for enterprising families and their advisors facing the financial challenges that are common to family businesses. While not specific to the oil and gas industry, there you’ll find a curated and organized diverse collection of resources from Mercer Capital’s family business professionals, including more 5-minute videos, articles, whitepapers, books, and research studies.The perspectives offered on the Family Business On Demand Resource Center are rooted in our experiences at Mercer Capital, working with hundreds of enterprising families in thousands of engagements over the past forty years. Our main focus is on the financial challenges faced by family businesses. There’s nothing else like it, and we hope you will visit the site. We plan to feature additional videos from our oil and gas industry team in the near future.
Understanding Oilfield Services Companies & How to Value Them
Understanding Oilfield Services Companies & How to Value Them
This whitepaper provides invaluable guidance in regard to these aspects of the OFS industry. If you haven’t already, take a look.
Are You Ready for the Next Recession? What 2023 Might Have in Store
Are You Ready for the Next Recession?

What 2023 Might Have in Store

This post offers a few practical steps business owners, directors, and their advisors can take to ensure their business continues to thrive.
Energy Newsletter Release: 4Q 2022
Value Focus | Exploration & Production

Fourth Quarter 2022 | Region Focus: Appalachian Basin

In this quarter’s newsletter, we focus on the Appalachian. Notable topics include Russia-Ukraine War’s effect on the demand for LNG exports to Europe in the face of winter, tight valuations between major operators, flat production levels in the region despite a high commodity price environment, as well as increased M&A activity in 2022 highlighted by Sitio Royalties and Brigham Minerals merger — creating the largest public minerals owner.
All in the Family Limited Partnership
All in the Family Limited Partnership
In this week’s Energy Valuation Insights post, we share a recent piece from our Family Business Director blog on the topic of Family Limited Partnerships. While the post speaks directly to family-owned businesses, the content is applicable to many because the individual estate tax exemption reverts to $6 million in 2026 from its current level of $12 million. As a result, many estates are beginning to plan now.
Appalachian Gas Valuations: A Beautiful Future Emerges From An Ugly Past
Appalachian Gas Valuations: A Beautiful Future Emerges From An Ugly Past
Today’s solid earnings and strong balance sheets are a far cry from what they were then. Stock prices have risen alongside a fresh confidence that $4 and $5 gas prices will be sustainable for a while. Mercer Capital’s sector statistics tell the story.
EP First Quarter 2023 Eagle Ford
E&P First Quarter 2023

Eagle Ford

Eagle Ford // Strong rig-count growth spurred an Eagle Ford production increase that was second only to the Permian.
Appalachian Production Holds True Despite Market Disruptions
Appalachian Production Holds True Despite Market Disruptions
The economics of Oil & Gas production vary by region. Mercer Capital focuses on trends in the Eagle Ford, Permian, Bakken, and Marcellus and Utica plays.  The cost of producing oil and gas depends on the geological makeup of the reserve, depth of reserve, and cost to transport the raw crude to market. We can observe different costs in different regions depending on these factors.  This quarter we take a closer look at the Marcellus and Utica shales.Production and Activity LevelsEstimated Appalachian production (on a barrels of oil equivalent, or “boe” basis) decreased approximately 1% year-over-year through late December.  Production in the Eagle Ford, Permian, and Bakken increased 16%, 11%, and 5% year-over-year.  Despite a much-improved year-over-year commodity price environment, Appalachian production was fairly stable, largely due to high price volatility over the year, which left the markets uncertain as to where prices would be going forward. Rig counts continued to climb in all four basins over the last year.  Growth rates in the Appalachian and Permian basins were more modest, while rates for the Bakken and Eagle Ford basins were notably higher.  The Appalachian rig count rose 30% from 40 to 52 rigs.  Among the oil-focused basins, the Eagle Ford led with a 71% increase from 42 to 72 rigs.  The Bakken followed with a 56% increase (27 to 42 rigs), while the Permian had the lowest increase with a 24% increase (283 to 350 rigs). As is typical, Appalachian production has been relatively flat despite its rig count growth.  That’s due to the basin’s higher production declines which necessitate a higher rig count to maintain production levels. Commodity Price VolatilityHenry Hub natural gas front-month futures prices have experienced significant volatility over the latest year.  Prices began 2022 on a general upswing before rising sharply as the market reacted to Russia’s invasion of Ukraine in late February.  As Russia subsequently began leveraging its natural gas supplies against Europe in retaliation of Europe’s response to the war in Ukraine, natural gas prices became notably more volatile.  They rose from an early March low of $4.56 to an early June high of $9.29 — only to drop back to $5.39 in late June and then hit a 2022 high of $9.42 in late August.  By mid-December, Henry Hub had declined, albeit with only lightly reduced volatility, to $5.79.Oil prices, as benchmarked by West Texas Intermediate (WTI) and Brent Crude (Brent), also began 2022 on a steady upward trend that took the WTI from $76/bbl to $88/bbl and the Brent from $79/bbl to $91/bbl, prior to the Russian invasion.  As the reality of the Russian-Ukraine war took hold, the oil benchmarks showed a marked uptick in volatility that lasted into mid-May, with prices hitting highs of $120/bbl and $128/bbl, and lows of $93/bbl and $96/bbl.  Since then, WTI and Brent prices have trended downward, exhibiting more typical volatility other than modest rallies in August and October.  As of mid-December, WTI sat at $73/bbl and Brent at $78/bbl.Financial PerformanceThe Appalachian public comp group saw markedly strong stock price performance over the past year (through December 12th), led by Antero and EQT with price increases of 90% and 77% as of December 12th.  The remaining members of the comp group showed more modest 1-year price increases of 12% to 38%.  Prices peaked in early June for all members, except EQT, with year-to-date increases of 71% to 171%.  EQT’s stock price peaked in mid-September at a year-to-date increase of 143%.  Stock prices fell sharply beginning in mid-September but reversed direction immediately following the sabotage of the Nord Stream pipelines in the Baltic Sea that transport Russian natural gas to northern Europe.Antero and  EQT led the way among this group for several reasons.  For Antero, one reason appears to have been its lack of hedging for 2023, which has allowed it greater exposure to the uptick in gas prices and has allowed Antero to be aggressive in paying down debt.  EQT, on the other hand, does have more near-term hedging ceilings to deal with.  However, its strength is in its operational efficiencies, whereby their recent literature demonstrates breakeven operating expenses at $1.37 per mcf.  This is among the lowest in the industry and allows them to accumulate cash flow.ConclusionAppalachian production held steady in 2022 despite historically high commodity price volatility driven by the Russian-Ukraine war, the sabotage of the Nord Stream pipelines, and rising LNG exports to Europe to stave-off potential winter heating shortages.  The Q4 Appalachian rig count is at a level beyond that needed for production volume maintenance, so there would seem to be at least some potential for Henry Hub price reductions going into 2023.  However, the demand for new natural gas supplies to Europe provides a countervailing wind to any potential downward movement in natural gas prices.  In the end, the natural gas markets seem to be in the midst of a series of events that promise continued supply and demand shifts with no certainty as to where the market will go in 2023.We have assisted many clients with various valuation needs in the upstream oil and gas space for both conventional and unconventional plays in North America and around the world.  Contact a Mercer Capital professional to discuss your needs in confidence and learn more about how we can help you succeed.
M&A in Marcellus & Utica Basins
M&A in Marcellus & Utica Basins

Shareholder Value Creation Abounds; ESG Interest Waning

Through November 2021, there were three M&A deals in the Marcellus and Utica shales.  Compared to the 16 deals in the same period in 2020, companies looking to get into or out of the Appalachian basins effectively did so in 2020.   The following table summarizes transaction activity in the Marcellus and Utica shales in 2021:Click here to expand the image aboveAs shown in the following table, M&A activity picked up in 2022 year-to-date, with twice as many transactions announced.Click here to expand the image aboveWhat has caused the slight rebound in M&A activity in the Marcellus and Utica shales?  Companies are focusing on asset quality, strong balance sheets, prudent capital structures, and free cash flow growth.  Below we examine the two largest transactions that occurred in but were not limited to the Marcellus and Utica shales in 2022.Sitio Royalties and Brigham Minerals, Inc. Merge to Create the Largest Public Minerals OwnerOn September 6, Sitio Royalties Corp. (NYSE: STR) (“Sitio”) and Brigham Minerals, Inc. (NYSE: MNRL) (“Brigham”) announced a definitive agreement to combine in an all-stock merger, with an aggregate enterprise value of approximately $4.8 billion based on the closing share prices of Sitio and Brigham on September 2, 2022.  The combination brings together two of the largest public companies in the oil and gas mineral and royalty sector.  Upon completion of the merger, the combined entity will retain the name Sitio Royalties Corp.Under the merger agreement's terms, Brigham shareholders will receive a fixed exchange ratio of 1.133 shares of common stock in the combined company for each share of Brigham common stock owned.  Sitio’s shareholders will receive one share of common stock in the combined company for each share of Sitio common stock, based on ownership on the closing date.   Brigham’s and Sitio’s Class A shareholders will receive shares of Class A common stock in the combined company, and Brigham’s Class B and Sitio’s Class C shareholders will receive shares of Class C common stock in the combined company.  Upon completion of the transaction, the former Sitio shareholders will own approximately 54%, and the former Brigham shareholders will own about 46% of the combined entity on a fully diluted basis.Robert Rosa, CEO of Brigham, commented,“Our merger with Sitio creates the industry-leading powerhouse in the minerals space … with approximately 100 rigs running across all of our operating basins and greater than 50 activity wells to continue to drive production and cash flow growth.”The Sitio-Brigham deal press release discusses operational cash cost synergies, a balanced capital allocation framework that aligns with shareholder interests to drive long-term returns, enhanced margins, and increased access to capital.  But, as a recent Forbes article points out, despite Kimmeridge Energy, which owns approximately 43.5% of Sitio, being a heavy promoter of ESG in the shale business, the press release has only a slight mention of ESG.  The only direct mention of ESG is in the last bullet point of the strategic rationale behind the deal.EQT Corporation Continues to Add to Core Marcellus Asset BaseOn September 8, EQT Corporation (NYSE: EQT) (“EQT”) announced that it entered into a purchase agreement with THQ Appalachia I, LLC (“Tug Hill”) and THQ-XcL Holdings I, LLC (“XcL Midstream”) whereby EQT agreed to acquire Tug Hill’s upstream assets and XcL Midstream’s gathering and processing assets for total consideration of $5.2 billion.  The purchase price consists of cash of $2.6 billion and 55 million shares of EQT common stock worth $2.6 billion.  The transaction is expected to close in the fourth quarter of 2022, with an effective date of July 1, 2022.  Transaction highlights include:~90,000 core net mineral acres offsetting EQT’s existing core leasehold in West Virginia95 miles of owned and operated midstream gathering systems connected to every major long-haul interstate pipeline in southwest AppalachiaCombined upstream and midstream assets at 2.7x next-twelve-month (“NTM”) EBITDAUpstream-only valuation of 2.3x NTM EBITDA300 untapped drilling locations in the Marcellus and Utica shales The deal is the largest U.S. upstream deal since Conoco Phillips purchased Shell’s Permian Basin assets for $9.5 billion in September 2021. EQT President and CEO Toby Rice commented, “The acquisition of Tug Hill and XcL Midstream checks all the boxes of our guiding principles around M&A, including accretion on free cash flow per share, NAV per share, lowering our cost structure and reducing business risk, while maintaining an investment grade balance sheet.” The Tug Hill/XcL Midstream transaction piggybacks EQT’s May 2021 $2.93 billion acquisition of all of the membership interests in Alta Resources Development, LLC’s (“Alta’) upstream and midstream subsidiaries.  Consistent with his comments on the Tug Hill/Xcl Midstream deal, Mr. Rice commented that the Alta deal would provide attractive free cash flow per share accretion to EQT shareholders. As with the Sitio-Brigham deal, Forbes points out that the EQT-Tug Hill-XcL Midstream press release provides only a token reference to ESG in a quote by the CEO of Quantum Energy Partners, the private equity backers of Tug Hill and XcL Midstream.ConclusionM&A transaction activity in the Marcellus & Utica shales increased in 2022 relative to 2021, with large industry players motivated by free cash flow growth and creating shareholder value and less motivated by championing the ESG cause.We have assisted many clients with various valuation needs in the upstream oil and gas industry in North America and around the world.  In addition to our corporate valuation services, Mercer Capital provides investment banking and transaction advisory services to a broad range of public and private companies and financial institutions.  We can leverage our historical valuation and investment banking experience to help you navigate a critical transaction in the oil and gas industry, providing timely, accurate, and reliable results.  Contact a Mercer Capital professional to discuss your needs in confidence.
Themes from Q3 2022 Earnings Calls (1)
Themes from Q3 2022 Earnings Calls

Part 2: Oilfield Service Companies

In a previous post, we highlighted common themes from OFS companies’ Q2 earnings calls, which included the role of OFS in energy security, OFS operators’ focus on margins rather than market share, and industry optimism.  In last week’s post, we noted common themes from E&P companies, including a continued focus on share buybacks, moderate production growth, and the effects of inflation.  This week we focus on the key takeaways from the OFS operators’ Q3 2022 earnings calls.Expanding Role of International Business SegmentsA common theme among OFS operators included the prevalence of quarterly growth in international segments and expectations of continued optimism among international segments.  Executives noted that this growth is primarily driven by the need for updated oilfield equipment and technology outside the U.S.  Their optimism is further enhanced by the surging U.S. dollar’s effect on overseas freight costs and labor.  As broad-based activity increases tighten equipment availability, this will further drive price increases within global business segments.“Over the last few months, we booked orders for equipment into the Middle East and Africa.  We’ll continue to selectively target international markets as we progress plans for more meaningful growth abroad.  On the supply chain front, transit times and overseas freight costs are improving…while a strengthening dollar further supports improving margins.”  – Scott Bender, CEO, Cactus Inc.“Our third quarter performance demonstrates the strength of our strategy to deliver profitable international growth through improved pricing… International revenue in the third quarter for the C&P [Completion and Production] and D&E [Drilling and Evaluation] divisions grew year-over-year from a percentage standpoint in the high teens and mid-20s, respectively, which outpaced international rig count growth and reflects our competitiveness in all markets.  Our year-over-year growth and the margin expansion demonstrated by both divisions give me confidence in the earnings power of our international business.” – Jeff Miller, Chairman & CEO, Halliburton Company“I think international markets, in particular, have a long way to go in stepping up their technology that they apply in… in their drilling operations.” – Clay Williams, Chairman, President & CEO, NOV Inc. The Suspected Result of Near-Term Market Tightness — Long-term Sustainable Growth for Oilfield Service CompaniesOFS operators attributed expectations of steady and sustainable growth in their business to near-term tightness in the hydrocarbon commodity market.  Without an immediate fix to the current supply and demand imbalances, equilibrium in the global oil and gas commodity marketplace will require years of investment to level.  The imbalance may be further prolonged by E&P companies focusing on returning cash to shareholders.“While broader market volatility is clear, what we see in our business is strong and growing demand for equipment and services.  There is no immediate solution to balance the world’s demand for secure and reliable oil and gas against its limited supply.  I believe that only multiple years of increased investment in existing and new sources of production will solve the short supply… [E&P operators’] commitments to investor returns require a measured approach to growth and investment.  Service companies follow the same discipline, delivering on their commitments to investor returns and taking a measured approach to growth and investment.  What I think is underappreciated is how this results in more sustainable growth and returns over a longer period of time.” – Jeff Miller, Chairman & CEO, Halliburton Company“There’s very little used equipment that really can be refurbished economically, and what we’ve seen over the past year is more and more pressure pumpers in North America are pivoting towards buying new and the longevity and sort of the overall value offered by going to new versus used, I think, is a lot stronger.” – Clay Williams, Chairman, President & CEO, NOV Inc.“And there’s some drill out rigs that, again, what a couple of our customers have said is that they wanted to --they were out of budget, they were out of wells to complete.  They wanted to stop that in kind of mid-Q4 and then pick them back up in Q1.  Now we’ve had demand that’s kind of been building up behind, and so most of those rigs have already been redeployed… We’re now in a situation where even though there was some budget exhaustion, those rigs are now being put to work.  And we know we have demand coming on the backside and 2023.” – Melissa Cougle, CFO, Ranger Energy Services Inc.E&P Production Growth Plans Concentrated Amid Strict BudgetsAs highlighted in a theme from last week’s post, domestic E&P production is expected to rise, albeit modestly.  This growth is concentrated among certain large contracts; though the top lines may indicate relatively gradual and steady growth across the board, production growth is more concentrated among certain E&P operator plans.  More generally, a limitation on broader growth for oilfield services companies in the near term is attributable to the E&P’s limited budgets.  Considering the fragmentation in domestic production plans, some OFS companies have sought growth through acquisitions.“In terms of concentration, I’m going to guess that two-thirds — maybe a half to two-thirds — have to do with additions from our existing customers, which would be the publics and the other would be new logos.  So, I guess the short answer is, [plans for production growth are] certainly concentrated with the large publicly traded E&Ps, at least ours.” – Scott Bender, CEO, Cactus Inc.“For the fourth quarter, we expect growing opportunities associated with our Completion & Production Solutions segment’s backlog to be mostly offset by certain projects that were pulled forward into the third quarter and supply chains that remain elongated, resulting in revenues that should be relatively flat.” – Jose Bayardo, SVP & CFO, NOV Inc.“It is clear that our acquisitions executed last year are now delivering strong returns, demonstrating the value of our consolidation strategy for Ranger and for the sector more broadly.  The Ranger management team and board believe that consolidation remains an essential and ongoing process for the company within both existing and adjacent product lines.  And we continue to be actively engaged on this front.” – Stuart Bodden, CEO, Ranger Energy Services Inc. Mercer Capital has its finger on the pulse of the OFS operator space.  As the oil and gas industry evolves through these pivotal times, we take a holistic perspective to bring you thoughtful analysis and commentary regarding the full hydrocarbon stream, including the ancillary service companies that help start and keep the stream flowing.  For more targeted energy sector analysis to meet your valuation needs, please contact the Mercer Capital Oil & Gas Team for further assistance.
Themes from Q3 2022 Earnings Calls
Themes from Q3 2022 Earnings Calls

Part 1: Upstream

In Part 1: Themes from Q2 2022 Earnings Calls, the common themes among E&P operators and mineral aggregators calls included the strengthening of balance sheets to offset price volatility, the increasing role of share buybacks, and the persistence of supply and demand imbalances.  This week we focus on the key takeaways from the Upstream Q3 2022 earnings calls.Continued Focus on Share BuybacksAs we noted in our analysis of last quarter’s earnings calls, E&P operators and mineral aggregators have seen exceptional profitability since the start of the upcycle in late 2021; companies accentuated paying down their debt and distributing to shareholders.  With the continuance of stable cash flows, the role of share buybacks has increased as a source of returns in lieu of bolt-on acquisitions or other investment opportunities.“Look, we've seen the volatility in the market that every quarter, we've had the opportunity to buy shares back, and when that opportunity presents itself, we'll do so aggressively.  I think the key to any of those questions is the ability to generate free cash flow.  And that's certainly what our focus is… [as well as] maintaining the flexibility on how the return of that free cash flow gets prosecuted. I will say that in conversations with our long-only shareholders,  a lot of those guys prefer to get the cash back.  But again, we believe that we'll have opportunities to repurchase shares back.” – Travis Stice, CEO & Chairman, Diamondback Energy Inc.“While we had guided third quarter return of capital to at least 50% of our CFO due to strong operating and financial performance, our financial strength, including our replenished cash balance and favorable market conditions, [and] including clear value in our stock price, we saw an opportunity to materially step-up the pace of repurchases.  We bought back $1.1 billion of stock during the third quarter.” – Dane Whitehead, Executive Vice President and CFO, Marathon Oil Corp.“On the capital allocation side… we continue to take advantage of current equity market conditions by repurchasing 8.4 million shares in the quarter and another 3.2 million shares after the close of the quarter through October 21.  Said differently, we bought back another 4% of our total shares outstanding.  And over the last eight quarters, we have repurchased approximately 20% of the outstanding shares of the company.  We continue to see this as a remarkable low-risk capital allocation opportunity moving forward.  And although we have not given an explicit capital allocation framework, if you extrapolate these levels of buybacks moving forward, you can see that we will continue to dramatically reduce our denominator and thereby meaningfully grow our free cash flow per share.” – Alan Shepard, CFO, CNX Resources Corp.Moderate Production GrowthAs a consequence of a favorable pricing environment and continued tightness on the supply side, industry operators are increasing production in order to capitalize on strong market conditions. Ultimately, firms may not be able to fully capitalize on high prices due to increased labor and equipment costs as well as other miscellaneous supply-side challenges.“We generated total production volumes for the quarter of 40,000 Boe per day, an increase of 19% over our second quarter volumes.  All that increase was from royalty volumes, which were up 23% to 37,300 Boe per day.  Our base production is trending up as development activity remains robust across our acreage and as our target development programs with operators in the Shelby Trough, Haynesville and East Texas, Austin Chalk continue taking shape, while growing and moving forward.  Production from the quarter exceeded expectations due to certain operators, particularly in Louisiana Haynesville, bringing new wells on line at more aggressive initial flow rates to take advantage of higher natural gas prices.” – Tom Carter, Chairman and CEO, Black Stone Minerals, L.P.“We posted strong results this quarter that were underpinned by sequential production growth of 7% on a BOE basis and 8% on an oil-only basis, exceeding both our guidance and consensus estimates.  These gains were driven by well performance that was above expectations and consistent execution in the field, particularly on the completions front with reduced cycle times in the Permian and Eagle Ford.  At a bigger picture level, our commitment to a life of field development philosophy of our multi-zone resource base, paired with continuous improvements in drilling and completion designs, has resulted in year-over-year improvements in Callon's well performance at a time when concerns around inventory degradation are increasingly becoming a focal point of the industry.” – Joe Gatto, President & CEO, Callon Petroleum“I think there is asset maturation.  I think certainly, supply chain constraints are also limiting growth... I think all of those factors weigh into more of a muted production growth from US shale going forward. That said, out here in the Permian, I think we're still continuing to hit production records every month, somewhere close to 5.3 million to 5.5 million barrels a day. But that's going to be challenged to continue to grow that into the future. Do we have the assets out here?  Yes, we do.  But some of those other topical constraints that I mentioned are going to be impediments to efficient growth.” – Travis Stice, CEO & Chairman, Diamondback Energy Inc.“I think, just generally we see some large pads coming on [in] Q2 and beyond… The Diamondback piece, which we have 100% visibility on, will grow 10%.  It's just going to start growing in Q2 and Q3… the way we see it right now is basically flat oil from Q3, which was an all-time high into Q4 and Q1 and then the ramp starts to begin again in… Q2 of next year.” – Kaes Van’t Hof, President, Viper Energy Partners, L.P.Inflation Continues To Limit GrowthThe current high-price environment incentivizes operators to grow rapidly.  While most industry participants certainly would like to increase the scale of their output, multiple executives discussed how high inflation has constrained their efforts.  The impact from inflation is evident in multiple areas, but especially in the cost of raw materials and labor.“One of the major topics of the year continues to be the inflation story.  The price pressure we are seeing on steel, fuel and labor continues to be persistent.  Our employees are maintaining their focus on finding ways to mitigate inflation through innovation and efficiencies in our operations.  Through their efforts, we now expect our average well cost to increase a modest 7% as compared to last year.” – Billy Helms, President, and COO, EOG Resources Inc.“The biggest concern we've got is not so much labor inflation or service inflation outside the company as much as it is… the quality of the available labor set or the quality of the available service skill set.  And that's where we spent most of our time.  So it's not just the easy question of will the individuals and the service provider be available.  It's more a question of can we get the best of the individuals and the best of the service providers available.” – Nicholas Deluliis, President, CEO & Director, CNX Resources Corp.“Casing has been a massive headwind for us and for the industry.  Midland Basin casing is now $110 a foot, that is a huge number of… fixed cost that we can't really control here.” – Kaes Van’t Hof, President & CFO, Diamondback Energy Inc.“I think on the labor inflation side, that's subject to kind of more of the macro environment.  I mean you could potentially paint a scenario where if the company slips -- or the country slips into recession, some of those pressures ease.  And conversely, if we avoid that, you can continue to see pressure on those fronts.  So again, this just goes back to kind of the wider guidance we provided on this call, and then we'll have some more color as we move forward.  I think we'll know a lot more a quarter from now about where things are headed.” – Alan Shepard, CFO, CNX Resources Corp. Mercer Capital has its finger on the pulse of the minerals market.  As the oil and gas industry evolves through these pivotal times, we take a holistic perspective to bring you thoughtful analysis and commentary regarding the full hydrocarbon stream, including the E&P operators and mineral aggregators comprising the upstream space.  For more targeted energy sector analysis to meet your valuation needs, please contact the Mercer Capital Oil & Gas Team for further assistance.
Mineral Aggregator Valuation Multiples Study Released (3)
Mineral Aggregator Valuation Multiples Study Released

With Market Data as of November 14, 2022

Mercer Capital has its finger on the pulse of the minerals market.  An important trend has been the rise of mineral aggregators, which have largely supplanted the trusts as the primary method of publicly traded minerals ownership.Due to a variety of corporate structures (including master limited partnerships and Up-Cs) and complex capital structures (including preferred equity and non-traded common units), mineral aggregator enterprise values pulled from databases are often missing meaningful components of value, leading to skewed valuation multiples.Mercer Capital has thoughtfully analyzed the corporate and capital structures of the publicly traded mineral aggregators to derive meaningful indications of enterprise value.  We have also calculated valuation multiples based on a variety of metrics, including distributions and reserves, as well as earnings and production on both a historical and forward-looking basis.Mineral Aggregator Valuation Multiples StudyMarket Data as of November 14, 2022Download Study
45Q Tax Credit Boosts Values Of Carbon Sequestration Projects, Yet Most Still In Development
45Q Tax Credit Boosts Values Of Carbon Sequestration Projects, Yet Most Still In Development
Approximately half of the Inflation Reduction Act’s budget ($369 billion) has been authorized for spending on energy and climate change. One of the components buried in that act was the supercharging of an existing tax credit—45Q. This tax credit expanded from $50 per ton of sequestered CO2 to $85 per ton. What does this mean for potential carbon capture sequestration projects around the country? Perhaps a lot. However, it is too early to tell. According to Robert Birdsey of Greenfront Energy Partners, it would be like asking the pilgrims what they thought of America as they stepped off the boat.That has hardly kept interest and activity from moving forward. A few weeks ago, Exxon and EnLink announced a largest-of-its-kind commercial deal in Louisiana to capture emissions from CF Industries’ Ascension Parish and transport it on EnLink’s transportation network to store it underground on Exxon property. Start-up is expected in 2025 and will sequester up to two million metric tons of CO2 annually. At $85 per ton, that’s a commercially significant tax credit—$170 million. It won’t be the last one. There are dozens of projects at various points in the development pipeline for this space. In addition, capital has been flowing freely into the broader “sustainability” space. According to Morningstar, in the first half of 2022 alone, there was approximately $33 billion of net cash inflow into that sector, along with 245 new funds launched.Last week, I attended the Hart Energy Capital Conference, whereby Mr. Birdsey gave a presentation. I also spent some time with Mike Cain of U.S. Carbon Capture Solutionsto find out more. Some interesting facts and issues arose.IncentivesThis effect helps remove financing bottlenecks for a number of these green projectsThe White House has placed a value on the social cost of carbon at $51 per ton, which is partly why the tax credit was included in the Inflation Reduction Act (“IRA”). This effect helps remove financing bottlenecks for a number of these green projects. It can be, in effect, like the government financing approximately 30% of one’s equity in a project. In a space where being the low-cost producer is the name of the game, this puts a lot more players in the game. In fact, Carbon Capture Sequestration (“CCS”) volume could reach 200 million tons by the year 2030, a 13-fold increase relative to pre-IRA estimates, according to Net Zero Labs. Ironically, the upstream industry is the most qualified to capitalize on this incentive, giving traditional E&P players more opportunities to execute projects.IssuesEven so, most of the potential projects in the CCS pipeline remain in development, where memorandums of understanding and letters of intent abound. However, binding contracts are fewer and far between, and there are reasons for this. First, from the standpoint of the 45Q credit itself, there is a potential time-matching issue here. Projects like this are multi-year—even over a decade if permits get held up. If a small government congress comes along and abolishes the incentive, it would almost certainly submarine the economics of the project. At this point, the 45Q credit is at the heart of the project’s economic viability, so if it goes, the project goes. There could be a lot of elections between now and 2030, which makes some investors nervous.However, that’s less of an issue compared to others. There are three main elements to a successful CCS project: (i) an emitter, (ii) transportation, and (iii) a sequestration site. There are issues with all three. Emitters have been cagey about these projects because they are reticent about third parties adding infrastructure to an expensive asset such as a power plant. In addition, the long take-or-pay contracts that have been proposed for a lot of these projects are risky themselves. From the transportation aspect comes most of the same issues as other pipelines. Just ask the Keystone or Atlantic Coast Pipeline proponents. In addition, CO2 has to be transported at high pressures (say 1,100 PSI) in semi-liquid, low-temperature form. That makes the infrastructure potentially different than a conventional natural gas pipeline. Then, there are sequestration site issues. The injection sites for CO2 are known as Class VI wells. To date, there are only two active Class VI wells in the U.S., so permitting is a big unknown and presents a binary risk profile. Get your well approved, then move forward. If it gets rejected, your project could be finished. Oh, and did I forget to mention that these projects can be in the hundreds of millions of dollars of capital? That’s a lot of money that could wait a long time for a return.Many investors look for emitter and sequestration sites that are proximate to each otherBecause of this, many investors look for emitter and sequestration sites that are proximate to each other, which is not always easy to find. Emission concentration economics, issues with monetization of 45Q credits (there is not currently a robust trading market for these), and other issues can sideline a project.The Future?Nobody really knows, yet optimism remains. It’s an emerging market. U.S. Carbon Capture Solutions is pushing forward with its Wyoming project, even though it may be 2030 before it comes online. The 45Q appears to have given this space a shot in the arm; we’ll see in five or more years from now what that turns into.Originally appeared on Forbes.com.
Takeaways from Two Recent Energy Events in Dallas
Takeaways from Two Recent Energy Events in Dallas

Strong Industry Fundamentals, Capital Markets Showing Signs of Resurgence, and Energy Security

In the past week, several energy-related gatherings have been held in the Dallas area. We attended two of them: the D-CEO Energy Awards and Hart Energy’s Energy Capital Conference. We had numerous discussions with company representatives, dealmakers, and service providers.  The marketplace appears excited about the potential for the upcoming year amid challenges. At both events, several industry themes were evident including: the energy industry has strong fundamentals, capital markets are showing signs of a resurgence in needed capital, and energy security is returning to the lexicon.Strong FundamentalsSeveral speakers and panelists at both events expressed optimism and confidence in the important role that the sector is playing both today and in the future. “This will be the golden decade for hydrocarbon production,” said Kyle Bass of Hayman Capital at the D-CEO Energy Awards.  In this inflationary environment, the best place to be in energy, according to Mr. Bass, is royalties because they capture all the cost issues beneath them.This will be the golden decade for hydrocarbon productionAt the Hart Energy Capital Conference, Tim Perry of Credit Suisse said that returns are very strong considering high profits coupled with lower than historical valuations.  Upstream companies that used to trade at 6-8 times EBITDA now trade between 3-5 times. IPOs are coming out at higher discounts to these multiples, and as such, returns expected are higher.  Mr. Perry pointed out that energy occupies only about 5.1% of the S&P market capitalization, whereas historically, it has typically been between 8 - 13%.Which upstream area (oil vs. gas) was a better place to be right now has been a big boardroom discussion, with oil producers getting higher margins but gas producers facing a bright future with the major energy transition fuel.Capital Resurgence?Another theme was the prospect of capital returning to the space.  Considering the deleveraging trend that has been happening for several years now, it was interesting to hear from multiple panelists that capital sources are coming back to the space.  Banks are starting to return and borrowing bases, which were hard to come by, are now becoming more available to upstream producers.  Over the past five years or so, so-called “casual” investors have left the space.  The smaller landscape is now populated with sophisticated investors who are interested in energy’s strong tenets.Due to the fundamentals, private capital has also been responsive to filling the void with more unconventional sources, such as private placements and even family offices offering debt and equity capital.  The space has become more attractive as what was described on one panel as the 3 “R”s – returns; realization of the industry’s importance; and regulatory framework to allow more investing.These trends have also begun to creep into the institutional space as well.  It has become less polarizing in the past year, and more people are willing to listen to energy-oriented investment theses.  One panelist remarked that some larger institutional shops are quietly “repurposing’ some of their internal talent to the oil and gas space, with some even planning to hire energy industry teams.Energy Security Part of the optimism for the space is the realization that the geopolitical landscape is not as stable as it has been. Both conferences referenced the likelihood of food and energy shortages in the next decade.  “There are going to be riots in Europe this winter,” said Jim Wicklund of Wicklund & Associates.  With issues ranging from wars to fertilizer to pipelines; the focus in the U.S. on energy transition in the longer term may have overlooked energy security in the shorter term.Part of the optimism for the space is the realization that the geopolitical landscape is not as stable as it has beenWe can export 12 BCF a day now, but will that be enough for Europe’s needs this winter?  Mohit Singh, Chesapeake’s new CFO said that 75% of future demand growth in gas will come from LNG.  The key will be takeaway, and the next wave of LNG completions are supposed to be in 2025 or 2026, where we may be able to export closer to 28 BCF per day.  However, in the meantime, there may be more turmoil as energy markets attempt to get energy where it is needed now in both Europe and Asia.Multiple speakers and panelists lamented the overreach of the idea of energy transition to renewables at the expense of potentially available energy today.  Some expressed optimism that the Inflation Reduction Act would help remove bottlenecks on a lot of renewable projects; however, they conceded that it still won’t change the situation in the shorter term.  In addition, most panelists agreed that disincentivizing and demonizing the oil and gas industry during this energy transition has been a mistake.Jay Allison of Comstock Resources, who received the Energy Executive of the Year award at the D-CEO Awards Dinner, put it this way: “When Henry Ford invented the Model T, he didn’t kill all the horses.”Thanks again to everyone we connected with this week.  The conversations were terrific, and we enjoyed seeing all of you.
Now Available: Mercer Capital's 2022 Energy Purchase Price Allocation Study
Now Available: Mercer Capital's 2022 Energy Purchase Price Allocation Study
Mercer Capital is pleased to announce the release of the 2022 Energy Purchase Price Allocation Study.This study researches and observes publicly available purchase price allocation data for four sub-sectors of the energy industry: (i) exploration & production; (ii) oilfield services; (iii) midstream; and (iv) downstream.  This study is unlike any other in terms of energy industry specificity and depth.The 2022 Energy Purchase Price Allocation Study provides a detailed analysis and overview of valuation and accounting trends in these sub-sectors of the energy space.  This study also enables key users and preparers of financial statements to better understand the asset mix, valuation methods, and useful life trends in the energy space as they pertain to business combinations under ASC 805 and GAAP fair value standards under ASC 820.  We utilized transactions that closed and reported their purchase allocation data in calendar year 2021.This study is a useful tool for management teams, investors, auditors, and even insurance underwriters as market participants grapple with ever-increasing market complexity.  It provides data and analytics for readers seeking to understand undergirding economics and deal rationale for individual transactions.  The study also assists in risk assessment and underwriting of assets involved in these sectors. Further, it helps readers to better comprehend financial statement impacts of business combinations.>> DOWNLOAD THE STUDY <<
How Waves Of Reality Are Swelling Upstream Returns
How Waves Of Reality Are Swelling Upstream Returns
Upstream and oilfield service companies have bucked trends most of this year.While other industries have had stagnant to negative returns, the oil patch has outperformed them all, as I highlighted earlier this summer. Since then, market capitalizations have stagnated. Yet, the reality is that equity returns are soaring on a wave of cash flow right now.Operational cash flow for the sector was at its highest in the five year period since 2017 at $203 billion, according to the EIAs’ Financial Review of the Global Oil and Natural Gas Industry: Second Quarter 2022 report.This led to a 22% return on equity which was notable not only because it was the highest recorded return in the survey period, but also because it usurped U.S. manufacturing companies' returns on equity for the first time in the survey period.It has been a long time coming, but several realities have been coming to the forefront to build this wave: world realities, production realities, and capital realities.World RealitiesThe energy industry’s reality is one tethered to the zeitgeist. Few if any other industries are as sensitive to the volatility of politics, regulation, and events. A year ago, longer-term supply and demand trends were pushing tailwinds for upstream producers, but those winds blew up into a storm when Russia invaded Ukraine. Several of my contributing colleagues here at Forbes.com have done good work covering these developments. That has Russian oil production likely dropping around 20%, with an accompanying impact to prices. In addition, OPEC+ has reduced oil production quotas for October.The energy industry’s reality is that some unintended consequences regarding the scramble for energy transition away from fossil fuels have collided with “contingencies.” Aramco’s CEO Amin Nasser was very blunt about this in Switzerland last Tuesday (before the Nord Stream incident).Perhaps most damaging of all was the idea that contingency planning could be safely ignored“Perhaps most damaging of all was the idea that contingency planning could be safely ignored,” said Nasser, “Because when you shame oil and gas investors, dismantle oil- and coal-fired power plants, fail to diversify energy supplies (especially gas), oppose LNG receiving terminals, and reject nuclear power, your transition plan had better be right.”“Instead, as this crisis has shown, the plan was just a chain of sandcastles that waves of reality have washed away.And billions around the world now face the energy access and cost of living consequences that are likely to be severe and prolonged,” said Nasser.There has been a flurry of speculation as to who is responsible for the explosions emanating from the Nord Stream pipeline, but what is now concerning is Europe’s ability to keep warm this winter. The U.K. reversed its fracking ban to help secure its energy supply. It may be too little too late this winter for the Brits.In the meantime, Europe’s eyes look to the U.S. to stand in the growing energy gap, particularly gas.  The U.S. has skyrocketed to become the top exporter of LNG in the world this year. This won’t change any time soon and is expected to continue to expand and grow.At the same time, U.S. domestic demand has been growing too, thus multiplying natural gas prices compared to two years ago.Production RealitiesWhile demand has resurged domestically and abroad, upstream production has not been keeping up the same way it has in the past. The good news is that production is growing and will continue to. However, there are several things limiting growth. As I have written before, producers have been cautious for a myriad of reasons and as such, new major investments in development and drilling have been stalled. According to the EIA Financial Review, Capex of the companies surveyed was $59 billion in the 2Q of 2022, only 8% higher than the 2Q of 2021.Rig counts are growing, but not at the same pace as they did the last time commodity prices were this high.DUC wells are at the lowest level in almost a decade, so drilling inventories continue to shrink.Another reality is that productivity at the individual rig level is waning. This comes in two ways: 1) the form of productivity for new wells drilled, and 2) existing legacy production is declining faster than before.Explanations for this are not entirely clear. Perhaps it is the exhaustion of top-tier PUD well locations, continued permitting problems that Joe Manchin could not fix, or the flight of talent from the oilfield in the last few cycles. Costs increased for the seventh straight quarter in the Fed Survey – near historical index highs. Nonetheless – it is happening and fueling a bevy of comments like this from the Dallas Fed Survey: “Uncertainty on the political front continues to be a major concern. The withdrawal of leases that have already been issued is an example. Inflationary pressure is eating significantly into discretionary cash flow, limiting the amount of money allocated to new projects.” 85% of survey participants expected to see a significant tightening in the oil market by the end of 2024 given the underinvestment in exploration. Capital RealitiesIn the past several years there simply has not been enough capital deployed in the sector to defray some of the shorter-term event volatility such as Ukraine’s war with Russia.79% in the Fed Survey expect to see some investors return to the spaceWith the spike in prices, 79% in the Fed Survey expect to see some investors return to the space, attracted by superior returns. However, it may be some time for that to matter. In this business, measured in years and decades, investments that can move the world needle take time to come to fruition. In the meantime, 69% of respondents in the Fed Survey expect to see the age of inexpensive gas ending by 2025. Existing capital remains focused on paying off debt and dividends, not drilling. Cash flows from Operations of $203 billion and Capex of $59 billion clearly communicates this reality.In the long run, prices ultimately communicate reality in a commodity business, so the expectations of higher prices should be the instigator to change behavior to a more balanced energy policy for much of the developed world.In the short run, oil and gas investors are getting exceptional returns. That should not change any time soon.Originally appeared on Forbes.com.
Mineral Interest Owners: How to Know What You Own
Mineral Interest Owners: How to Know What You Own
Because of the popularity of this post, we revisit it this week. Originally published in 2019, this post is as a guide for mineral owners who are seeking to learn more about what they own.As we’ve discussed, there are plenty of factors to consider when determining the value of mineral interests. While some mineral owners may be very well attuned to decline curves and local pricing dynamics, others may only casually monitor the price of oil and gas to get a general sense of the trend in the industry.  This post is geared towards those mineral interest owners who have less knowledge on the subject and should serve as a guide for those seeking to learn more about what they own. We frequently receive calls from mineral interest owners who know little about what they own other than the operator’s name on the check and the amount they receive each month. Besides just the amount paid by the operator, royalty checks provide valuable information to mineral owners that can help determine the value of their minerals.How to Read a Royalty CheckThe information on royalty checks is beneficial because it gives mineral interest owners plenty of granular detail on how the operator calculates their monthly payment. The problem is that companies may issue checks with differing formats (see two examples below) and they can be hard to read. However, with a trained eye, mineral interest owners can learn to read these checks and glean valuable insight into what is driving the value of their interests.The first example is a check one might actually receive in the mail. The second is a sample check provided by an operator to help owners understand what it means. Regardless of the operator, there are a few key items that appear on every check:Ownership PercentageProduct CodeCountyOwnership PercentageA lease arrangement is designed to be a mutually beneficial agreement. Mineral owners own the rights to a valuable commodity, but they lack the ability to harvest it themselves. Operators come in with the equipment and requisite knowledge necessary to extract minerals from the ground. In exchange for the right to drill on the property, operators pay mineral owners a fraction of the revenue generated from the production. This fraction can appear on a check as a string of numbers like 0.0234375. You may be wondering, where does this number come from? This is the product of the net mineral acreage owned multiplied by the royalty percentage negotiated.Most of the United States uses the Public Land Survey System which is divided into townships and further into sections. A township is 36 sections and a section is 640 acres (or one square mile).[1] Sections are further broken down into quadrants, or some other division as the land is passed down over time. For instance, a lease could specify “all of the mineral interest under the E ½ SE ¼ of 11-2N.” This is read “The east half of the southeast quarter of Section 11, township 2 North.”  As depicted below, this would be the rectangle in the bottom right quarter, and would represent 80 net mineral acres.  That is: 640 acres per section times ¼ times ½. The lease would go on to specify the royalty percentage to be paid, like 3/16. This will frequently be presented in some form similar to the follow: “To pay Lessor for gas (including casinghead gas) and all other substance covered hereby, a royalty of 3/16 of the proceeds realized by Lessee from the sale thereof.” This simply means the operator will pay a royalty of 3/16 of revenue generated from production on the property. Multiplied by the 80 net mineral acres that make up the 640 acre section, we arrive at: 80/640 x 3/16 = 0.0234375Owners will note much larger dollar figures on their checks which represent the gross revenue the operator receives from production of the minerals.  This gross value is multiplied by the ownership percentage, which determines the amount actually received by the owner on their check. Knowing the net mineral acreage owned (not determined by the operator) can help determine the royalty rate the mineral owner is being paid, which helps to understand the value ultimately being paid for their interests.Product CodeThe information on royalty checks is beneficial because it gives mineral interest owners plenty of granular detail on how the operator calculates their monthly payment.The revenue received by both the operator and ultimately the owner depends on both the quantity produced and the price achieved.  As of the writing of this article, crude oil prices are trading around $53 per barrel for West Texas Intermediate (WTI), the most commonly tracked figure for U.S. crude oil. By comparison, natural gas is trading around $3.04 per Mcf at the Henry Hub, the most common benchmark for natural gas in the country.  Knowing what is being produced: oil, gas, NGL, or a combination of these is crucial to understanding the value of the interests. Owners can figure this out by looking at the product code on their checks, which can be expressed as either a letter or number. Our first example lists the product code as 204, and the legend at the bottom of the check indicates that gas is being produced. Even less clearly, our second example shows the letter “G” under the “P” column, and which, according to the legend, means gas is being produced. This can be far from intuitive without some sort of key describing each item.When oil prices decline, as they have since the beginning of October, mineral owners who receive royalty checks based on oil production can expect to see smaller figures on their checks. But the price isn’t purely based on the value listed on an exchange. It also depends on location and infrastructure to bring the commodity to market.CountyThe county where the minerals are produced is another common feature of royalty checks. However, it is not clearly stated as “Gaines County” for example. In our first example, we see the check says /TX/ Gaines which tells us the mineral interests are in Gaines County, Texas, which is located in the prolific Permian Basin. Again, this isn’t very clear just from looking at the check, and someone not from the region may not automatically know the names of counties in different states.Knowing the county where the minerals are located can go a long way to understanding their value.  For instance, oil production in the Permian Basin has increased significantly in recent years and has been a very attractive place for industry players. However, a lack of pipeline infrastructure has led to oversupply, meaning operators were forced to take a discount to the WTI price. Mineral owners have no control over where and when operators choose to produce, and current production leads to more upfront revenue, but taking a discounted price to get the revenue upfront could ultimately be detrimental to mineral owners in the long term, given the way production tends to decline significantly.Other Sources of InformationWhile royalty checks are tangible pieces of information sent frequently to mineral owners, there’s more information out there that owners can turn to. The lease agreement itself can be the primary source for determining what you own. While many may look the same, lease agreements are ultimately an economic agreement between two parties and can have a variety of different clauses. However, there are frequently instances where our clients do not have access to these key documents. In the case of interests being passed down or donated, clients are usually dealing with legacy arrangements with operators and may not have all the documents that spell out the specific rights with their particular lease.Royalty checks provide valuable information to mineral owners that can help determine the value of their minerals.There are other potential sources of information published online that owners can access free of charge. For instance, in Texas, there’s the Texas General Land Office and Texas Railroad Commission where mineral owners can, among other things, zoom in on plots of land and see well locations. Mineral owners can also learn about historical drilling permits and activity by region. The FDIC also publishes sales of oil and gas interests which can be helpful to see actual sales prices for mineral interests observed in the market.ConclusionRoyalty checks are hardly intuitive, and not everyone would bother asking too many questions when they regularly receive a check in the mail. However, without putting in some research, it can be hard to know if the next check will be higher or lower, or if there will even be one next month. That’s where it becomes crucial to understand what drives the value for mineral interests and what are the relevant risk factors. For those looking to sell their interests, or simply looking to understand the value of what they own, an appraisal can be a helpful tool in understanding both the value of mineral interests, and what drives this value. It is important to seek advice from someone who has experience valuing mineral interests and is well-versed in all potential sources of information.Mercer Capital is an employee-owned independent financial advisory firm with significant experience (both national and internationally) valuing assets and companies in the energy industry (primarily oil and gas, bio fuels and other minerals). Our oil and gas valuations have been reviewed and relied on by buyers and sellers and Big 4 Auditors.As a disinterested party, we can help you understand the fair market value of your royalty interest and ensure that you get a fair price for your interest. Contact anyone on Mercer Capital’s Oil and Gas team to discuss your royalty interest valuation questions in confidence.[1] Exampled based on a presentation at the National Association of Royalty Owners (NARO) 2018 Conference in Denver, CO
EP Fourth Quarter 2022 Appalachian Basin
E&P Fourth Quarter 2022

Appalachian Basin

Appalachian Basin // Production in the Marcellus & Utica held steady in 2022 despite historically high commodity price volatility driven by the Russian-Ukraine war, the sabotage of the Nord Stream pipelines, and rising LNG exports to Europe to stave-off potential winter heating shortages.
Bakken Regains Its Footing
Bakken Regains Its Footing
The economics of Oil & Gas production vary by region. Mercer Capital focuses on trends in the Eagle Ford, Permian, Bakken, and Marcellus and Utica plays. The cost of producing oil and gas depends on the geological makeup of the reserve, depth of reserve, and cost to transport the raw crude to market. We can observe different costs in different regions depending on these factors. This quarter we take a closer look at the Bakken.Production and Activity LevelsEstimated Bakken production (on a barrels of oil equivalent, or “boe” basis) increased by 5% year-over-year in September. Bakken production, relative to the September 2021 level, plunged nearly 20% in April due to the impact of back-to-back blizzards but had recovered to the September 2021 level by June 2022. Production in the Eagle Ford and Permian were 13% and 8% higher, respectively than in September 2021, without the short-lived plunge seen in the Bakken. The gas-focused Appalachia region production relative to September 2021 levels was more stable than the oil-focused regions, with relative production only varying within a band of -1% to 4%, ending at a year-over-year 3% increase in September 2022. As of September 16, 2022, 40 rigs were operating in the Bakken, marking a 74% increase from September 10, 2021. Eagle Ford, Permian, and Appalachia rig counts were significantly higher than year-earlier levels at 112%, 35%, and 24% increases, respectively. The Permian continued to command the largest number of rigs at 343, with the Eagle Ford and Appalachia closer in-line with the Bakken at 72 and 47 rigs, respectively. Oil Climbs While Gas Shows Heightened VolatilityOil prices, as benchmarked by West Texas Intermediate (WTI) and the Brent Crude (Brent), rose from $72/bbl and $75/bbl, respectively, in September 2021 to $85/bbl and $90/bbl, respectively, as of September 16, 2022. While the rise in pricing was fairly steady through mid-February 2022, the Russian invasion of Ukraine spurred a series of ups and downs, with prices spiking to a high of $120/bbl (WTI) and $128/bbl (Brent) in early March, immediately followed by a plunge to $94/bbl and $96/bbl in mid-March. Subsequent spikes and dips were somewhat more muted, but prices remained volatile through early June. A general price decline during the third quarter resulted in prices at the $85/bbl and $90/bbl level.Henry Hub natural gas front-month futures prices dipped from a late 2021 high of $5.48/mmbtu to a low of $3.44/mmbtu near 2021 year-end as commodity markets incorporated indications of rising production levels and ebbing weather-driven demand. Pricing subsequently rose to as high as $9.29/mmbtu in June on weather-driven demand and lacking supplies due to a reduction in Russian exports. In mid-June Henry Hub pricing began a sharp decline on the announcement that prices recovered over the remaining two months of the September LTM period, albeit with some volatility, to end at $7.81/mmbtu.Financial PerformanceThe Bakken public comp group's latest twelve-month financial performance (stock price) analysis was reduced to two subject companies and the XOP SPDR, as a result of the Whiting and Oasis merger in March 2022. The combined Whiting/Oasis company, Chord Energy, appears in our analysis as CHRD.The Bakken comp group showed strong price performance from year-end 2021 through early June, with increases ranging from 63% to 83%, largely reflective of oil prices. The subsequent decline in commodity prices, which ran nearly un-checked for two months, slashed the analysis period performance to increases of only 3% and 46%, with Chord posting a decline that nearly wiped out its post September 2021 gains. Prices have recovered since July with one-year gains of 42% (Chord) to 61% (Continental).ConclusionThe Bakken showed a general increase in activity over the last year, albeit with a large winter storm disruption and subsequent production recovery along the way. Rig counts have risen on strong commodity pricing, despite the oil price decline in Q3 2022. Share prices generally increased early in the latest twelve-month period, with a sharp decline in Q3 tied to oil prices slipping. Share prices recovered enough in late Q3 to show reasonably strong year-over-year growth as of September.We have assisted many clients with various valuation needs in the upstream oil and gas space for both conventional and unconventional plays in North America and around the world. Contact a Mercer Capital professional to discuss your needs in confidence and learn more about how we can help you succeed.
Bakken M&A
Bakken M&A

Increased Transaction Volume Continues into 2022

Deal flow in the Bakken has been steady over the last twelve months, with 14 transactions announced since October 2021, up from nine deals during the same period in 2020-2021.  Devon Energy’s $5.6 billion acquisition of assets from WPX Energy was the only deal in the twelve months prior to September 2021 that exceeded $1.0 billion in value.  In comparison, five deals exceeded $1.0 billion during the twelve-month time period ended September 2022, led by the Oasis Petroleum – Whiting Petroleum merger, at $6.0 billion.Recent Transactions In the BakkenA table detailing transaction activity in the Bakken over the last twelve months is shown below.  Despite an increase in the number of deals, relative to 2020 – 2021, the median deal size decreased by roughly $215 million, with five deals valued at less than $200 million. The median value per acre and value per Boepd, however, increased over 300% and 100%, respectively.Oasis and Whiting Combine In a $6.0 Billion MergerOn March 7, 2022, Oasis Petroleum and Whiting Petroleum announced a $6.0 billion merger, renaming the combined entity Chord Energy. The deal closed on July 5, 2022. Under the terms of the agreement, Whiting shareholders received 0.5774 shares of Oasis common stock and $6.25 in cash for each share of Whiting common stock owned. Oasis shareholders received a special dividend of $15.00 per share. At closing, Whiting and Oasis shareholders owned approximately 53% and 47%, respectively, of the combined entity on a fully diluted basis. Transaction highlights include:Production (2022 Q1) – 92,000 BoepdAcreage – 480,000 net acres in Montana and North DakotaThe deal creates the Bakken’s second-largest producer and the largest pure-play E&P A pro forma table of the transaction is shown below:Devon Energy - RimRock Oil and Gas DealThe next largest deal exclusive to the Bakken is Devon Energy’s $865 million acquisition of a working interest and related assets from RimRock Oil and Gas (seven of the 14 deals analyzed included acreage or midstream assets in areas in addition to the Bakken, including the $4.8 billion Sitio Royalties – Brigham Minerals transaction and the $1.8 billion Crestwood Equity Partners – Oasis Midstream Partners transaction).  The deal was announced on June 8, 2022 and closed on July 21, 2022. Deal highlights include:38,000 net acres in Dunn County, North Dakota15,000 Boep/d as of Q1 2022 (78% oil)88% working interestOver 100 drilling locations Characterized by Devon Energy as a bolt-on acquisition, the 38,000 net acres are contiguous to Devon Energy’s existing position in the Bakken. Production from the acquired assets is expected to increase to approximately 20,000 Boep/d over the next twelve months. RimRock Oil and Gas is backed by private equity sponsor Warburg Pincus, which has held a stake in RimRock Oil and Gas since 2016.ConclusionM&A transaction activity in the Bakken increased through year-to-date 2022 relative to the same time period in 2021 and consisted of a handful of large deals and numerous small deals.  Deal activity in the Bakken will be important to monitor as companies continue to find significant opportunities to grow their Bakken positions.We have assisted many clients with various valuation needs in the upstream oil and gas industry in North America and around the world.  In addition to our corporate valuation services, Mercer Capital provides investment banking and transaction advisory services to a broad range of public and private companies and financial institutions.  We have relevant experience working with companies in the oil and gas space and can leverage our historical valuation and investment banking experience to help you navigate a critical transaction, providing timely, accurate and reliable results.  Contact a Mercer Capital professional to discuss your needs in confidence.
Themes from Q2 2022 Earnings Calls
Themes from Q2 2022 Earnings Calls

Part 1: Upstream

In the post Upstream Reviews of Q1 2022 Earnings Calls, the common themes among the earning calls of both E&P operators and mineral aggregators included the role of U.S. production in the European market, industry confidence in continued favorable pricing, and the trend of increasing completions.This week, we focus on the key takeaways from the Q2 2022 Upstream earnings calls including strong balance sheets, the increasing role of share buybacks, and supply and demand in the global oil & gas commodities market.Strong Balance Sheets and Cash Positions to Weather Price Volatility and Gain Upside ExposureExecutives zeroed in on the importance of a strong balance sheet amid the continuing volatility of oil and gas commodity prices. Upstream players can utilize robust cash positions to weather different price cycles and increase operational flexibility. Additionally, upstream Q2 earnings calls underlined the greater exposure to the high cycles by minimizing firm debt burden.“My perspective [is] as long as our return objectives are being met, modestly building some cash on the balance sheet is a positive thing. We're obviously in a highly volatile commodity price environment [and] I'd like to have a minimum of $500 million on the balance sheet just to handle intra-month working capital swings. We do have a couple of debt maturities coming up… We intend to retire that debt with cash on hand, so preparing for that time when prices are strong, is a good thing. And then also, it provides us the flexibility… on accretive bolt-on acquisitions that can improve our portfolio… given the macro uncertainties [ and] the volatility. So having a very robust company with strong liquidity, I think is a plus… Our return to shareholder commitment is top priority, but also keeping a bulletproof balance sheet and ample liquidity is right alongside that in our conservative financial model.”– Dane Whitehead, EVP & CFO, Marathon Oil Corp.“We want the absolute debt levels to be at $2 billion or even lower than that. We'd like to approach $1.5 billion over the next kind of medium term… The one times and the $2 billion or less of debt allows us to have a balance sheet that positions us to [future] swings in commodity prices. So, for us it's not as much a mid-cycle price. It allows us to go low and it allows us to go high. And we have a balance sheet that we feel gets us through the different commodity price environments.”– Kevin Haggard, SVP & CFO, Callon Petroleum Co.“The way we think about it is the best hedge is to have a strong balance sheet coupled with the strategy that can pretty much work in [a] multitude of prices and operational environments. So, this allows us to execute through these different commodity cycles. At current prices, our balance sheet is improving rapidly, so I think that's positioned us well to achieve our long-term debt target.”– Tom Mireles, EVP & CFO, Murphy Oil Corp.Increasing Role of Share Buybacks in Capital AllocationE&P operators and mineral aggregators have seen exceptional profitability since the start of the upcycle in 2021; companies started paying down their debt and distributing to shareholders. With the continuance of stable cash flows, the role of share buybacks has increased as a source of returns in lieu of bolt-on acquisitions or other investment opportunities.“So yes, like we’ve mentioned a bunch of different times. I mean, evaluating M&A, we are going to be selective and picky. I mean, we do look at this from an internal kind of risk-adjusted rate of return standpoint -- and as we’ve said before… it has to compete with our other capital allocation opportunities. And right now, at this current time, the best risk-adjusted meaningful for way to grow our free cash flow per share is buying ourselves… We’re always in the know of what’s going on in the M&A space, but with the low-risk opportunity to grow free cash flow per share, so visibly in front of us [by] buying ourselves, it’s hard to compete with that.”– Don Rush, Chief Strategy Officer, CNX Resources Corp.“We certainly think that there's a lot of value in our existing stock price, and we think that, that oil and public equity stocks [are] really undervalued right now… We spent about $500 million in the last 2 to 3 months repurchasing shares, and the Board just essentially doubled our authorization up to $4 billion. So, the base dividend still remains sacred, sustainable and growing followed by this environment share repurchases… [We will] make up the difference... returning at least 75% of free cash flow.”– Travis Stice, CEO & Chairman, Diamondback Energy Inc.“We're always assessing and evaluating bolt-on opportunities in basins where we have a competitive advantage and can generate value for our shareholders… We have a tremendous amount of confidence in our organic case, which delivers market-leading free cash flow and return of capital. And that is [how] we're going to assess all opportunities. So, the bar is quite high, and whatever we do, it's going to have to be accretive to that organic case… So, the same discipline that we show in our business is the same discipline we'll show in assessing inorganic opportunities. But to be clear, we like the assets in our core portfolio, and we're always looking to further improve our core positions.”– Lee Tillman, Chairman, President & CEO, Marathon Oil Corp.Beliefs of a Prolonged Imbalance of Supply and Demand in the Global Oil & Gas Commodities MarketExecutives of E&P companies and mineral aggregators underscored the economic effects of current global events as it pertains to the industry. Global demand for such commodities continues to grow despite the obstacles on the supply side. The current stream of Russian natural gas to Europe is not deemed to be reliable, OPEC+ is either unable or unwilling to meaningfully increase oil production, and U.S. E&P operators can only marginally ramp up production in the near-term. Meanwhile, demand shows no sign of dissipating as China re-opens from Covid-19 lockdowns and European officials attempt to secure enough natural gas in preparation for the winter so as to avoid rationing.“You think about US E&Ps, [and] the inability to really ramp up production because of the supply chain or the return of capital pieces… You think about the current potential issues in Russia and the potential embargo that's going to happen here at the end of December, the need to refill the SPR [Strategic Petroleum Reserve], because we've drawn down on those volumes significantly, and then really kind of the lack of OPEC’s ability to ramp up production here… [it] is really indicative to me of fundamental positives as we think about the second half and into 2023. So, I think you're going to see an improvement in energy markets going forward, and hopefully that yield compresses as well.”– Rob Roosa, Founder & CEO, Brigham Minerals Inc.“As China reopens further [the] utilization rate is expected to climb to the upper 80% range. This higher utilization rate, combined with an estimated 500,000 barrels per day of new PDH capacity coming online in China and over 100,000 barrels per day of new capacity in Europe and North America over the next 18 months, is expected to lead to a tightening propane market as we enter winter, with over 50% of our NGL volumes being exported.”– Dave Cannelongo, SVP of Liquids Marketing & Transportation, Antero Resources Corp.“I'm still very optimistic that the oil price is going to continue to march forward with probably more upside than downside. Demand is coming back. Around the world, people are flying more. China's going to come back and as you know there's not much supply [in] the OPEC agreement… OPEC+ announced a minuscule increase today… They just don't have the supply, [there is] very little left in UAE and Saudi.”– Scott Sheffield, CEO & Director, Pioneer Natural Resources Co. Mercer Capital has its finger on the pulse of the minerals market. As the oil and gas industry evolves through these pivotal times, we take a holistic perspective to bring you thoughtful analysis and commentary regarding the full hydrocarbon stream, including the E&P operators and mineral aggregators comprising the upstream space. For more targeted energy sector analysis to meet your valuation needs, please contact the Mercer Capital Oil & Gas Team for further assistance.
Mineral Aggregator Valuation Multiples Study Released (2)
Mineral Aggregator Valuation Multiples Study Released

With Market Data as of August 15, 2022

Mercer Capital has its finger on the pulse of the minerals market.  An important trend has been the rise of mineral aggregators, which have largely supplanted the trusts as the primary method of publicly traded minerals ownership.Due to a variety of corporate structures (including master limited partnerships and Up-Cs) and complex capital structures (including preferred equity and non-traded common units), mineral aggregator enterprise values pulled from databases are often missing meaningful components of value, leading to skewed valuation multiples.Mercer Capital has thoughtfully analyzed the corporate and capital structures of the publicly traded mineral aggregators to derive meaningful indications of enterprise value.  We have also calculated valuation multiples based on a variety of metrics, including distributions and reserves, as well as earnings and production on both a historical and forward-looking basis.Mineral Aggregator Valuation Multiples StudyMarket Data as of August 15, 2022Download Study
Value Focus | Exploration & Production
Value Focus | Exploration & Production

Second Quarter 2022 | Region Focus: Permian

Mercer Capital’s Value Focus: Exploration & Production newsletter provides an overview of the industry through supply and demand analysis, commodity pricing, and public market performance. In addition, each issue of this quarterly newsletter focuses on a region, including, Eagle Ford, Permian, Bakken, and Appalachia, examining general economic and industry trends. In this quarter’s newsletter, we focus on the Permian.  Notable topics include the impact of Russia’s invasion of Ukraine on oil prices, the deleveraging of the majors relative to the constituents of the S&P 500, the increase in production in the Permian compared to other basins, and Earthstone Energy’s acquisition of Bighorn Permian Resources’ Midland Basin assets. Download the Newsletter below.VALUE FOCUSExploration & ProductionSecond Quarter 2022Region Focus: PermianDownload Newsletter
What Is a Fairness Opinion And What Triggers the Need for One?
What Is a Fairness Opinion And What Triggers the Need for One?
For this week's post, we republish a prior post on the subject of Fairness Opinions. It's proven to be one of the most popular posts on the blog. If you missed it the first time, we hope you find it informative and helpful.What Is a Fairness Opinion?A Fairness Opinion involves a comprehensive review of a transaction from a financial point of view and is typically provided by an independent financial advisor to the board of directors of the buyer or seller.  The financial advisor must look at pricing, terms, and consideration received in the context of the market for similar companies. The advisor then opines that the transaction is fair, from a financial point of view and from the perspective of the seller’s minority shareholders. In cases where the transaction is considered to be material for the acquiring company, a second Fairness Opinion from a separate financial advisor on behalf of the buyer may be pursued.Why Is a Fairness Opinion Important?Why is a Fairness Opinion important?  There are no specific guidelines as to when to obtain a Fairness Opinion, yet it is important to recognize that the board of directors is endeavoring to demonstrate that it is acting in the best interest of all the shareholders by seeking outside assurance that its actions are prudent.One answer to this question is that good intention(s) without proper diligence may still give rise to potential liability.  In its ruling in the landmark case Smith v. Van Gorkom, (Trans Union), (488 A. 2d Del. 1985), the Delaware Supreme Court effectively made the issuance of Fairness Opinions de rigueur in M&A and other significant corporate transactions.  The backstory to this case is the Trans Union board approved an LBO that was engineered by the CEO without hiring a financial advisor to vet a transaction that was presented to them without any supporting materials.  Regardless of any specific factors that may have led the Trans Union board to approve the transaction without extensive review, the Delaware Supreme Court found that the board was grossly negligent in approving the offer despite acting in good faith.  Good intentions, but lack of proper diligence.The facts and circumstances of any particular transaction can lead reasonable (or unreasonable) parties to conclude that a number of perhaps preferable alternatives are present. A Fairness Opinion from a qualified financial advisor can minimize the risks of disagreement among shareholders and misunderstandings about a deal. They can also serve to limit the possibilities of litigation which could kill the deal. Perhaps just as important as being qualified, a Fairness Opinion may be further fortified if conducted by a financial advisor who is independent of the transaction.  In other words, a financial advisor hired solely to evaluate the transaction, as opposed to the banker who is paid a success fee in addition to receiving a fee for issuing a Fairness Opinion.When Should You Obtain a Fairness Opinion?While the following is not a complete list, consideration should be given to obtaining a Fairness Opinion if one or more of these situations are present:Competing bids have been received that are different in price or structure, leading to potential disagreements in the adequacy and/or interpretation of the terms being offered, and which offer may be “best.” Conversely, when there is only one bid for the company, and competing bids have not been solicited.The offer is hostile or unsolicited.Insiders or other affiliated parties are involved in the transaction, giving rise to potential or perceived conflicts of interest.There is concern that the shareholders fully understand that considerable efforts were expended to assure fairness to all parties.What Does a Fairness Opinion Cover?A Fairness Opinion involves a review of a transaction from a financial point of view that considers value (as a range concept) and the process the board followed in reaching a decision to consummate a transaction.  The financial advisor must look at pricing, terms, and consideration received in the context of the market.  The advisor then opines that the consideration to be received (sell-side) or paid (buy-side) is fair from a financial point of view of shareholders, especially minority shareholders in particular, provided the advisor’s analysis leads to such a conclusion.While the Fairness Opinion itself may be conveyed in a short document, most typically as a simple letter, the supporting work behind the Fairness Opinion letter is substantial.  This analysis may be provided and presented in a separate fairness memorandum or equivalent document.A well-developed Fairness Opinion will be based upon the following considerations that are expounded upon in the accompanying opinion memorandum:A review of the proposed transaction, including terms and price and the process the board followed to reach an agreement.The subject company’s capital table/structure.Financial performance and factors impacting earnings.Management’s current year budget and multi-year forecast.Valuation analysis that considers multiple methods that provide the basis to develop a range of value to compare with the proposed transaction price.The investment characteristics of the shares to be received (or issued), including the pro-forma impact on the buyer’s capital structure, regulatory capital ratios, earnings capacity, and the accretion/dilution to earnings per share, tangible book value per share, dividends per share, or other pertinent value metrics.Address the source of funds for the buyer.What Is Not Covered in a Fairness Opinion?It is important to note what a Fairness Opinion does not prescribe, including:The highest obtainable price.The advisability of the action the board is taking versus an alternative.Where a company’s shares may trade in the future.How shareholders should vote a proxy.The reasonableness of compensation that may be paid to executives as a result of the transaction. Due diligence work is crucial to the development of the Fairness Opinion because there is no bright-line test that consideration to be received or paid is fair or not.  The financial advisor must take steps to develop an opinion of the value of the selling company and the investment prospects of the buyer (when selling stock).ConclusionThe Professionals at Mercer Capital may not be able to predict the future, but we have four decades of experience in helping boards assess transactions as qualified and independent financial advisors.  Sometimes paths and fairness from a financial point of view seem clear; other times they do not.Please give us a call if we can assist your company in evaluating a transaction.
Talk To The Hand: Upstream Industry Eyeing Returns More Than Rigs
Talk To The Hand: Upstream Industry Eyeing Returns More Than Rigs
Second quarter earnings for publicly traded upstream producers are trickling in, and profitability has returned to the energy sector. In the meantime, government officials have been sending mixed messages to the upstream sector, desiring temporary supply relief in the aim of lowering prices whilst remaining bearish on fossil fuels overall. The industry response: thanks, but no thanks (a polite way of putting it). Producers have largely been holding the course set years ago towards returns and deleveraging, snubbing pressure from the Biden administration. It has been tempting for producers to ramp up production amid $100+ oil prices and gas prices the highest they have been since 2008. However, with supply chain issues and labor shortages, the appeal has been dampened.Cash Flow Remains KingAccording to the latest Dallas Fed Energy Survey, business conditions remain the highest in the history of the survey. Concurrently, profits continue to rise. Analysts are pleased and management teams are eagerly talking about free cash flow, debt management, and stock buybacks. By the way, an interesting factoid from Antero’s investor presentation: most oil and gas companies are now much less levered than their S&P 500 counterparts. When it comes to Net Debt to EBITDAX multiples, the majors average about 0.9x while the S&P 500 averages 2.8x. Most independents that I reviewed were aiming towards around 1x leverage.The industry should be able to keep it up. Last year around this time, I was questioning how long this might be able to continue. I noted drilled but uncompleted well (“DUC”) counts as an inexpensive proxy for profitable well locations. However, at today’s prices, DUCs matter less than they did from an investment decision standpoint.I sampled current investment presentations of six upstream companies (randomly chosen) and read them to discern key themes that they are communicating to investors. Adding new rigs to the mix was not on any of their agendas. Not one has announced a revision to their capex plans from early in the year even amid the changes in the past five months. There have been some companies accelerating plans, but not many. This quote from the Fed Energy Survey was representative of sentiment in this area: “Government animosity toward our industry makes us reluctant to pursue new projects.” There are 752 rigs in the U.S. currently, according to Shaleexperts.com. In early March, the week before the pandemic wreaked its industry havoc — there were 792. Yes - we still have not reached pre-pandemic rig counts. To boot, rigs are relatively less productive on a per rig basis, primarily because most new drilling locations are less attractive and productive than the ones already drilled. The capex calvary is not coming to the rescue either. Capex at the world’s top 50 producers is set to be just over $300 billion this year, as compared to $600 billion in 2013 according to Raymond James. 2013 was the last year oil prices were over $100 a barrel for the year. As has been said before, production should grow, but not at a particularly rapid pace.Energy Valuations: A Bright SpotThese industry and commodity forces have contributed to the energy sector having an outstanding year from a stock price and valuation perspective as well. Returns have outpaced all other sectors, and Permian operators have performed at the top of the sector. While the U.S. suffered its second quarter of GDP decline in a row, and the stock market has officially become a bear but energy returns stand out. Some investors appear to be changing their tune towards the energy sector amid these kinds of results, and the valuations are reflecting this. There are some indicators that suggest we could be entering into a long “super cycle” for the energy sector whereby the industry could outperform for years to come. It bears out that to fruition the sentiment I quoted last year as well from the Dallas Fed’s Survey: “We have relationships with approximately 400 institutional investors and close relationships with 100. Approximately one is willing to give new capital to oil and gas investment…This underinvestment coupled with steep shale declines will cause prices to rocket in the next two to three years. I don’t think anyone is prepared for it, but U.S. producers cannot increase capital expenditures: the OPEC+ sword of Damocles still threatens another oil price collapse the instant that large publics announce capital expenditure increases.” That prophecy has come true.Supply Chain WoesThe challenge for producers may be less about growth and more about maintenance. 94% of Dallas Fed Survey Respondents had either a slightly or significantly negative impact from supply-chain issues at their firm. Major concerns about labor, truck drivers, drill pipe and casing supplies, equipment, and sand are hampering the execution of existing drilling plans, to say nothing about expansion.“Supply chain and labor-shortage issues persist. Certain materials are difficult to access, which is hampering our ability to plan, absent a willingness to depart from certain historical practices relating to quality standards.” – Dallas Fed Respondent.Nonetheless, global inventories continue to decline. The U.S. Energy Information Administration’s short-term energy outlook expects production to catch up, but it appears harder to envision that now and nobody exactly knows what that will look like in the U.S. The EIA acknowledged that pricing thresholds at which significantly more rigs are deployed are a key uncertainty in their forecasts. Who knows how much longer upstream companies will continue to tune out the administration or finally try to rev up their growth plans in response to commodity prices? The December 2026 NYMEX futures strip is over $70 right now. There are a lot of potentially profitable wells to be drilled out there at $70 oil. However, management teams know all too well that prices can change quickly. We shall see. Originally appeared on Forbes.com.
Meet the Team: J. David Smith, ASA, CFA
Meet the Team: J. David Smith, ASA, CFA
In each “Meet the Team” segment, we highlight a different professional on our Energy team. This week we highlight David Smith, Senior Vice President of Mercer Capital and a senior member of the Oil and Gas Industry Team. The experience and expertise of our professionals allow us to bring a full suite of valuation, transaction advisory, and litigation support services to our clients. We hope you enjoy getting to know us a bit better.What attracted you to a career in valuation?Admittedly, I really didn’t know what a “valuation analyst” was back in 1992 when I responded to a job posting that was distributed by our local CFA Institute chapter – then known as the Houston Society of Chartered Financial Analysts. I had just completed my MBA and was wanting to get into a position that involved more analysis than my then-current job involved, and the Valuation Analyst job description seemed just right to me. I interviewed, got an offer, accepted the position, and was probably a month into the job before I really started to get a good grasp as to what a Business Appraiser “does” – and realized that I loved the job.Once in the job, what really attracted me to making a career in Business Valuation was the combination of applying economics, accounting, finance, investment analysis, equity analysis, fixed income analysis, money and capital markets, as well as so many other disciplines that I’d studied in my undergraduate and MBA programs. Basically, all the interesting parts of the Chartered Financial Analyst body of knowledge. I have a strong curiosity as to “how things work” or “what makes things tick,” and that curiosity is abundantly satisfied in the analysis that takes place in appraising a business.What does your personal practice consist of?As with many in our profession, my Business Valuation career began as a generalist. We performed appraisals for all four primary “purposes” – tax, transaction, financial reporting, and litigation – and we appraised businesses in many different industries. However, having started my Business Valuation career in Houston, our practice always had a double dose of subject companies in the oil and gas industry. Over time, I also developed an industry concentration in the biotech industry. There is plenty there to satisfy my interest in understanding how things work.Also, over my career, I’ve had the opportunity to work on and gain expertise in performing Fairness Opinions and Solvency Opinions. To this day, those types of projects remain a large part of the projects I’m involved in.What types of oil & gas industry engagements do you work on?The types of O&G industry engagements that I work on vary, although they’re somewhat concentrated in oilfield services (OFS). So, I’ve been part of projects involving mud companies, drilling companies, oilfield waste disposal (saltwater disposal) companies, oilfield equipment (pumps, valves, downhole tools, drilling pipe, seismic equipment, seismic vehicles, drilling equipment, offshore floatation equipment, offshore trenching, ROVs, etc.) manufacturing businesses, and a variety of oilfield services companies. The purpose of those projects is quite varied as well, including federal tax, financial reporting, and transaction purposes.What are the capabilities of Mercer Capital’s Oil & Gas Industry team?Mercer Capital’s Oil & Gas Industry Team capabilities are unusually broad. In addition to our capabilities in the exploration and production (E&P), OFS, midstream and downstream areas, we also have top-notch capabilities in appraising reserves, mineral interests, and other O&G “interests,” which is not nearly as common among our peers. In a sense, this broad O&G industry capability isn’t much of a surprise considering our team has four individuals who’ve practiced business valuation for 20+ years in Texas.What is unique about Mercer Capital’s oil & gas industry services/expertise compared to your competitors?Probably the most unique aspect of our Oil & Gas Industry services is our expertise in appraising reserves, mineral interests, and other O&G “interests” (royalty, working, etc.). While there is any number of business appraisal firms that dabble in appraising these types of assets, unless the appraiser has real expertise, you can often end up with a somewhat questionable valuation. Our Oil & Gas Industry Team is a bit unusual, even among our larger peers, as to the depth of knowledge that we bring to appraising these assets. Knowledge of decline curves and the varying geophysics of different oil and gas basins is not a common body of knowledge in the Business Appraisal community, but we have that knowledge – in abundance.What is the one thing about your job that gets you excited to come to work every day?Early in my career, the exciting part of my job was certainly getting to understand what made the subject company tick. It was, and remains, fascinating to me. As I’ve moved deeper into my career, I’ve also grown to really enjoy many of the broader aspects of running a business valuation practice – such as working with our younger analysts to help them advance in their careers, growing our Houston and Dallas offices, continuing to grow and expand our presence in the Oil & Gas industry, and learning new technical skills as our profession develops more and more sophisticated methodologies for modeling value. Over time, I’ve come to realize that this career in Business Valuation — that I sort of fell into back in the early 1990s — really fits me like a glove. I thoroughly enjoy it and can’t see myself doing anything else.
U.S. LNG Exports (1)
U.S. LNG Exports

Part 2: A Closer Look at Projected U.S. LNG Export Terminal Capacity

In Part 1 of our analysis on U.S. LNG Export Terminal Facilities, we examined trends in the number of LNG export facility applications and approval rates from 2010 through 2021 and examined the projected export capacity relative to the projected export volumes of U.S. LNG from 2022 through 2031.  In Part 2 of our analysis, we take a closer look at the anticipated export capacity proposed to come online over the near and mid-term horizons to better understand the underlying factors that have spurred so many projects, seemingly far in excess of the projected level of LNG exports from the U.S.Excess Export Capacity?As noted in Part 1 of our analysis, the Federal Energy Regulatory Commission (“FERC”) received approximately 145 long-term applications for export facilities seeking to send liquified natural gas to countries both with and without free-trade agreements with the U.S from 2010 to 2021.  Of these applications, 64% were approved, with the vast majority of approvals made from 2011 through 2016.  What was particularly striking was the apparent excess capacity of all the export terminals, from both existing and proposed facilities, relative to the export levels as projected by the U.S. Energy Information Administration (“EIA”), as presented in the following chart: What is not so apparent is that very few projects (ergo, capacity) have firm commitments from buyers to purchase the produced LNG, with even fewer projects having reached an affirmative final investment decision (“FID”).  The nameplate export capacity from all proposed facilities skews the picture a bit, suggesting the U.S. is well able to ship out LNG as fast as natural gas can be extracted, without considering the financial support backing these major capital builds. When stratifying the export capacities of all facilities for which an in-operation date has been put forth, all facilities for which an affirmative FID has been made, and all facilities which are currently in operation, it becomes clear that the capacity of the last group represents the boundary by which the projected LNG export levels anticipated by the EIA over the next 5 years are limited. Further detail regarding the export terminal facility and capacity expansion projects are provided in Appendices A and B at the end of this post (updated and revised from Part 1 of our U.S. LNG analysis). Furthermore, we see that a total export capacity level is slated to be “operational” over the course of 2023 through 2027, while only a portion of that capacity has affirmative FIDs underlying such progress.  In other words, quite a few projects are behind schedule.  Far behind.  For this reason, we will consider “reasonably-expected” LNG export capacity to be based solely on existing capacity and FID-supported capacity.  In order to reasonably include any capacity levels for which an in-operation (but no FID) date is provided, the supporting engineering, procurement, and construction (EPC) activities for those projects would have to be either near completion or well underway.  This simply cannot be assumed to be the case given the lack of clarity regarding the expected timing of any FIDs for these projects, and considering the greatly extended lead times on equipment deliveries due to increasing costs, supply chain constraints, and tight labor markets. The projected capacity utilization over the next ten years is as follows: Click here to expand the image aboveAt face value, the projected annual utilization rates indicate potential tightness in the ability to ship out LNG volumes over the next 6-18 months.  While this possible bottleneck appears – based on current projections – to ease up over the following 2 to 5-year period, other factors should be considered aside from just export terminal capacity.  After all, these facilities can only send out what they receive.Ancillary FactorsOn June 8, the failure of a safety valve caused a pipeline to burst at the Freeport LNG facility, releasing approximately 120,000 cubic feet of LNG.  In addition to posing a “risk to public safety, property or the environment,” U.S. natural gas futures prices fell as the spigot was shut and natural gas slated for export had to remain in storage onshore.  The EIA expects that the shutdown, projected to last for at least 3- to 6-months, will reduce the total U.S. LNG export capacity by 17%.  Widening our focus from the Freeport LNG shutdown, this event reveals the potential risk and impact of total U.S. LNG exports stemming from a significant unforeseen or unplanned shutdown from any of the major (>1.0 Bcfd) 4 export terminals currently in operation.  Until more or larger facilities come online, any major shutdown at a currently-operational export facility may impact the ability of the U.S. to serve oversea markets.Until more or larger facilities come online, any major shutdown at a currently-operational export facility may impact the ability of the U.S. to serve oversea markets.Further upstream, midstream O&G operators, such as Williams (NYSE:WMB), are setting up to help supply natural gas to LNG export terminals.  On June 29, Williams announced its FID to proceed with its Louisiana Energy Gateway (LEG) project, which will gather and help deliver 1.8 Bcfd of natural gas from the Haynesville Shale to Gulf Coast export terminals by way of several existing and future intermediate trunklines.Beyond the physical capital infrastructure required to move gas volumes from the wellhead to the liquefaction terminal, support for LNG export activity remains constrained by political crosswinds as the Biden administration attempts to balance its initiative of supplying U.S. gas to Europe, in order to reduce its reliance on Russian-sourced fuel, while simultaneously addressing a greater public interest in lower domestic energy prices and progressing a platform to mitigate climate change, primarily by reducing the use of fossil fuels.In an attempt to appeal to the various parties with a particular interest in these respective goals, the Biden administration has sent mixed signals with countervailing rhetoric and actions. Increased LNG exports to Europe directly leads to increased domestic energy prices and does little in the way of improving the current trajectory of climate change. Keeping the supply of natural gas onshore helps mitigate high domestic energy prices, but falls short of helping fuel Europe, and still does little to curb climate change. In the pursuit of meaningful change with respect to transitioning away from fossil fuels, neither LNG exports nor promoting greater levels of natural gas production are truly viable policy options. In the pursuit of all goals, no goals are likely to be achieved. It's a stalemate. Given the factors at hand, it remains to be seen just how U.S. LNG export terminal projects develop.  There are clear indications that demand is present, but nebulous political actions, words, and potential regulatory issues still cast a shadow on any perception of a clear path forward.We have assisted many clients with various valuation needs in the upstream oil and gas space for both conventional and unconventional plays in North America and around the world.  Contact a Mercer Capital professional to discuss your needs in confidence and learn more about how we can help you succeed.Appendix A – U.S. LNG Terminals – Existing, Approved Not Yet Built, and ProposedClick here to expand the image aboveAppendix B – U.S. LNG Terminals – Existing, Approved Not Yet Built, and ProposedClick here to expand the image above
EP Third Quarter 2022 Bakken
E&P Third Quarter 2022

Bakken

Bakken // Oil prices declined in the third quarter of 2022, as West Texas Intermediate (WTI) and Brent Crude front-month futures ended the quarter at about $79/bbl and $85/bbl, respectively — a decrease from $108/bbl and $112/bbl, respectively, at the start of the quarter.
The Importance of a Quality of Earnings Study
The Importance of a Quality of Earnings Study
This week, we welcome Jay D. Wilson, Jr., CFA, ASA, CBA to the Energy Valuation Insights blog. Jay is a Senior Vice President at Mercer Capital and a member of the firm’s Financial Institutions and Transaction Advisory teams. The post below originally appeared as part of an ongoing series from Mercer Capital’s Transaction Advisory team regarding the importance of quality of earnings studies in transactions for middle market companies.Acquirers of companies can learn a valuable lesson from the same approach that pro sports teams take in evaluating players. Prior to draft night, teams have events called combines where they put prospective players through tests to more accurately assess their potential. In this scenario, the team is akin to the acquirer or investor and the player is the seller. While a player may have strong statistics in college, this may not translate to their future performance at the next level. So it’s important for the team to dig deeper and analyze thoroughly to reduce the potential for a draft bust and increase the potential for drafting a future all-star.A similar process should take place when acquirers examine acquisition targets. Historical financial statements may provide little insight into the future growth and earnings potential for the underlying company. One way that acquirers can better assess potential targets is through a process similar to a sports combine called a quality of earnings study (QoE).What Is a Quality of Earnings Study?A QoE study typically focuses on the economic earning power of the target. A QoE combines a number of due diligence processes and findings into a single document that can be vitally helpful to a potential acquirer. The QoE can help the acquirer assess the key elements of a target’s valuation: core earning power, growth potential, and risk factors.Ongoing earning power is a key component of valuationOngoing earning power is a key component of valuation as it represents an estimate of sustainable earnings and a base from which long-term growth can be expected. This estimate of earning power typically considers an assessment of the quality of the company’s historical and projected future earnings. In addition to assessing the quality of the earnings, buyers should also consider the relative riskiness, growth potential, and potential volatility of those earnings as well as potential pro-forma synergies that the target may bring in an acquisition.Analysis performed in a QoE study can include the following:Profitability Procedures. Investigating historical performance for impact on prospective cash flows. Historical EBITDA analysis can include certain types of adjustments such as: (1) Management compensation add-backs; (2) Non-recurring items; (3) Pro-forma adjustments/synergies.Customer Analysis. Investigating revenue relationships and agreements to understand the impact on prospective cash flows. Procedures include: (1) Identifying significant customer relationships; (2) Gross margin analysis; and (3) Lifing analysis.Business and Pricing Analysis. Investigating the target entities positioning in the market and understanding the competitive advantages from a product and operations perspective. This involves: (1) Interviews with key members of management; (2) Financial analysis and benchmarking; (3) Industry analysis; (4) Fair market value assessments; and (5) Structuring. The prior areas noted are broad and may include a wide array of sub-areas to investigate as part of the QoE study. Sub-areas can include:Workforce / employee analysisA/R and A/P analysisCustomer AnalysisIntangible asset analysisA/R aging and inventory analysisLocation analysisBilling and collection policiesSegment analysisProof of cash and revenue analysisMargin and expense analysisCapital structure analysisWorking capital analysis For high growth companies in certain industries such as technology, where valuation is highly dependent upon forecast projections, it may also be necessary to analyze other specific areas such as:The unit economics of the target. For example, a buyer may want a more detailed estimate or analysis of the target’s key performance indicators such as cost of acquiring customers (CAC), lifetime value of new customers (LTV), churn rates, magic number, and annual recurring revenue/profit. These unit economics provide a foundation from which to forecast and/or test the reasonableness of projections.A commercial analysis that examines the competitive environment, go-to-market strategy, and existing customers' perception of the company and its products.The QoE study should be customized and tailored to the buyer’s specific concerns as well as the target’s unique situationsThe QoE study should be customized and tailored to the buyer’s specific concerns as well as the target’s unique situations. It is also paramount for the buyer’s team to utilize the QoE study to keep the due diligence process focused, efficient, and pertinent to their concerns. For sellers, a primary benefit of a QoE can be to help them illustrate their future potential and garner more interest from potential acquirers.Leveraging our valuation and advisory experience, our quality of earnings analyses identify and assess the cash flow, growth, and risk factors that impact value. By providing our clients with a fresh and independent perspective on the quality, stability, and predictability of future cash flows of a potential target, we help them to increase the likelihood of a successful transaction, similar to those teams and players that are prepared for draft night success.Mercer Capital’s focused approach to traditional quality of earnings analysis generates insights that matter to potential buyers and sellers and reach out to us to discuss your needs in confidence.
Permian Production Remains Strong
Permian Production Remains Strong
The economics of Oil & Gas production vary by region.  Mercer Capital focuses on trends in the Eagle Ford, Permian, Bakken,  and Marcellus and Utica plays. The cost of producing oil and gas depends on the geological makeup of the reserve, depth of reserve, and cost to transport the raw crude to market.  We can observe different costs in different regions depending on these factors.  In this post, we take a closer look at the Permian.Production and Activity LevelsEstimated Permian production (on barrels of oil equivalent, or “boe,” basis) increased approximately 11.4% year-over-year through June.  This is notably greater than the production increases seen in the Eagle Ford, Bakken and Appalachia (8.0%, 2.2% and 1.9%, respectively). There were 345 rigs in the Permian as of June 10, up 49% from June 4, 2021.  The Bakken, Eagle Ford, and Appalachia rig counts were up 131%, 106%, and 34%, respectively, over the same period. In terms of production growth, the Permian has far exceeded the other basins, and Permian production is expected to continue increasing over the next several months based on anticipated increases in the rig count and new-well production per rig. Commodity Prices Continue to RiseOil prices generally rose through the second half of 2021, although they started to decline in mid-Q4.  The shale revolution had largely put geopolitics in the back seat as the key driver of commodity prices.  However, geopolitics once again came front and center as Russia launched its invasion of Ukraine in late February.  Western nations responded with a series of economic sanctions against Russia.  Although the sanctions generally included carve-outs for energy exports, issues with financing and insurance, and the exit of Western oil companies and oilfield service providers from Russia resulted in a substantial decline in oil exports from the country.  The exclusion of oil from Russia, the third-largest producer of petroleum and other liquids in 2020 according to the U.S. Energy Information Administration, from global markets led to a high degree of volatility in oil prices.  WTI front-month futures prices began the latest quarter at ~$99/bbl and were floating around $121/bbl as of mid-June.  With no indications of any near-term resolution of the Russian-Ukraine war, and a continued outlook of relatively flat production in the U.S., the upward trajectory of global energy prices has no foreseeable inflection point at the moment. Natural gas prices fluctuated over the past year, albeit with slightly less volatility than oil prices, and have exhibited the same upward trend over the past quarter.  Natural gas is becoming more globalized as Europe grapples with replacing imports of Russian gas.  In late March, President Biden pledged to boost LNG exports to Europe, which may re-invigorate the advancement of U.S. LNG export terminal projects. Financial PerformanceThe Permian public comp group saw moderately positive stock price performance over the past year (through June 10).  The prices of Diamondback Energy and Laredo Petroleum rose 79% and 78%, respectively, and more than the broader E&P sector (as proxied by XOP, which rose 68% during the same period).  Pioneer Natural Resources’ stock price rose 66% over the period, and Callon Petroleum rose a relatively tepid 24%.Survey Says Eagle Ford Wells Among Most EconomicAccording to participants of the First Quarter 2022 Dallas Fed Energy Survey (the latest available as of mid-June), wells in the core plays of the Permian are positioned as some of the most economical in the nation. Survey respondents indicated that the average WTI price needed to break even on existing wells in the primary Permian plays was $28/bbl to $29/bbl.  This exceeds the average breakeven in the Eagle Ford ($23/bbl) but is still lower than other parts of the U.S. (over $30/bbl).  The average breakeven price for new development in the Permian is in the middle of the pack at $50/bbl to $51/bbl, greater than the Eagle Ford’s breakeven ($48/bbl), but notably lower than in other parts of the country ($60/bbl to $69/bbl). ConclusionProduction growth in the Permian continued to exceed growth in the Eagle Ford, Appalachia and Bakken over the past year as the basin remains one of the most economical regions in U.S. energy production.  With the surge in commodity prices over the past quarter, it might have been expected that producers would start bringing more rigs online, leading to more production growth than what we saw.  However, as upstream companies have signaled, it may not be realistic to expect such increased deployment of capital from public operators in the near future, though private operators may very well move to take advantage of the higher price environment.  With greater emphasis on returning cash to shareholders, continued levels of relatively low investment in growth capital may be expected.  However, its significantly large contribution to total energy production continues to make the Permian a steady source of growth for overall U.S. oil and gas production.We have assisted many clients with various valuation needs in the upstream oil and gas space for both conventional and unconventional plays in North America, and around the world.  Contact a Mercer Capital professional to discuss your needs in confidence and learn more about how we can help you succeed.
M&A in the Permian: Acquisitions Slow as Valuations Grow
M&A in the Permian: Acquisitions Slow as Valuations Grow
Transaction activity in the Permian Basin cooled off this past year, with the transaction count decreasing to 21 deals over the past 12 months, a decline of 6 transactions, or 22%, from the 27 deals that occurred over the prior 12-month period. This level is in line with the 22 transactions that occurred in the 12-month period ended mid-June 2020. It is difficult to interpret the significance with any certainty. On one hand, it could indicate increased trepidation regarding production prospects in the basin. On the other hand, it could simply be a sign that regional E&P operators have started to "right-size" their inventories in the West Texas and Southeast New Mexico basin. Based on the evolving economics of the region, as we will examine further below, the latter case may be closer to the truth.A table detailing E&P transaction activity in the Permian over the last twelve months is shown below. Relative to 2020-2021, the median deal size nearly was $387 million, just 4% lower than the median deal size of $405 million in the prior 12-month period. However, the median acreage purchased over the past year was 21,000 net acres, just over 42% lower than the 36,250 acres among the deals in the previous year. Given the concurrent decrease in acquired acreage and relatively unchanged median transaction price, the median price per net acre was up 16% period-over-period. Looking at acquired production, the median production among transactions over the past year was 5,500 barrel-oil-equivalent per day ("Boepd"), a 39% decrease from the 8,950 Boepd metric from the prior year.Given the relatively unchanged level in the median transaction value in conjunction with a lower median production level, the median transaction value per Boepd, unsurprisingly, jumped 54% from $31,886 in the prior 12-month period to $49,143 in the latest 12-month period. This willingness to pay over 50% more per acre and/or per Boepd suggests that these targets' underlying economics have been, and remain, supportive. However, the marginal costs of these acquisitions may be approaching the perceived marginal returns projected for these properties, as evidenced by the decrease in the transaction count relative to last year.Click here to expand the image above. The approach to the marginal "equilibrium" appears to have been a pretty short runway to land on. Of the 21 transactions completed, 14 occurred from June to December, with the remaining 7 occurring from January 2022 to the present. One metric we analyzed, based on the deal value per production (annualized) per acre, indicates a sharp decline in the "bang for the buck" exhibited by the transactions before and after year-end 2021. As presented below, the median cost per production acre for the 14 transactions from June to December 2021 was $1.072. In contrast, the median metric for the seven transactions from January to June 2022 was $10.762, indicating a 10.0x increase in the cost per production acre.A deeper dive into the details of each transaction would be needed to discern any common causes for this movement, but this could indicate a shift in focus from proven reserves towards unproven acreages. In other words, acquirers may be putting increased value on the potential optionality for greater-but-yet-proven production presented by these targets.Click here to expand the image above.Despite the upward trend in energy prices over the past year, what we are seeing is a likely slowdown in M&A activity in what is generally considered to be the most economical oil and gas basin in the U.S.  If the Permian is a bellwether of U.S. production in general, are we likely to see a slowdown in M&A activity in other basins soon? I would venture to say "yes."Earthstone Energy Acquires Bighorn's Permian PortfolioIn late January 2022, Earthstone Energy announced its agreement with Bighorn Permian Resources to acquire its Midland Basins assets for a total consideration of $639 million in cash and 5.7 million shares of Earthstone's Class A common stock (the "Bighorn Acquisition"). The effective date of the Bighorn Acquisition was January 1, 2022, and the deal closed on April 18, 2022. The Bighorn Acquisition included 110,600 net acres (98% operated, 93% WI, 99% HBP), primarily in Reagan and Irion counties, with an estimated production of 42,400 Boepd (57% liquids, 25% oil), and proved reserves of 106 MMBoe (20% oil, 34% NGL, 46% natural gas).Robert Anderson, President, and CEO of Earthstone Energy, commented, "The transformation of Earthstone continues with the announcement of the significant and highly-accretive Bighorn Acquisition. Combining the Bighorn Acquisition with the four acquisitions completed in 2021 and the pending Chisholm Acquisition, we will have more than quadrupled our daily production rate, greatly expanded our Permian Basin acreage footprint and increased our Free Cash Flow generating capacity by many multiples since year-end 2020. The proximity of the Bighorn assets to existing Earthstone operations positions us to create further value by applying our proven operating approach to these assets, primarily in the form of reducing operating costs. The addition of the high cash flow producing assets from Bighorn to the strong drilling inventory of Earthstone, including the Chisholm Acquisition, furthers Earthstone's transformation into a larger scaled, low-cost producer with lower reinvestment in order to maintain combined production levels."Earthstone Energy Acquires Midland Basin Assets from Foreland InvestmentsIn early November 2021, Earthstone Energy announced the completion of its acquisition of privately held operating assets located in the Midland Basin from Foreland Investments LP ("Foreland") and from BCC-Foreland LLC, which held well-bore interests in certain of the producing wells operated by Foreland (collectively, the "Foreland Acquisition"). The aggregate purchase price of the Foreland Acquisition was $73.2 million at signing, consisting of $49.2 million in cash and 2.6 million shares of Earthstone's Class A common stock valued at $24.0 million based on a closing share price of $9.20 on September 30, 2021. The Foreland Acquisition included approximately 10,000 net acres with an estimated production of 4,400 Boepd (26% oil, 52% liquids), and PDP reserves of approximately 13.3 MMBoe (11% oil, 31% NGL, 58% natural gas).Mr. Robert Anderson, President and CEO of Earthstone, commented, "This transaction will be our fourth acquisition this year as we continue to advance our consolidation strategy and enhance our Midland Basin footprint with additional scale. The acquisition of these low operating cost, high margin, producing assets at an attractive valuation is a nice addition to our production and cash flow base. The Bolt-On Acquisition also includes approximately ~10,000 net acres (100% operated; 67% held by production) in Irion County. We expect to benefit from additional operating synergies when production operations are combined with other assets in the area. As we have done in prior acquisitions, we look forward to applying our operating approach to these assets in order to reduce costs and maximize production and cash flows."ConclusionM&A transaction activity in the Permian declined at an increasing rate over the past year, with two-thirds of the 21 transactions occurring in 2021, and the remaining third transpiring in the YTD period ended in mid-June. But the overall upward trend in deal cost per unit (be it per-production level, acreage, or production-acre) indicates buyers' willingness to pay more to achieve their desired asset base. The overall story is one of the companies right-sizing their presence in the basin.We have assisted many clients with various valuation needs in the oil and gas industry in North America and globally. In addition to our corporate valuation services, Mercer Capital provides investment banking and transaction advisory services to a broad range of public and private companies and financial institutions. We have relevant experience working with companies in the oil and gas space and can leverage our historical valuation and investment banking experience to help you navigate a critical transaction, providing timely, accurate and reliable results. Contact a Mercer Capital professional to discuss your needs in confidence.
Mineral Aggregator Valuation Multiples Study Released (1)
Mineral Aggregator Valuation Multiples Study Released

With Market Data as of May 12, 2022

Mercer Capital has its finger on the pulse of the minerals market.  An important trend has been the rise of mineral aggregators, which have largely supplanted the trusts as the primary method of publicly traded minerals ownership.Due to a variety of corporate structures (including master limited partnerships and Up-Cs) and complex capital structures (including preferred equity and non-traded common units), mineral aggregator enterprise values pulled from databases are often missing meaningful components of value, leading to skewed valuation multiples.Mercer Capital has thoughtfully analyzed the corporate and capital structures of the publicly traded mineral aggregators to derive meaningful indications of enterprise value.  We have also calculated valuation multiples based on a variety of metrics, including distributions and reserves, as well as earnings and production on both a historical and forward-looking basis.Mineral Aggregator Valuation Multiples StudyMarket Data as of May 12, 2022Download Study
Themes from Q1 Earnings Calls
Themes from Q1 Earnings Calls

Part 2: Oilfield Service Companies

In a prior post — Themes from Q4 2021 Earnings Calls, Part 3: OFS — we noted common themes from OFS companies’ Q4 earnings calls, including macro headwinds, industry consolidation through M&A activity, and ESG activity.In Themes from Q1 2022 Earnings Calls, Part 1: Upstream, we explored key topics among the upstream segment of the oil & gas industry through the earnings calls of E&P operators and mineral aggregators.  These themes included:The future role of U.S. production in the European market as European nations plan to phase out Russian oil & gas;Confidence of continued favorable pricing exhibited through shorter-term deals and unhedged positions;Increasing completion rates in Q1, with expectations of further growth in completions beyond Q1. This week we focus on the key takeaways from the OFS Q1 2022 earnings calls.Short-Cycle Projects to Bolster Near-Term Production Are Those Most Sought AfterOFS companies have highlighted that — as E&P companies remain focused on returning near-term profits to shareholders — their investment efforts are sighted on capitalizing on short-cycle developments, rather than longer-term developments.  Amid ESG headwinds and supply chain disruptions, OFS companies have been more commonly tasked with supporting active rigs, supplying marginal equipment, and other services necessary for E&P companies to capitalize on this commodity upcycle.“In addition, I expect an important change in our customers behavior and priorities will provide structural support to oil prices throughout this upcycle. I believe supply dynamics have fundamentally changed due to investor return requirements, public ESG commitments and regulatory pressure, which make it more difficult for operators to commit to long-cycle hydrocarbon investments and instead drive investment flexibility through short-cycle barrels.” – Jeff Miller, Chairman, President & CEO, Halliburton“The shorter cycle [is] catching up, improving the situation around our very, very constrained supply chain challenges [and] meeting sort of the near-term demand of supporting rigs, frac fleets and stimulation equipment…both land and offshore, I think that's kind of the biggest near-term needle mover for NOV.” – Clay Williams, Chairman, President & CEO, NOV“There have been episodic supply chain disruptions with our customers, where we've been on location waiting for another service company to arrive or complete a job, and that's becoming, unfortunately, more frequent. I think that you're seeing a lot of marginal equipment being deployed and you're going to see a lot more marginal equipment being deployed as we pass through the 700 level in the U.S. rig count on the way to maybe just under 800 by year-end.” – Scott Bender, President, CEO & Director, Cactus  Shifting Priority to Margin ExpansionThough the demand for oilfield services has particularly revolved around short-cycle projects to support production, executives note that total demand for these products and services has still increased across the board.  Amid a plague of supply constraints and a tight market for their products and services, OFS companies have shifted their focus towards increasing margins, rather than gaining market share.  Despite a surge in demand, margins face pushback as inflation and rising wages erode the pricing power of OFS companies.“It's probably fair to say that we're entering into a period of potential meaningful margin expansion. And I think that volume expansion in terms of shipments is going to be constrained. And unlike some of our peers, we have the capacity to manage increased volumes. So we could potentially benefit from [this].” – Scott Bender, President, CEO & Director, Cactus“We are seeing increasing demand across all services. And I'd say, particularly on the well servicing side just because for a lot of operators, some of their cheapest incremental barrels are workover barrels. So we are seeing that demand. As Brandon indicated, we're now running 157 rigs and we would expect through the year that, that number starts to kind of trend up.We are being pretty diligent in maintaining margins, but we do think we can deploy additional rigs and maintain margins.” – Stuart Bodden, President & CEO, Ranger Energy ServicesPrivate Companies Have an Increasing Role Within the Customer BaseA recurring theme, as mentioned in previous blog posts, is how private companies have been more active than public companies in ramping up production.  As this relates to OFS, Q1 earnings calls have acknowledged that relationships with private operators are of greater importance than in the past.  This shift comes in light of capital restraint from public operators.  While perspectives differ about the future activity plans of the public E&P companies, OFS company executives commonly recognized increased activity from private operators, due to growth, consolidation, and greater capital freedom.“Our penetration of privates is undeniable. It's going to increase this year because I think the privates are becoming much more sophisticated. They're consolidating. And as they become more sophisticated and larger, then our product becomes far more attractive to them. They're not nearly restrained from a capital perspective. And we're doing our level best to call on those customers with whom it makes economic sense for us to pursue that business.” – Scott Bender, President, CEO & Director, Cactus “Today, as I look at a combination of customer activity and inflation, my outlook has improved, and I now expect North America spending to increase by over 35% this year. With respect to activity, over 60% of the US land rig count sits with private companies and they keep growing, while public E&Ps remain committed to their activity plans. Activity and demand for our services are increasing, both internationally and in North America.” – Jeff Miller, Chairman, President & CEO, Halliburton “As far as mix, I'd say it's twofold. We referred on the call that we are working for larger group of operators and I'd say the preponderance of that increase is probably in the private side ... so I think we will see growth in both sides, but two different dynamics driving this.” – Kyle Ramachandran, CFO & President, Solaris Oilfield Infrastructure Mercer Capital has its finger on the pulse of the minerals market.  As the oil and gas industry evolves through these pivotal times, we take a holistic perspective to bring you thoughtful analysis and commentary regarding the full hydrocarbon stream, including the mineral aggregators with working and royalty interests in the underlying production.  For more targeted energy sector analysis to meet your valuation needs, please contact the Mercer Capital Oil & Gas Team for further assistance.
Have Reserve Reports Been Relegated To Investor Footnotes?
Have Reserve Reports Been Relegated To Investor Footnotes?
In the early part of my career, I vividly recall first learning about what was then arguably the most important document that an upstream company produced – the reserve report. Full of pertinent information, the reserve report struck at the heart of an oil and gas company’s economic relevance.The now discontinued Oil and Gas Financial Journal once described reserves as “a measurable value of a company’s worth and a basic measure of its life span.” Thus, understanding the fair market value of a company’s Proven Developed Producing (PDP), Proven Developed Non-Producing (PDNP), and Proven Undeveloped (PUD) reserves was key to understanding the fair market value of the company. Investors and analysts looked to the reserve report before reviewing the financials sometimes.Not these days.Consigned to back pages, footnotes, and appendices, the reserve report’s relevance has waned. Current investor presentations of four Permian-focused oil and gas companies (Pioneer, Centennial, Laredo, and Callon) exemplify this. What I found pertaining to reserve reports continues a years-long trend and was a far cry from what I saw for most of my career. Only one, Laredo, spent any meaningful discourse on their reserve report over the course of a few pages in their investor presentation. They were the smallest company of the group. As for the others: Centennial and Callon spent one whopping page each on their reserves; and the most valuable of them all, Pioneer, showed a single curt reserve figure just in front of their footnotes.Investor presentations are notable in that they represent a company’s current communication to investors, aspiring to highlight some of the most important information investors want to know. Under that argument, management believes investors don’t care to know much about reserve reports.For decades, an oil and gas company (all else being equal) often expected to have an enterprise value somewhat close to their PV-10 calculations in their annual reserve report.Not these days.The table below shows that current Permian valuations don’t track very close to their PV-10 figures at all. Remember, SEC pricing utilized in these PV-10 calculations below were $66.56 per barrel and $3.60 per Mcf. The enterprise values below reflect today’s prices of over $105 per barrel and over $7.50 per Mcf so price volatility is also a big factor considering that reserve reports reflect a snapshot in time, just like values. We also looked at the enterprise value relative to developed and oil reserve mixes. No clear pattern emerged there either. It begs the question: if Pioneer is lapping the others regarding this time-tested metric, why are they currently burying it next to the fine print? As of May 11, 2022 Source: S&P CAPIQ The answer is because investors are focused on other things – namely the types of themes that show up in the big bold print of these investor presentations: returns to shareholders, free cash flow and deleveraging. Looking through that lens, we noticed a clearer picture of why Pioneer is valued so highly. Let’s quickly analyze these other metrics in the table below: As of May 11, 2022 Source: S&P CAPIQ Immediately Pioneer’s dividend yield and Debt/EBITDA ratio stand out on this table. Pioneer is also the only company on this list with an investment grade credit rating. This appears to be what investors notice. It can’t be understated that the return of capital theme is emphasized for the first ten pages of Pioneer’s investor presentation. Laredo, Callon and Centennial all centered their presentations on these themes too, sans the dividend yield that they don’t have. Valuations appear to be driven by: (i) near term cash flows, (ii) returns on capital, (iii) well margins, and (iv) deleveraging. There are other ancillary things that analysts and management teams additionally reference frequently such as: held by production (margin related metric), cost per lateral foot drilled (margin related metric), and inventory (near term cash flow related metric). Reserve reports speak into some of those things, but certainly not all and not comprehensively. Stock prices suggest that investors are less concerned about having 15 years of reserves life, or what a company’s probable and possible reserves could be, but more about how profitable next years’ worth of wells will be. It’s also clear that investors do not want management teams beholden to their bankers for capital but prize the ability to operate more self-sufficiently going forward. It is not that reserve reports are obsolete. They have valuable information, and the core components of value are still found within the walls of a detailed reserve analysis. Reserve reports give investors an idea of the possible production management can reasonably be sure of getting. That’s critically important. It also shows investors what production profiles look like for a company’s current (and perhaps future) wells. It also endeavors to measure near term well drilling and production costs. Bankers still utilize reserve reports as an input to lending decisions (although there has not been much reserve lending happening lately with the deleveraging trend). Most of the elements I touched on above (near term cash flows, returns on capital, well margins) can be dug out of the details of a reserve report. What’s different now is that how production, costs, risk, and growth are analyzed have gotten more nuanced, detailed, and challenging. More layered analytical work needs be done in an increasingly complex, regulated, and integrated global oil and gas market. So, can an investor reliably breeze through a reserve report, look at proven reserves, an SEC pricing deck, and a 10% standardized discount rate to come up with the fair market value of an oil and gas company? Not these days. Originally appeared on Forbes.com.
Themes from Q1 2022 Earnings Calls
Themes from Q1 2022 Earnings Calls

Part 1: Upstream

In Part 1 (E&P Operators) and Part 2 (Mineral Aggregators) reviews of Q4 Earnings Calls, prevalent themes among the E&P Operator calls included cost inflation, a shifting focus towards liquids, and policy headwinds towards the Oil & Gas industry.  Among the mineral aggregators, common themes were capital discipline, flat production growth, and the strength in the position of aggregators amid the highly inflationary environment.This week, we take a holistic upstream perspective on the themes of both the E&P operator and mineral aggregator earnings calls for Q1.The Future Role of U.S. Production in the European MarketRussia invaded Ukraine on February 24, 2022.  Global markets blinked, and commodity futures skyrocketed.  In the weeks following the invasion, European nations discussed plans to phase out sourcing energy from Russia. With OPEC holding firm on its production plans, attention turned towards the U.S. — the world’s largest hydrocarbon producer and a vocal supporter of sanctions towards Russia.  Upstream Oil & Gas companies recognize that their role in supplying European energy markets, and the global market generally will grow.“As the war in Ukraine and the resulting governmental sanctions continue, Russia's oil production is expected to be impacted by shut-ins, natural declines, storage limitations and lower exports, creating a global shortage of oil.  Over the next few years, we will need to make up for this lost production, and we believe that the U.S. oil and gas industry is best suited to provide the low-cost environmentally-friendly barrels needed to ensure global energy supply.  However, today, we are operating in a constrained environment with inflationary pressures continuing to increase across all facets of our business.  Also labor and materials shortages are now present across the supply chain…[an] increase in activity now would result in capital efficiency degradation that would not meaningfully contribute to fixing the global supply and demand imbalance in the oil market today.” – Travis Stice, Chairman and CEO, Diamondback Energy “The reality is that energy markets were already tightening from supply and demand fundamentals before this Russian action, and the risk premium now embedded in commodities, including oil and gas has returned with a vengeance.  Even in the unlikely event of a near-term resolution to this crisis, the die has been cast and actions, particularly by European countries are already underway to move away from Russian oil and gas and secure more reliable supply from the Middle East and the U.S.  It has underscored the need for an orderly energy transition that includes oil and gas as part of all of the above strategy, and has recalibrated global views as to the current and ongoing role of U.S. oil and gas in the world economy.” – Lee Tillman, Chairman, President and CEO, Marathon Oil“On the supply side, the shift towards maintenance capital plans and supply chain constraints led to moderated global supply growth.  Then during the first quarter of 2022, this bullish fundamental backdrop was further strengthened by the geopolitical events in Europe.  Unlike prior commodity price spikes, these events had a large impact on the futures curve, where we saw the natural gas strip move up 45% throughout the curve all the way to calendar year 2026.  As Europe looks to strengthen its energy security, it has become clear that there will be a significant call on U.S. shale gas in the coming decades.” – Paul Rady, Chairman, President and CEO, Antero Resources“Recent world events have highlighted the global strategic importance of U.S. gas reserves, and we believe the Haynesville shale is the best position play to benefit from continued growth in LNG export volumes over time.” – Tom Carter, Chairman and CEO, Black Stone MineralsConfidence of Continued Favorable PricingIn Part 1 (E&P Operators) of the Q4 earnings call themes, we noted upstream companies’ strong desire to reap the full benefits of the pricing environment.  Executives focused on shorter-term deals, unhedged positions, and a more opportunistic approach when it came to derivatives contracts.  With fewer hedges in place or shorter-term contracts, operators continue to pursue maximizing their upside from continued price appreciation or a prolonged favorable pricing environment.“We’re happy where we are right now on shorter-term deals, whether it’s selling on the day or on the month.  We’re not interested in longer-term supply deals unless we receive significantly higher premiums.  There is too much optionality today to get in prematurely.  We are virtually unhedged on all commodities in 2023.  This attribute will allow us to capture the upside to growing LNG and LPG export demand.” – Paul Rady, Chairman, President and CEO, Antero Resources“As we look to 2023, we have positioned the portfolio with a good base layer of hedges.  With strength in the oil and natural gas, we’ll opportunistically add 2023 hedges over the remainder of this year.  However, we expect to hedge less volumes, or said another way, a lower percentage of production than we have historically.” – Kevin Haggard, Senior Vice President and CFO, Callon Petroleum“If oil prices were to average $60 for the remainder of the year, Pioneer's shareholders would receive approximately $17 in dividends per share.  At $120, approximately $31.  Shareholders have significant upside on higher oil prices as we have zero 2022 oil hedges.” – Scott Sheffield, CEO and Director, Pioneer Natural Resources“While the Permian led all of the basins in terms of growth in rig count, we believe strong natural gas prices will compel improved activity in the Haynesville, Marcellus and Mid-Con as we continue through 2022.” – Bob Ravnaas, Chairman and CFO, Kimbell Royalty PartnersCompletions Trending UpUpstream operators commonly noted that their Q1 completion rates increased, with expectations that completions will continue to increase throughout 2022.  This is an encouraging sign for aggregate production.“[Regarding] completions, our field team continues to see really good improvements and they’ve increased their overall completed lateral per foot per day by 10% compared to 2021.” – Jeff Leitzell, Executive Vice President-Exploration & Production, EOG Resources“As you mentioned, 11-wells went online earlier, and they are performing above the type curves.  We still have six more to turn online, making 23 Eagle Ford for this quarter.  And we have even more wells set to come online in the Eagle Ford through third quarter.  It is very early, but we’re very excited about the wells coming online earlier and at higher results.” – Molly Smith, Vice President of Drilling and Completions, Murphy Oil“The decrease in oil volumes was primarily a result of lower suspended revenue volumes received in this quarter as compared to last quarter.  Our staff successfully worked with producers in the second half of last year to release suspended production volumes across our mineral position…  Given the temporary nature of these items and combined with the generally positive industry environment and the ramp up in activity, we expect to see the Haynesville and Austin formation shock through our organic growth programs.  We expect that growth trajectory to resume throughout the year.” – Jeff Wood, President and CFO, Black Stone Minerals“Strong commodity prices during the quarter translated into increased activity on our acreage as evidenced by the 20% increase in the rig count actively drilling on our acreage at no cost to us.  In addition, line of sight inventory from our major properties increased 6% sequentially to 5.03 net DUCs and permits.  This is notable since we only need approximately 4.5 net wells completed each year to keep production flat.” – Bob Ravnaas, Chairman and CFO, Kimbell Royalty Partners “Looking ahead, our net activity well inventory, which represents the combination of our drilled but uncompleted locations, or DUCS, in our permits was 11.7 net locations at the end of the first quarter, our net DUCs and inventory at the end of the first quarter stayed roughly flat versus the fourth quarter, despite our extremely strong aforementioned DUC conversions.  We anticipate that PDC, Chevron, Pioneer, Oxy, and Diamondback will convert the majority of our DUC inventory.” – Rob Roosa, CEO, Brigham MineralsConclusionMercer Capital has its finger on the pulse of the minerals market.  As the oil and gas industry evolves through these pivotal times, we take a holistic perspective to bring you thoughtful analysis and commentary regarding the full hydrocarbon stream, including the E&P operators and mineral aggregators in the upstream space.  For more targeted energy sector analysis to meet your valuation needs, please contact a Mercer Capital Oil & Gas Team member for further assistance.
U.S. LNG Exports
U.S. LNG Exports

Part I: The Current State of U.S. LNG Export Terminal Facilities and Projected Export Capacity

Up To This Point…From 2010 to 2021, the Federal Energy Regulatory Commission (“FERC”) received approximately145 long-term applications for export facilities seeking to export liquified natural gas to countries both with and without free-trade agreements (“FTA”) with the U.S.  Of these 145 applications, 93 (or 64%) have been approved, with approximately 80% of the approved applications coming from submissions made from 2011 through 2016.Up to this point, we have seen applications either submitted or reasonably anticipated to be submitted for approximately 25 export facilities. To be clear, a significant portion of these applications pertain to capacity expansions to either existing or proposed export terminals where the initial application for a proposed facility was approved, and another application for expanded output volume was later submitted prior to the actual construction of the facility.  Additionally, there are separate applications for exporting to FTA and non-FTA countries; if a facility seeks to export to both types, there is one application for the FTA markets and one for the non-FTA markets.  In other words, 145 applications received do not directly translate to 145 LNG export facilities. The number of submitted applications dropped in 2017 and has since remained far below the annual numbers seen in 2011 through 2016.  This was primarily caused by the massive decline in LNG export prices starting in Q1 of 2015.  The subsequent decline in the applications submitted, which was not very evident until 2016, was not as steep.  This was most likely due to project sponsors either hedging against sustained lowered natural gas export prices, or playing into the sunk cost fallacy of submitting an application after already having expended the time and resources necessary to prepare it in the first place. Further expanding on the element of LNG export prices, the following chart presents the monthly prices of LNG exports from January 2005 through January 2022, with annual 2010-2016 average prices also presented over the time period. In light of the clear increase in LNG export prices during mid to late 2021, it may be slightly surprising that the number of applications in 2021 and in 2022 (so far) has not picked back up.  However, a prior Energy Valuation Insights post noted that there were massive pullbacks in 2020 and 2021 capital expenditures throughout the oil and gas sector.  Real growth projections for projected capital outlays in 2022 are modest as upstream operators remain focused on returning capital to shareholders, paired with maintenance level capital expenditures that will keep overall oil and gas production relatively flat or modestly higher.  In addition, there are a number of outstanding final investment decisions (“FIDs”) to be made regarding the construction start for proposed facilities that have already received FERC approval. There are drilled but uncompleted (“DUC”) wells in the field  – wells that are queued up to be put into action.  Similarly, one may think of FERC-approved export terminal projects with outstanding FIDs as, “ready to roll”, relatively speaking, as compared to LNG export projects that still need regulatory approval. Approved LNG export terminal projects loom over potential new projects that may or would otherwise pursue FERC approval.  In essence, the U.S. LNG export terminal market is relatively saturated with projects that could be started and put into operation fairly quickly as compared to new entrants still in the pre-application or pre-approval stages of project development.  The development of already-approved projects would increase the capacity to supply global demand for U.S. LNG exports.  This would likely tank the underlying economics supporting any new (yet-to-be-approved and pre-FID) projects; and not by virtue of poor planning on the part of project sponsors at the micro level or weak energy prices at the macro level, but rather due to the total timing of the approval process, an affirmative FID, and the construction and commissioning phases of project development.  They would be showing up to register for the race right as everyone else was already taking off from the starting line. On that front, it’s worth taking a look at existing export capacity, total FERC-approved export capacity, and how that capacity may satisfy the demand for U.S. LNG exports. The Current State of AffairsHistorically, the U.S. has exported LNG to European markets, East Asian markets, and other markets, including within South America, the Caribbean, and within the past six years to parts of the Middle East, including Egypt, Israel, Jordan, and even Kuwait and the U.A.E.  As presented in the following two charts, growth in export volumes to the Asian and European markets has far outpaced export volumes to the other markets. On a forward looking basis, projections of global natural trade by the EIA in its International Energy Outlook 2021 report indicate a natural gas deficit may be the norm over the next 30 years.  (Negative values represent net exporters, with positive values representing net importers.) As it stands, total U.S. LNG export capacity is projected to grow approximately 13% from 14.0 Bcf/d at year-end 2021 to 15.9 Bcf/d by year-end 2022.  LNG export volume at year-end 2021 was 9.8 Bcf/d (or 70% of capacity) and is projected to increase 17% to 11.5 Bcf/d by year-end 2022 (or 72% of projected export capacity).  Regarding the export terminals themselves, eight were operational at year-end 2021, with one additional facility (Venture Global Calcasieu Pass) expected to be operational and delivering cargo by year-end 2022.Beyond 2022, export volume capacity is anticipated to increase rather sharply, reaching 38.5 Bcf/d (nearly 145% from year-end 2022) in 2027, indicating a compound annual growth rate of approximately 19% in export volume capacity over the prospective five-year period.  These projected volumes only consider the 18 export facilities for which the project sponsors have provided an anticipated date of the projects’ operational status; they do not consider the incremental volumes stemming from a new terminals or capacity expansion projects for which it is unclear as to when the additional export capacity might come online.  Clearly, the export capacity of U.S. LNG is primed to take off.  But take off to where?As we saw in the chart above concerning global natural gas trade projections, with the U.S. presented clearly as a net exporter of natural gas, export volumes are anticipated to rise quickly to just over 18 Bcf/d by 2030, then slowly tick up annually, topping out at around 20 Bcf/d in 2045-2050.To put this in better context, the following chart summarizes the projected export capacity by region and year of anticipated operational status, as well as the projected annual LNG export volumes through 2031. Further detail regarding the export terminal facility and capacity expansion projects are provided in Appendices A and B. Based on the eye-ball test, it’s pretty clear that projected export capacity could far outstrip demand for U.S. LNG, based on the EIA’s export projections (as of early 2021), only if all that capacity were to come online.  Free Market Economics 101 theory would indicate, rather decisively, that such excessive capacity would clearly not be worth building out given the export volumes projected as of early 2021.  Then, on February 24, 2022, Russia – the largest supplier of LNG to Europe – invaded Ukraine. In Part 2 of our analysis on U.S. LNG Exports, we will take a closer look at the destination markets of U.S. LNG export cargoes, with a particular focus on Europe and its move away from Russian natural gas, and the commitment by the U.S. to help mitigate that transition while balancing its policies and goals aimed at addressing climate change. We have assisted many clients with various valuation needs in the upstream oil and gas space for both conventional and unconventional plays in North America, and around the world.  Contact a Mercer Capital professional to discuss your needs in confidence and learn more about how we can help you succeed. Appendix A – U.S. LNG Terminals – Existing, Approved Not Yet Built, and ProposedClick here to expand the chart aboveAppendix B – U.S. LNG Terminals – Existing, Approved Not Yet Built, and ProposedClick Here to Read Part 2 of This SeriesIn part 2 we take a closer look at the destination markets of U.S. LNG export cargoes, with a particular focus on Europe and its move away from Russian natural gas, and the commitment by the U.S. to help mitigate that transition while balancing its policies and goals aimed at addressing climate change.
E&P Capital Expenditures Set to Rise, but Remain Below Pre-Pandemic Levels
E&P Capital Expenditures Set to Rise, but Remain Below Pre-Pandemic Levels
The upstream oil and gas sector is highly capital intensive; production requires expensive equipment and constant maintenance. Despite higher oil and gas prices, E&P operators have refrained from increasing capital investment and instead, are delivering cash to shareholders. This post explores recent capex trends in the oil & gas industry and the outlook for 2022 through 28 selected public companies.Historical and Projected Capital ExpendituresCapital expenditures, as measured by spending on property, plant, and equipment (PPE) has varied widely during the last five years.  After the recent high in capital investment in 2019 of $138 billion, guideline group capex dropped 33.5% in 2020 to $91 billion.  After minor growth from 2020 to 2021 on the order of 1.8%, capital expenditures are expected to ramp up investment to about $109 billion in 2022, representing a growth of 17.5% but still below pre-pandemic levels. Leading this growth, Exxon (XOM) is expected to increase capital expenditures by 44.0% to $17.4 billion in 2022, up from $12.1 billion in 2021.  Chevron follows Exxon with an estimated $11 billion in capital spending for 2022, up 37.5% from 2021’s level of $8 billion. All in all, global integrated companies and E&P companies are expected to experience capex growth on the order of 26.3%, up from $71 billion in 2021 to $89 billion in 2022. The global guideline companies account for the lion’s share of total forecasted growth in capital spending, as summarized in the chart below. Appalachia Is Regional Leader in 2022 Capex Growth EstimatesThrough the lens of our company groups by region, the Appalachian Basin is expected to see the largest upswing in capital expenditures. This is by no means an exhaustive indication of growth by region, but it is indicative of the industry environment in Appalachia — capital expenditures are expected to total $5.4 billion in 2022 from the five major operators active in the area, up from $3.9 billion in 2021. As shown below, 2022 is set to be the first year of significant capital investment growth since 2018. Companies in the Eagle Ford are expected to increase capital spending modestly by about 12.6% to $5.1 billion, up from $4.5 billion in 2021. On the other hand, companies in the Bakken and Permian have lowered their capital plans after relatively high spending in 2021, representing a decrease of 52.8% and 15.0%, respectively. Cost Inflation Baked into 2022 Capex BudgetsWhile the expected rise in 2022 capital investment levels from 2021 is encouraging for the global supply of oil & gas, spectators need to acknowledge the effects of cost inflation in the estimates.  According to the Bureau of Labor Statistics ' March Consumer Price Report, inflation has reached a four-decade high in March 2022 as the Consumer Price Index (“CPI”) rose 8.5% over the last 12 months.  Cost inflation, by definition, will detract from operators’ “bang-for-the-buck,” and it is no secret that this is baked into 2022 capex estimates.“In this upcycle, investors have made it clear they wanted to see discipline from all players. So far, E&Ps for the most [part] are exhibiting capital discipline. A significant part of E&P capital spending growth this year (2022 versus 2021) will be consumed by cost inflation as the cost for all inputs continues to increase…” – Dallas Fed Respondent, Q1 Dallas Fed Energy SurveyMoreover, estimates are directly tied to operators’ budgets and management forecasts — which also commonly attribute rising capital expenditures levels within their budget to, among other things, inflation — a theme we covered in a previous blog post.  This helps bridge the divide between rising capital investment budgets and the common industry theme of “capital discipline”.ConclusionCapital expenditures fluctuate as operators react to global marketplace demand for Oil & Gas commodities.  After a recent low in 2020, capital investment is expected to pick up — rising by about 17.5% in 2022, after relatively stagnant growth in 2021.  Rising capital expenditures are generally a precursor to increased production, which will likely help to alleviate the current imbalance of supply and demand of oil & gas in the global marketplace at some point.  However, capital expenditures for 2022 are expected to trail pre-pandemic levels still, and rising inflation is eroding the value generated by those investment dollars.We have assisted many clients with various valuation needs in the upstream oil and gas space for both conventional and unconventional plays in North America, and around the world.  Contact a Mercer Capital professional to discuss. your needs in confidence and learn more about how we can help you succeed.Appendix A – Selected Public Company Capital ExpendituresClick here to expand the chart above
Oilfield Water Markets
Oilfield Water Markets

Update, Trends, and the Future

The Oilfield Services (“OFS”) industry has long been known for its cyclicality, sharp changes in “direction” and demand-driven technological innovation.  One segment of the OFS industry that is among those most subject to recent, rapid change is the Oilfield Water segment – including water supply, use, production, infrastructure, recycling and disposal.  In this week’s Energy Valuation Insights blog, we look to key areas of the Oilfield Water segment – oilfield water disposal and oilfield water recycling – and address both recent trends and where the segment is going in the near-future.Oilfield Water DisposalThe oilfield water disposal (saltwater disposal) industry remains dynamic with numerous forces driving change.  Key among those forces are volume demand, growth in water recycling and rising seismic activity in key shale basins.  With the rebound in oil prices since 2020, demand for oilfield water disposal has rebounded as well. While oilfield water recycling continues to grow rapidly in volume, there remains a very significant imbalance between produced water and recycling volumes.  The portion of produced water that is being recycled was estimated at 20%, per Dr. Chris Harich, Chief Operating Officer at XRI during his presentation at the recent Oilfield Water Markets Conference (“OWMC”).Additional recent factors impacting the saltwater disposal (“SWD”) industry, particularly in prominent U.S. shale plays in Oklahoma, Texas and New Mexico, is the distinct increase in seismic events that are attributed to oilfield production and waste disposal activity.  In September 2021, the Texas Railroad Commission initiated added reporting, permitted volume reductions and even cessation of operations of certain SWDs near high seismic activity areas, referred to as seismic response areas (“SRA”).  As a result of the rising demand for oilfield water disposal capacity and reduced disposal availability in certain areas, Kelly Bennett, CEO & Co-Founder of B3 Insight, expects (i) disposal capacity to remain far below produced water volume through 2026, (ii) increased demand for additional SWD facilities and a race for development of shallow SWDs, (iii) more produced water being transported outside of production areas for disposal, and (iv) a resulting rise in water management costs to producers.In regard to the use of shallow SWD wells, one OWMC panel (including Gauri Potdar, SVP Strategy Analytics at H2O Midstream; Laura Capper, President of Energy Makers Advisory; Max Harris, Director at EIV Capital; and Ken Nelson, President & Co-Founder of Blue Delta Energy) noted that shallow depth SWD activity can interfere with production activity in the immediate area, inherently leading area producers to push back against shallow SWD development projects.Finally, how to finance projects providing additional oilfield water disposal capacity comes with challenges not faced in many other industries.  Bennett noted that as a dynamic industry that seems to be becoming even more dynamic, financing considerations are becoming even more complicated in recent years.Oilfield Water RecyclingOn the recycling side of oilfield water management, the complications aren’t any easier to deal with.  While demand for oilfield water recycling is certainly on the rise, the headwinds to providing recycling services are many and naturally push upward on the cost of recycling services.  However, as with most challenges in the oilfield services industry, new technology and innovation are expected to drive industry participants to overcome the inherent barriers.Notable among the oilfield water recycling headwinds are cost, lack of detailed information as to needed recycling volumes, the need for disposal of certain by-products of recycling, and landowners that are economically predisposed against recycling.  The cost of recycling services likely needs no explanation; however, the logic as to the other headwinds may not be quite as obvious.The OWMC’s panel on the Mechanics of Recycling at Scale (including Jason Jennaro, CEO of Breakwater Energy Partners; Dr. Chris Harich; David Skodak, SVP Water Treatment at CarboNet; Ryan Hassler, Senior Analyst with Rystad Energy; and Joseph De Almeida, Director Water Strategy & Technology at Occidental Oil and Gas), noted that currently there are no oilfield water recycling reporting requirements.  As such, potential recycling project developers have to deal with somewhat rough estimates as to demand volume, rather than a more concrete indication as to the recycled water volume potential in a particular production area.  As with any potential investment, less specificity as to the potential market for services is “read” as greater risk, thereby providing greater uncertainty to project investment.As to byproducts of oilfield water recycling, one only has to go as far as the industry name for the liquid being recycled – saltwater.  Yes, by volume, salt is logically one of the primary byproducts of saltwater recycling.  In the Permian Basin, already known for its high produced water to oil cuts, salt content is higher than found in other basins resulting in higher recycling costs due to the sheer volume of salt byproduct and driving up the cost of capital for development.The last headwind referenced is the economic motivation of landowners in the production area.  The OWMC’s panel on Engaging Landowners (including Rick McCurdy, VP-Innovation & Sustainability at Select Energy Services; Brian Bohm, Sustainability Manager with Apache Corp; Nate Alleman, HSE and Water Infrastructure Specialist at ALL Consulting; Matthias Bloennigen, Director – Consulting with Wood Mackenzie; and Jason Modglin, President of Texas Alliance of Energy Producers) noted that landowners are often compensated to supply water for oilfield exploration and/or production use, or for use of their property in the disposal of saltwater.  As such, these landowners naturally aren’t in favor of the development of water recycling projects that are viewed as cutting into the fees they are being paid under existing contracts.Recycling SolutionsDespite the abundance of recycling headwinds, expectations are that all will be successfully addressed and overcome by the innovation of industry participants.  Costs can be reduced by various means including the extraction of certain rare metals commonly found in produced water, use of flare gas as an inexpensive energy source for recycling operations, the development of recycling equipment that can be readily relocated, and greater cooperation in water management asset “sharing” between basin operators.  In addition, increased recycling reporting requirements can assist in reducing some of the risk inherent in recycling projects and landowners can be educated as to recycling being a complementary service to existing water supply and disposal operations, thereby decreasing the natural resistance to recycling projects.ConclusionAs has always been true of the OFS industry, change brings challenges – and that is no different in the Oilfield Water segment.  The dynamics of oilfield water disposal and oilfield water recycling continue to evolve, but the OFS industry has a long history of addressing and conquering its challenges, and there’s no reason to doubt the current challenges will also be conquered.Mercer Capital has significant experience valuing assets and companies in the energy industry. Our energy industry valuations have been reviewed and relied on by buyers, sellers, and Big 4 Auditors. These energy-related valuations have been utilized to support valuations for IRS Estate and Gift Tax, GAAP accounting, and litigation purposes.  We have performed energy industry valuations domestically throughout the United States and in foreign countries.Contact a Mercer Capital professional today to discuss your valuation needs in confidence.
Private Oil Company Values Are Readying For Take Off: While Publics Remain On Runway
Private Oil Company Values Are Readying For Take Off: While Publics Remain On Runway
As the term “energy security” comes back into the public lexicon, the values of U.S. oil companies are rising. This comes at the delight of some and chagrin of others. Regardless, it represents a foreshadowing of a potential longer-term cycle; whereby U.S. oil production being able to meet energy demands will be increasingly important. Many believe the U.S. is now the world’s “swing” producer (although John Hess disagrees), and it is not due to government action (or inaction). Biden’s third SPR release in the last six months is largely symbolic and more of a political gesture than a meaningful macro-economic needle mover. Demand and supply were drifting apart before Russia’s invasion of Ukraine and this geopolitical dynamic has only widened that gap. The market participants best positioned to seize upon this unexpected gap are private U.S. operators.The current price expectations of oil make a lot of reserves economically attractive. The rate of return on capital deployed for drilling is going to (if not already) outstrip the demand for other capital deployment options such as dividends or debt repayment. However, most U.S. public companies are not shifting their strategies.Domestic Dynamics (Not Russia’s) Keeping Public Valuations Relatively GroundedAs I have written before, shareholders have demanded returns from oil companies for years now in forms other than production growth. Oil company valuation in its fundamental form is a function of the present value of future cash flows. Therefore, if capital available today is best served in drilling more wells tomorrow, then production growth is the most efficient path to a higher value. At historical prices from a year ago, the decision to return more capital to shareholders (as opposed to deploying it in capex) made sense. It doesn’t now. However, public companies have yet to change the courses they’ve been setting for the past several years. That’s partly why the public sector (using XOP as a proxy) only rose 62% in the past year while prices nearly doubled. Demand is strong with the anticipated depletion of Russian oil on world markets. U.S. capital budgets would have to quadruple by the end of 2024 for shale to replace Russian oil exports to continental Europe according to Wells Fargo. In addition, break even prices in most basins for new wells are still around where they were a year ago according to the Dallas Fed Survey. That cost is going up and will continue to, but there is still lots of room for profitability at over $100 per barrel. Also, as I have mentioned before as well, DUC wells continue to shrink. In summary, there are a lot of signals to public companies to “drill baby drill”, yet they aren’t. To be fair there are some caution signs on the horizon that should be considered and are baked into these public valuations. First, the futures curve is still backwardated, meaning that prices are anticipated to fall in the future (not rise). However, even the long-term NYMEX curveis still over $70 in four years, which is still profitable for a lot of reserve inventory. Second, new wells drilled today appear to be less productive. The EIA’s drilling productivity report shows that new well production per rig is going down (although they acknowledge that metric is “unstable” right now). Lastly oilfield services markets have become very tight: “ Labor and equipment shortages, along with inflation in oil country tubular goods and shortages of key equipment and materials, will limit growth in our business and U.S. oil production. In particular, truck drivers are in critical shortage, perhaps due to competition from delivery services.” – Dallas Fed Survey RespondentPrivate Companies Take To The FrontEnter the private oil companies. If forecasts suggest the U.S. can add between 600,000 and 800,000 barrels of oil by the end of the year (EIA says this can be 760,000) then the path to get there will be through the drill bits of private and private equity backed producers. According to an Enverus Report cited by Hart Energy, these types of operators have assumed the vast majority of new rig activity since the summer of 2020. With fewer external concerns, less ESG pressure, and lower regulatory costs, the private sector’s flexibility and nimbleness allow it to surge in front in search of the growth that the fundamental economics suggest is lurking.As an example, Mercer Capital’s latest merger and acquisition discussion focused on the Eagle Ford shale suggested that the market have signaled to potential buyers that the time was right to increase their footprint in southern Texas while conversely providing for an exit for sellers who could either capitalize on the prospect of a continued upswing in energy prices or redeploy capital elsewhere.Whatever the exact incentives may have been that drove the M&A activity, the result was ten deals closed, mostly by private buyers or small-cap producers such as SilverBow Resources.These implied valuation metrics in the table above suggest that there are outsized returns to be made on incremental new wells at the present time. Lots of eyes are turning to watch U.S. production, not only in the Permian, but South Texas, Oklahoma, and the Bakken as well. What they are seeing right now is public companies remaining grounded with their capital, while private companies could be leaving them behind - and quickly.Originally appeared on Forbes.com.
Modest Production Growth for Eagle Ford
Modest Production Growth for Eagle Ford

With More on the Way

The economics of Oil & Gas production vary by region. Mercer Capital focuses on trends in the Eagle Ford, Permian, Bakken, and Marcellus and Utica plays. In this post, we take a closer look at the Eagle Ford.Production and Activity LevelsEstimated Eagle Ford production (on a barrels of oil equivalent, or “boe,” basis) increased approximately 4% year-over-year through March. This is in line with the production increases seen in the Bakken and Appalachia (4% and 5%, respectively) but lags behind the Permian, where production increased 14% year-over-year. There were 56 rigs in the Eagle Ford as of March 25, up 75% from March 19, 2021. Bakken, Permian, and Appalachia rig counts were up 162%, 48%, and 21%, respectively, over the same period. One may wonder why the Eagle Ford has lagged the Permian in production growth despite a larger increase in rigs. The answer has to do with legacy production declines and new well production per rig. Based on data from the U.S. Energy Information Administration (“EIA”), the Eagle Ford needs ~40-45 rigs running to offset existing production declines, and only recently (starting in January) had more rigs running than this maintenance level. The Permian has generally been operating with more than the maintenance level of rigs, so it has seen a higher level of production growth despite a smaller increase in rigs. However, with 56 rigs now running in the Eagle Ford, more production growth should be on the way. Commodity Prices Rise Amid Geopolitical TensionOil prices generally rose through the first two months of the quarter as increased demand was met with continued producer restraint. While the shale revolution had largely put geopolitics in the back seat as a key driver of commodity prices, geopolitics once again became front and center as Russia launched its invasion of Ukraine. In response, Western nations launched a series of economic sanctions against Russia. While the sanctions generally included carve-outs for energy exports, issues with financing and insurance, as well as the exit of Western oil companies and oilfield service providers from Russia, have resulted in a substantial decline in oil exports from the country. Russia was the third-largest producer of petroleum and other liquids in 2020, according to data from the U.S. Energy Information Administration, behind the U.S. and just shy of Saudi Arabia. The potential for that much oil to no longer be available for global markets has led to a high degree of volatility in oil prices. West Texas Intermediate (WTI) front-month futures prices began the quarter at ~$75/bbl and reached $120/bbl in March. Prices have swung dramatically based on actions in Ukraine and the progress of peace talks. Natural gas prices did not exhibit the same level of volatility as oil prices, given the more localized nature of the commodity. However, natural gas is becoming more globalized as Europe grapples with how to replace Russian imports. One obvious source is the United States, as President Biden pledged to boost LNG exports to Europe, despite these same exports being demonized by Democratic Senator Elizabeth Warren just a few short months ago. Administration officials aim to increase European LNG exports to 50 billion cubic meters annually, up from 22 billion cubic meters exported to the E.U. last year. Financial PerformanceThe Eagle Ford public comp group saw relatively strong stock price performance over the past year (through March 28). The beneficial commodity price environment was a significant tailwind to smaller, more leveraged producers like SilverBow and Ranger, whose stock prices increased 326% and 147%, respectively, during the past year, outperforming the broader E&P sector (as proxied by XOP, which rose 62% during the same period). Larger, less leveraged EOG was a laggard, with its stock price rising 61%, slightly behind the broader E&P sector.Survey Says Eagle Ford Wells Among Most EconomicAccording to participants of the First Quarter 2022 Dallas Fed Energy Survey, Eagle Ford wells are among the most economic in the nation. Survey respondents indicated that the average WTI price needed to break even on existing Eagle Ford wells was $23/bbl. This is below the average breakeven in the Permian ($28-$29) and other parts of the U.S. ($30+). While the economic advantage diminishes somewhat for drilling new wells, the Eagle Ford also had the lowest average breakeven for new development, with producers needing WTI at $48/bbl to profitably drill new wells, besting the Permian ($50-51) and other parts of the country ($54-$69). The Eagle Ford’s economic advantage comes from both its geology and geography. The basin’s proximity to Gulf Coast refining and export markets gives it a leg up relative to more inland basins. ConclusionEagle Ford production growth was relatively muted over the past year as capital discipline led to producers running rigs largely at maintenance level. However, with the recent surge in commodity prices, producers are finally starting to bring more rigs online, which should lead to more production growth. However, this growth can’t fill the void left by Russian exports, so commodity prices will likely remain volatile until there is some sort of resolution in Ukraine.We have assisted many clients with various valuation needs in the upstream oil and gas space for both conventional and unconventional plays in North America and around the world. Contact a Mercer Capital professional to discuss your needs in confidence and learn more about how we can help you succeed.
EP Second Quarter 2022 Permian Basin
E&P Second Quarter 2022

Permian Basin

Permian Basin // Both oil and gas commodity prices rose in the second quarter of 2022, with WTI and Henry Hub front-month futures prices floating around $121/bbl and $9/mmbtu in mid-June, as Russia launched its invasion of Ukraine in late February.
Eagle Ford M&A
Eagle Ford M&A

Transaction Activity Over the Past 4 Quarters

Deal activity in the Eagle Ford increased over the past year as energy prices recovered from a tumultuous 2020. As we noted in June of last year, production in the Eagle Ford remained relatively flat over the prior year despite 146% growth in the regional rig count, suggesting the significant increase in drilling activity was just enough to offset the decline in already-producing wells, but not economical enough to spur production growth meaningfully. This may also have signaled to potential buyers that the time was right to increase their footprint in southern Texas while conversely providing for an exit for sellers who could either capitalize on the prospect of a continued upswing in energy prices or redeploy capital elsewhere. Whatever the exact incentives may have been that drove the M&A activity, the result was ten deals closed in the Eagle Ford over the past four quarters, up from eight transactions closed in the prior four quarters.Recent Transactions in the Eagle FordA table detailing E&P transaction activity in the Eagle Ford over the last twelve months is shown below. The median deal value in the past four quarters ($370 million) was approximately $282 million higher than the median deal value from Q2 2020 to Q1 2021, excluding Chevron’s acquisition of Noble Energy in July 2020. The average deal value over the past year ($573 million) was more than double the average value ($274 million) over the prior year (excluding the Chevron-Noble Energy deal). Also notable, larger positions were transacted over the past year, with a median size of 45,000 net acres as compared to 26,500 net acres in the prior year (excluding Chevron-Noble Energy), and an average deal acreage of nearly 80,000 net acres this past year which was more than double the average of 34,775 net acres in the prior year.SilverBow Resources Builds Up Its Eagle Ford AssetsOn October 4, 2021, SilverBow Resources announced the closing of its purchase to acquire oil and gas assets in the Eagle Ford from an undisclosed seller in an all-stock transaction. The aggregate purchase price for these assets was $33 million, with the transaction consisting of approximately 1.5 million shares of SilverBow’s common stock. In late November 2021, SilverBow announced another transaction closed with its purchase of oil and gas assets from an undisclosed seller for $75 million, including $45 million in cash and approximately 1.35 million shares of SilverBow’s common stock.Of this second transaction, Sean Woolverton, CEO of SilverBow, commented, “This is the third acquisition we have closed in the second half of this year. This transaction represents SilverBow’s largest to date. As we look to 2022, the Company is set to grow production by double digits in part from the incremental development locations and a full year’s worth of contribution from the acquired assets. With greater cash flow and liquidity, SilverBow remains well-positioned for strategic M&A and further de-levering.”Callon Petroleum Divests Non-Core Eagle Ford AssetsOn October 5, 2021, Callon Petroleum – one of the upstream companies we follow regularly in our quarterly review of earnings call themes from E&P operators – announced it had entered into an agreement to sell non-core acreage in the Eagle Ford as part of its acquisition of leasehold interests and related oil, gas, and infrastructure assets in the Permian basin from Primexx Energy Partners. Total cash proceeds from the divestiture were approximately $100 million. The Eagle Ford properties included approximately 22,000 net acres in northern LaSalle and Frio counties. Net daily production from the properties was approximately 1,900 Boe/d (66% oil) on average in the third quarter through month-end August. Callon noted in its press release that the sale would eliminate approximately $50 million in capital expenditures related to continuous drilling obligations over the next two years, allowing for redeployment of capital to higher return projects.ConclusionM&A activity in the Eagle Ford has picked up over the past year in terms of both deal count and the amount of acreage involved. The ten deals noted over the past year were split evenly between property/asset acquisitions and corporate transactions, such as the Desert Peak Minerals-Falcon Minerals Corporation merger announced in mid-January of this year. This signals a notable increase in corporate-level activity as only one of the eight transactions in the prior year involved a corporate transaction, possibly foreshadowing greater industry consolidation in the Eagle Ford moving forward.We have assisted many clients with various valuation needs in the upstream oil and gas industry in North America and around the world. In addition to our corporate valuation services, Mercer Capital provides investment banking and transaction advisory services to a broad range of public and private companies and financial institutions. We have relevant experience working with companies in the oil and gas space and can leverage our historical valuation and investment banking experience to help you navigate a critical transaction, providing timely, accurate and reliable results. Contact a Mercer Capital professional to discuss your needs in confidence.
Mineral Aggregator Valuation Multiples Study Released
Mineral Aggregator Valuation Multiples Study Released

With Market Data as of March 15, 2022

Mercer Capital has its finger on the pulse of the minerals market.  An important trend has been the rise of mineral aggregators, which have largely supplanted the trusts as the primary method of publicly traded minerals ownership.Due to a variety of corporate structures (including master limited partnerships and Up-Cs) and complex capital structures (including preferred equity and non-traded common units), mineral aggregator enterprise values pulled from databases are often missing meaningful components of value, leading to skewed valuation multiples.Mercer Capital has thoughtfully analyzed the corporate and capital structures of the publicly traded mineral aggregators to derive meaningful indications of enterprise value.  We have also calculated valuation multiples based on a variety of metrics, including distributions and reserves, as well as earnings and production on both a historical and forward-looking basis.Mineral Aggregator Valuation Multiples StudyMarket Data as of March 15, 2022Download Study
Themes from Q4 Earnings Calls (1)
Themes from Q4 Earnings Calls

Part 3: Oilfield Service Companies

Last month, we reviewed Q1 through Q3 2021 earnings call themes from oilfield service companies. Commentary regarding the progress of ESG efforts, whether initiated by the OFS companies themselves or in support of their customers' ESG programs, was prevalent throughout the year. OFS management teams also noted their anticipation of increased industry consolidation by way of M&A activity. Perhaps most poignantly over the first three quarters of 2021, OFS companies signaled increasing leverage in their ability to either start commanding higher prices of their customers, or the expectation they would be able to do so in the very near term.In Part 1 of our Themes from Q4 Earnings Calls, we examined key topics among E&P operators, including:Projections of moderate cost inflation, typically in the upper single digits;Shifting focus towards liquids, including crude oil and NGL streams; andIndustry headwinds stemming from macro energy policies in the U.S. In Part 2 of our Themes from Q4 Earnings Calls, key topics among mineral aggregators included:Greater scrutiny and discipline regarding the execution of M&A deals;Expectations of relatively stagnant production in the near-term; andGreater insulation from price inflation relative to the impact on E&P operators. With this background in mind, we focus this week on the key takeaways from the OFS operator Q4 2021 earnings calls.Macro HeadwindsLabor shortages and supply chain constraints have been a common topic in the daily news cycle regarding the macroeconomic environment in the U.S.  Suffice it to say, the OFS industry has not been immune to these factors."You know the story of tubulars people are struggling to get the right tubulars on time. They are having to make substitutions. We are seeing some rig efficiencies begin to deteriorate, which is attributable to several factors. Part of that, of course, is the basins. Different basins have different efficiency profiles. But I think our view is activities at the rig side have slowed down, all things being equal, strictly because of problems with personnel breakdowns. I think the industry is a bit stressed right now." – Scott Bender, President & CEO, Cactus Wellhead"Beyond activity trends, we see a continuation of many of the same things from 2021. Operators will continue to look for ways to improve efficiency and sustainability. We see the current constraints in many critical areas such as labor, sand, and trucking also continuing for the near term." – William Zartler, CEO & Chairman, Solaris Oilfield Infrastructure"Productivity and efficiency was broadly encumbered by 2 significant factors. First, the tightening labor market we faced in the U.S. was exacerbated by COVID outbreaks in certain plants during the fourth quarter. As skilled workers recuperated safely at home, their work was performed by less experienced, less efficient crews or by other skilled workers working overtime. Labor shortages led to higher product costs and scheduling headaches. Second, our manufacturing scheduling headaches were compounded by component and raw material shortages and late deliveries from our vendors who are facing the same sort of challenges that we are. Some businesses report supply chain challenges are getting a little better, but mostly these disruptions are persisting or getting more challenging in the near-term." – Clay Williams, CEO, National Oilwell VarcoIndustry Consolidation through M&A ActivityIn our Q1 through Q3 2021 OFS earnings call themes post, we noted anticipation of greater M&A activity and industry consolidation in 2022. This continued in Q4, with the ongoing expectation of consolidation activity in the near future."We have not given up on industry consolidation. That's our number one priority. And importantly, I don't think the industry has given up on industry consolidation. Yes, the valuations are going to be higher today than they were this time last year, but our currency is also more valuable today than it was this time last year. I don't really consider that to be an impediment to getting a deal done. The impediment is finding the right deal.  ...  Private equity has decided maybe now is the time to monetize after they've probably given up hope over the last couple of years." – Scott Bender, President & CEO, Cactus Wellhead"As I've stated many times, I believe consolidation is very important for this industry. Through a combination of cash and stock consideration, we closed on the acquisitions of Complete Energy Services, Agua Libre Midstream, HB Rentals and UltRecovery during 2021. Additionally, we are set to close on the acquisition of Nuverra Environmental Solutions. In doing so, we've added nearly $300 million of run rate revenues to an already growing base business and acquired strategic portfolio of infrastructure assets, including gathering and distribution pipelines, disposal facilities, and landfill operations." – John Schmitz, President & CEO, Select EnergyESG ActivityThe Q4 OFS earnings calls were peppered with commentary regarding ESG, including recognition of OFS operator initiatives from outside the industry, the mitigation of environmental impacts on local communities at present, and projections of continued demand for ESG-focused services."We announced our science-based emission reduction targets, added 11 new participating companies to Halliburton Labs and were named to the Dow Jones Sustainability Index, which highlights the top 10% most sustainable companies in each industry." – Jeff Miller, CEO, Halliburton"Overall in 2021, we recycled 25 million barrels that produced water through our fixed facilities, and we expect to continue driving these volumes higher. This recycling alleviates demand for freshwater sources in water stress regions, while also limiting waste disposal which is particularly important in areas of seismicity concerns." – Nick Swyka, CFO, Select Energy"On the technology and sustainability front, we continue to advance our water recycling efforts. We've invested in six facilities during 2021 which are backed by long-term contracts. This sets the stage for a significant growth in our recycled volumes for 2022." – John Schmitz, President & CEO, Select Energy"We're busy upgrading Tier 2 fleets to Tier 4 dual fuel fleets that can utilize up to 85% natural gas. And we expect the pursuit of ESG-friendly operations, efficiency gains and the industry's existing tired fleet of equipment will lead to continued demand for such rebuilds." – Jose Bayardo, CFO, National Oilwell Varco Mercer Capital has its finger on the pulse of the OFS operator space. As the oil and gas industry evolves through these pivotal times, we take a holistic perspective to bring you thoughtful analysis and commentary regarding the full hydrocarbon stream, including the ancillary service companies that help start and keep the stream flowing. For more targeted energy sector analysis to meet your valuation needs, please contact the Mercer Capital Oil & Gas Team for further assistance.
Themes From Q4 Earnings Calls
Themes From Q4 Earnings Calls

Part 1: E&P Operators

InPart I of our Themes from Q3 Earnings, topics included increased global demand for U.S. LNG exports and the divergence in the value proposition of E&P operators. Some opted to focus on using free cash flow to either pursue share repurchase programs and/or increase dividends instead of seeking out acquisition opportunities.On the other end of the spectrum, Continental Resources announced an agreement to purchase Delaware basin assets from PioneerResources to the tune of $3.25 billion. Technically, this acquisition was announced in Q4 (on November 3rd), but Continental’s management team made a point of mentioning it in the Q3 earnings call. Still, some companies, like EOG Resources, signaled setting their sights on pursuing more organic, exploration-driven growth and footprint expansion.In the last round of earnings calls for 2021, cost inflation was discussed with a bit more granularity than in recent quarterly calls, strengthening oil prices sparked a shift in focus towards the liquid hydrocarbon streams, and commentary regarding macro policies targeting hydrocarbons were prevalent in E&P management discussions.Cost InflationIn our Q1-Q3 2021 Themes From Oilfield Service Company Earnings Calls post from late January, we noted that OFS operators were likely hitting an inflection point in mid- to late-2021, with greater command of the prices they charged their E&P customers than in recent history. While service cost inflation was certainly on the minds of some E&P operators, costs for various industry inputs were mentioned in the Q4 earnings calls.“On the service side, on the rig and the frac crew side, because the way that we've contracted those services we've been somewhat isolated so far, in any kind of cost inflation along those lines. Where we've seen the bulk of the inflation so far in our business has been materials, particularly with respect to steel related material. Probably half of the inflation that we’ve baked into our '22 forecast [5% to 10%, year over year] is almost entirely in either steel or tubular. The rest of it, would it be spread across the multitude of materials that we use in our business." – Chad Griffith, Chief Operating Officer, CNX Resources“Our drilling and completion capital budget of $675 million to $700 million reflects an impact of approximately 5% from service cost inflation. This inflation includes the net benefit of expected sand savings from our regional sand mine.” – Paul Rady, President & CEO, Antero Resources“On the cost side, structural operating efficiency gains in 2021 continue to drive our average cost per foot down by approximately 7% on average, year-over-year. In our 2022 budget, we expect modest cost inflation.” – Jack Stark, President, Continental ResourcesShifting Focus Towards LiquidsIt is not newsworthy at this point to say energy prices bounced back over the course of 2021 as compared to the subdued levels seen over 2020. However, despite the significant increase in U.S. natural gas production (with no countering decrease in gas prices), several E&P management teams noted a shift back towards liquids in the latest earnings calls.“While our 2022 lease operating cost per barrel-oil equivalent guidance is modestly above our 2021 level, this reflects our pivoting towards greater oil activity…” – John Hart, CFO, Continental Resources“My comments today will focus on our current view of the liquids markets, more important than ever given we are fully unhedged on all oil and NGL production as of the start of 2022. The past few months, we have seen crude prices reaching their highest levels since 2014, with Brent and WTI touching these 7-year highs supported by global supply concerns and geopolitical tensions across several key regions. At the same time, demand has surprised to the upside and market demand forecasts have been revised upward, primarily due to the more muted impact of Omicron on global consumption compared to previous COVID variants. NGL prices have also benefited in the current bullish price environment.” – David Cannelongo, Vice President – Liquids Marketing & Transportation, Antero ResourcesPolicy HeadwindsIn our Energy Valuation Insights coverage of Appalachia, we noted a strongly worded letter sent from Massachusetts Senator Elizabeth Warren to natural gas E&P operators for the purpose of “turning up the heat on big energy companies who are gaming the system by raising natural gas prices for consumers to boost profits and line the pockets of executives and investors.”  Controversy regarding the perception, whether real or imagined, that the U.S. E&P industry holds enough power to materially or unilaterally guide global energy prices is nothing new. However, several comments made in the Q4 earnings calls suggested a deeper underlying sentiment from E&P management teams that certain industry headwinds are the direct result of certain national policies.“We are proud to play our role in supporting U.S. energy security, which protects the U.S. consumer and serves as a powerful tool of foreign policy providing options for both the U.S. and our allies. We must take on the dual challenge of meeting the world's growing energy needs while also prioritizing all elements of our ESG performance, including efforts to address climate change. This is not an either/or proposition and failure on either front is not acceptable. However, our approach must be pragmatic and grounded in the free market, innovation and an ‘all of the above energy’ approach. We are unfortunately experiencing firsthand the impacts of misguided energy policy and the dramatic role it can play on energy affordability as well as geopolitical stability.” – Lee Tillman, President & CEO, Marathon Oil“I may add one other thing that I know you would have seen some of the comments from the Federal Reserve, if I can, this morning about, ‘Do you want to go and target industries?’ [We note that the referenced comments from the Fed could not be readily verified], and so I think that's why you're seeing us and probably the industry at large being very focused on getting that net debt down, because there is potentially a targeting of this industry to not be friendly toward lending money term.” – Bill Berry, CEO, Continental Resources“What you've got right now, not just within Appalachia, but nationally, is a policy that is designed basically to not have a natural sort of [pipeline] investment occur to match something like the supply of natural gas to the demand centers. I don't know if, at last, we're starting to see some problems manifest with respect to that type of policy.” – Nick Deluliis, CEO, CNX Resources Mercer Capital has its finger on the pulse of the E&P operator space. As the Oil & Gas industry evolves through these pivotal times, we take a holistic perspective to bring you thoughtful analysis and commentary regarding the full hydrocarbon stream. For more targeted energy sector analysis to meet your valuation needs, please contact the Mercer Capital Oil & Gas Team for further assistance.
Oilfield Services 2022
Oilfield Services 2022

The Rise of the OFS Bulls

In our Energy Valuation Insights post from last week, Bryce Erickson focused on Oilfield Services (OFS) company valuations.  This week we follow the same OFS theme, but with a focus on OFS “expectations” and the question: “Has the OFS industry turned the corner to a more prosperous outlook?”Enthusiasm Among ExpertsOne can’t come away from a review of current OFS industry musings without feeling that, in the endless battle between OFS Bulls and OFS Bears, the Bulls have gained the advantage and are on the rise.From Bloomberg Intelligence – and under the noteworthy heading of OFS Recovery to Reach Cruising Altitude in 2022 – we find that oilfield services industry revenues are expected to grow by ten to fifteen percent in 2022, compared to nearly flat revenue growth in 2021.  North American OFS is expected to lead the way with likely 20% revenue gains.Representatives of investment banking firm Evercore’s E&P and OFS groups noted in a recent Natural Gas Intelligence piece that the E&P and OFS groups’ expectations for 2022 remain bullish as they believe we are in the early stages of a long, strong, multi-year E&P spending upcycle.In its recent industry outlook, Zacks noted that the OFS industry is bright again and that the business environment for E&P activities has shown drastic improvement.  That improvement is reflective of oil prices having returned to the “glorious days,” thereby leading drillers to return to the oil patch, resulting in significantly improved demand for oilfield services.Many more significantly optimistic references are available, but suffice it to say that expectations for the OFS industry (due to E&P industry activity) have changed a lot, for the better, in the last year.Basis for OptimismSo, what are the industry experts seeing that is leading to this optimism?  In short:oil demand rising as the Covid pandemic recedes and the world begins the return to normal levels of activities that require energy use,significant potential for an oil supply shortage, andrecent under-investment in the new production needed to sustain supply. In light of the factors above, industry analysts are detailing some very positive expectations for the OFS industry.  Such as: The Energy Information Administration (EIA) forecasts that global consumption of petroleum and liquid fuels will average 100.6 million b/d for all of 2022, which is up 3.5 million b/d from 2021 and more than the 2019 average of 100.3 million b/d. On top of which the EIA forecasts that global consumption of petroleum and liquid fuels will increase by 1.9 million b/d in 2023.  So, for the first time since Covid reared its head in early 2020, global oil consumption is expected to rise to a level materially higher than pre-Covid consumption. Mizuho Securities USA LLC indicates in a January 2022 NGI article (U.S. E&Ps, OFS Players Expected to Reset in 2022, with Eyes on Inflation, Supply Chains) that in order to generate sustainable oil volumes through 2022 based on current production volumes, the rig count across the five major U.S. oil basins would have to increase by 100 rigs, compared to a 178 rig increase since January 2021. Mizuho further indicated that the rate of completions in the major U.S. basins is probably sufficient to support growth.  However, the drilled but uncompleted (DUC) inventory is at a historically low level, so more drilling activity will be required.  Otherwise, the needed 2022 growth in the U.S. supply could be materially held-back. Early Indications Favoring the BullsAs to early evidence supporting those expectations, Baker Hughes’ most recent North American rig count is at 854, a level not seen since the onset of the Covid pandemic in March 2020.According to Bank of America, due to the draw-down in global oil inventories in 2021, the oil market is anticipated to move from a steep deficit to a more balanced market.  With that in mind, BofA is predicting that WTI and Brent will average $82 and $85 over the course of this year.Other industry analysts, including Goldman Sachs Group, are indicating that oil prices could reach $100 during 2022, while forecasting average 2022 oil prices at $85. Employment in the U.S. oilfield services and equipment sector rose by an estimated 7,450 jobs in December, according to the Houston-based Energy Workforce & Technology Council. Zacks Equity Research summarized how all this ties in to the OFS outlook: “The price of West Texas Intermediate (WTI) crude is trading higher than $89 per barrel, marking a massive improvement of more than 50% in the past year. Strong fuel demand across the world and ongoing tensions in Eastern Europe are aiding the rally in oil prices. The massive improvement in oil price is aiding exploration, production and drilling activities. This, in turn, will boost demand for oilfield service since oilfield service players assist drillers in efficiently setting up oil wells.” Potential HeadwindsOf course, there are also headwinds for the OFS sector that will have to be dealt with, including inflation being a key consideration.  As detailed in our January 14, 2022 Energy Valuation Insights post, industry analysts are projecting over 30% average OFS revenue growth in 2022, although average EBITDA margins are expected to edge downward from 13% toward 12%.  Inflationary factors are pushing up OFS costs, but such increased costs are expected to only partly be passed through to their E&P clients.In addition, the Biden Administration is clearly adamant about getting the country moving rapidly away from hydrocarbon-based energy, despite the public already complaining mightily about fast-rising energy prices and more general inflationary pressures.  Where those political winds will carry the matter is anyone’s guess.In SummaryAs indicated, the companies that comprise the OFS segment – at least those that survived 2020 – experienced some stabilization in 2021, and are now facing what appears to be a market that has the industry analysts feeling fairly bullish.  Influenced by rising oil demand, an existing shortage, and recent E&P investment well below the sustainable level, expectations have moved from OFS stabilization to strong multi-year OFS growth in 2022 and likely beyond.Mercer Capital has significant experience valuing assets and companies in the energy industry. Our energy industry valuations have been reviewed and relied on by buyers, sellers, and Big 4 Auditors. These energy-related valuations have been utilized to support valuations for IRS Estate and Gift Tax, GAAP accounting, and litigation purposes.  We have performed energy industry valuations domestically throughout the United States and in foreign countries.Contact a Mercer Capital professional today to discuss your valuation needs in confidence.
Oilfield Service Valuations: Dawn Is Coming
Oilfield Service Valuations: Dawn Is Coming
Most people who know me know that I have loved movies most of my life.  One favorite is 2008’s The Dark Knight, where Harvey Dent proclaims hope to a skeptical media, “The night is darkest just before the dawn.  And I promise you, the dawn is coming!”  This comes to mind as I observe valuations and prospects for oilfield service companies.  It has been tough sledding for OFS companies during COVID.  Many shuttered their doors, equipment, or people.  At the end of 2020, rig counts were around 350 and DUC counts were high.However, as we’ve been talking about for the past several weeks, things have changed for the positive as far as the industry is concerned, and it’s going to get better according to people like Marshall Adkins of Raymond James, who spoke at the NAPE Global Business Conference in Houston.  The current U.S. rig count is now at 613 and, according to Mr. Adkins, may be heading to 800 this year if OFS companies can fill a real labor shortage gap.However, when it comes to valuations, assuming oilfield service companies will join the recovery has not always been true in the shale era.  That said – this time may be different.What’s Old Is New: Cycle Could Be PivotingOFS is well documented to be one of the most cyclical industries.  Financial performance tends to lag customers in the E&P sector.  As an example, despite the expectation for strong revenue growth in 2022, analysts project that EBITDA margins are expected to actually decline slightly from a year-end 2020 median forecast of 12.8%, to a current figure of 12.2%.  However, what if that growth continued beyond 2022 and into the following years?  Many think this will be the case as global demand for oil and gas continues to grow amid the surge in renewables.  Industry research analysts at IBISWorld project growth of 2.4% compounded for the entire $85.4 billion revenue industry (that’s over $2 billion of revenue growth every year for the next five years).  Adkins sees this as the beginning of a multi-year bull run for energy on the tail of sector underinvestment, low supply, inflation, and demand growth rising to pre-COVID levels.Past Oilfield Service PerformanceOilfield service providers, drillers, pumpers, and equipment providers enabled E&P companies to ramp back up. So, where do they stand today? One lens through which to view things is the OSX index–a popular metric to track sector performance. Since the end of 2020, the OSX index has bounced around but has generally moved back up as demand has risen.  In addition, this will almost certainly go higher if rig counts go back up to 800, which hasn’t been the case since 2019.  From Adkins’ perspective, his question is: will the OFS industry be able to handle getting back up to 800 rigs?  This is particularly acute from a labor perspective.  The oilpatch has long been challenged to attract workers because of seasonality, remote operations, camp life, and the expectation that you will continue working regardless of the weather. It compensated with high wages, interesting and challenging work, and endless opportunities for advancement in a growing industry.  But that’s not the case in 2022. The young generation that the industry has always managed to attract is increasingly urban, pampered, and has grown up in a society that has a negative impression of fossil fuels and is produced by an industry that some perceive to have no future. All the while the demand grows.  Part of the reason for this growing demand is the steady depletion of drilled but uncompleted (DUC) well inventory in the past year or so.  DUCs will eventually deplete to the point that more new wells must be drilled, thus increasing demand for OFS. E&P companies will, out of necessity, rediscover great respect for their suppliers.  And the service sector will enjoy rewards for surviving the past seven years – perhaps not bigger, but certainly much better. Current Oilfield Service PerformanceHigher oil prices, coupled with competitive breakeven costs for producers, are making drillers, completers and a host of other servicers busy. Capex budgets for E&P companies, known as lead indicators for drillers and contractors, have cautiously been increasing, even amid the capital discipline drumbeat over the past several years.IHS Markit released a report early this month titled, “The Great Supply Chain Disruption: Why It Continues in 2022.” In the introduction, Vice-Chairman Daniel Yergin wrote, “There is no recent historical precedent for the current disruption in the modern highly integrated global supply chain system that has developed over the last three decades … [resulting in] delays and disruptions for manufacturers and deliveries on a scale never recorded in our 30 years of PMIs (Purchasing Managers’ Index).”In the meantime, the oil patch will need its supply chain to be working.  According to Rystad Energy, the average productivity of new wells in the Permian Basin is set to hit a record high in 2022, breaching past 1,000 BOED due to a surge in lateral well length.  The only way that this can be done is with more OFS services.Valuation TurnaroundNow that utilization rates and day rates are both trending upward, valuations should logically respond and by certain aspects, they are.Take, for example, a selection of guideline company groups: onshore drillers and pressure pumpers (fracking companies). One way to observe the degree of relative value changes is to look at enterprise value (sans cash) relative to total book value of net invested capital (debt and equity) held by the company or “BVIC”. Any multiple over 1.0x indicates valuations above what net capital investors have placed into the firm, which for drillers and pumpers is a notable threshold. In 2019-2020, with a multiple well below 1.0x, investors didn’t expect to get an adequate return on the capital deployed at these companies. However, in 2021 and continuing in early 2022, that trend has reversed.  This suggests that the market is recognizing intangible value again for assets such as developed technology, customer relationships, trade names and goodwill. For pressure pumping and fracking concentrated businesses, which are more directly tied to DUCs, the trend is clear.  Intangible asset valuations have grown even faster, more heavily weighted towards pumpers’ developed technology that is driving demand for these companies’ services. ConclusionOverall rig counts have shifted downward since 2014 and are currently nowhere near levels back then, however, this cycle may resemble pre-shale eras when fundamentals like inflation, supply issues, and related factors pushed commodity prices upward for extended periods.  Oil and gas are fundamental economic building blocks in the world economy.  If the longer-term cycles are pivoting towards the direction they appear, values of OFS companies may be increasing for a longer cycle this time.
Meet The Team
Meet The Team

Bryce Erickson, ASA, MRICS

In each “Meet the Team” segment, we highlight a different professional on our Energy team. This week we highlight Bryce Erickson, Senior Vice President of Mercer Capital and the leader of the oil and gas industry team. The experience and expertise of our professionals allow us to bring a full suite of valuation, transaction advisory, and litigation support services to our clients. We hope you enjoy getting to know us a bit better.What attracted you to a career in valuation?Bryce Erickson: There are a lot of things appealing about valuation, and I feel fortunate to have been a part of it for over 20 years.  Looking back, for me, three things stand out.  First, I sort of grew up in the profession. My dad entered valuation in 1972, and I would hear the conversations at the dinner table about the cost of capital, customer lists, and comparables.  Secondly, the economic and analytical disciplines at the center of what I do align well with how my brain functions and how I approach problem solving.  That’s fun.  Lastly, it allows me to serve clients in a way that, if done well, will lead to a long career whereby I have a lot of ability to chart my own course.  That’s a great incentive.What does your personal practice consist of?Bryce Erickson: Sort of like the Generation X member that I am, my practice is a mix of a lot of things. When I started in valuation in the late ’90s, most firms and groups had not specialized (that has changed). I got exposed to a lot of industries and service lines as a result. I have touched a bit of everything in my career and still do in many respects. However, as my career has progressed, I have developed a few specializations. One is in energy, particularly upstream oil & gas, as well as minerals. That has been a big part of my career in the past 10+ years. Another has been professional sports (NFL, NBA, MLB, NHL), where I have had the opportunity to value teams I grew up watching or rooting for as a kid. That has been a real thrill. Again, I touch them all as far as service lines, but the two areas I have spent the most time on have been tax-driven and litigation-driven work. In addition to valuation, I have done a lot of economic damage-driven work and have testified nearly two dozen times now. Litigation is intense by its nature, and that intensity is useful in other areas of my practice, helping me give the best service I can to all clients.What types of oil & gas engagements do you work on?Bryce Erickson: As I’ve already mentioned, in addition to exploration and production company valuations, I do fairness opinions and quite a bit of mineral and royalty interest valuations.  These come in many different scenarios, from tax to financial reporting to litigation.  At this point, we have probably worked in just about every major oil & gas basin in the U.S. and several international projects as well.  I also do some work with oilfield service clients.What is unique about Mercer Capital’s oil & gas industry services compared to your competitors?Bryce Erickson: I believe what is unique about our oil & gas group is our blend of industry expertise that we have gained over the years alongside the depth and knowledge of the valuation space. It is a powerful combination for our clients and they like it a lot. On the industry side, we are able to connect with clients and speak their language as far as reserves, basins, structures, and economics are concerned.  On the valuation side, we speak the language of the audiences we are addressing as well, whether that’s a judge in a courtroom, an IRS engineer in a tax matter, or an auditor for a financial reporting issue. Our competitors may have one or the other of those two skill sets, but rarely both.As a Forbes.com contributor, what types of issues do you cover in your column?Bryce Erickson: I address industry developments, economic trends, and the impact on valuation for companies operating in the Permian, Eagle Ford, Bakken, and Marcellus & Utica regions, among others. Additionally, I cover these issues as they pertain to mineral rights and royalty owners. It is a fun column to write. It also allows me to stay tied into the industry as well as keep current.What is the one thing about your job that gets you excited to work every day?Bryce Erickson: That’s simple. Solving problems and serving clients.  It scratches itches and is so satisfying for me.  I am excited I get to utilize so much of my education and experience on each engagement so that Mercer Capital can do excellent work for our excellent clients.
Q1-Q3 2021 Themes From Oilfield Service Company Earnings Calls
Q1-Q3 2021 Themes From Oilfield Service Company Earnings Calls
Nuances of the Upstream PerspectiveAs our readers are well aware, Mercer Capital tracks and reviews themes from the quarterly earnings calls ofE&P operatorsand mineral aggregators, providing key insights into the upstream perspective on U.S. oil and gas.  In this post, we look at oilfield service (OFS) company earnings calls for the first three quarters of 2021.  Looking forward, we will likely incorporate OFS earnings calls in our quarterly survey of themes from the public oil and gas sector, using this post as a reference point for the upcoming round of Q4 2021 calls.We typically review earnings calls for 3 to 8 companies among the E&P operators and mineral aggregators each.  Likewise, we look forward to reviewing calls for a roster of approximately 7 OFS companies that operate in the primary onshore U.S. basins covered by Mercer Capital.  In this inaugural survey, however, we focus on Q1 through Q3 earnings calls for just two OFS companies – Halliburton and Ranger Energy Services.  We follow the earnings call themes for these two companies, who represent some of the largest and smallest (by market cap) public OFS companies, through the first three quarters of 2021 to get a sense of how OFS industry dynamics have evolved over the past year.Promoting ESG InitiativesIn our review of Q1 2021 earnings call themes among E&P Operators, we saw a continued trend (from Q4 and Q3 2020 E&P operator earnings call themes) of emphasizing and discussing the progress of various ESG initiatives.  This theme was absent in the Q2 2021 E&P earnings calls, and not a significant theme in the Q3 2021 E&P earnings calls.  However, OFS operators were clear to point out their contribution towards various ESG initiatives throughout the first three quarters of 2021.“We're excited about the progress of Halliburton Labs, our clean-energy accelerator.  In the first quarter, we announced Halliburton Labs' inaugural group of participating companies.  They are working on solutions for transforming organic and plastic waste to renewable power; recycling of lithium-ion batteries; and converting carbon dioxide, water, and renewable electricity into a hydrogen-rich platform chemical.” – Jeff Miller, President & CEO, Halliburton [Q1]“We have successfully completed gas processing jobs for both dual fuel and e-frac fleet and anticipate more to come.  There are several rewarding attributes to this transition.  We are tangibly contributing to the ESG efforts of our industry.” – Darron Anderson, CEO, Ranger Energy Services [Q1]“On the Processing Solutions side, we continue to expect our customers' ESG mandate to drive an uptick in both the traditional flare gas capture use and newer fracturing dual-fuel and e-fleet generation fuel supply.  We continue to have pilot program success on fuel supply projects, but have yet to sign that elusive long-term contract.  Stay tuned here as stronger commodity pricing, incremental flare gas, emission regulation and the build-out and adoption of dual fuel and electric frac fleet are all tailwinds for our Processing Solutions segment.” – Bill Austin, Interim CEO & Chairman, Ranger Energy Services [Q2]“In the third quarter, Halliburton completed an all-electric pad operation on a multi-year contract with Chesapeake Energy in the Marcellus Shale.” – Jeff Miller, President & CEO, Halliburton [Q3]Opportunistic Acquisitions & Increased Consolidation of Smaller OperatorsWhile mineral aggregators were active on the M&A front in Q3 2021, with a favorable sentiment towards expanding their holdings since Q1, E&P operators were relatively quiet in the Eagle Ford and Appalachian basins, a bit more active in the Bakken, and chomping at the bit in the Permian.  OFS operators, particularly those for whom incremental expansions carry more weight, kept their eyes on the horizon over 2021.“Our acquisition strategy has been fixed and simple.  We are focusing on potential counterparties with top-tier assets, who have a reputation for best-in-class service quality.  We are looking at both bolt-ons to our existing service lines and complementary service lines that extend our current core service offerings.  Tactically, we believe in being opportunistic.” – Darron Anderson, CEO, Ranger Energy Services [Q1]“As we said in the prepared remarks, many of these small operators, frankly, we believe, lived and died on the PPP.  They priced things that keep them alive and trade dollars.  We think by signaling, and more than signaling that there's consolidation, and we think there'll be other players that will try to consolidate.” – Bill Austin, Interim CEO & Chairman, Ranger Energy Services [Q2]Leverage to Increase Service PricingThe greatest theme of 2021 from the perspective of E&P operators and mineral aggregators was the upward trajectory out of the crude abyssfrom 2020.  What a difference a year makes, both in hindsight and for the road ahead.  This was probably most present with OFS operators, which likely hit an inflection point from riding the wave as price-takers to potentially commanding the wave as price-makers in the near-term or at least being able to take more than what they can just get.“Service pricing improvement is the final step.  We're not there yet, but we see positive signs of market rebalancing that should drive future pricing improvements.  Total fracturing equipment capacity has limited room to grow in the current pricing environment.” – Jeff Miller, President & CEO, Halliburton [Q1]“I believe equipment availability will tighten much faster than most people think.  In multiple product lines, we believe that equipment supply will fall behind anticipated demand.  Today, both drilling and completions equipment are nearing tightness in North America.” – Jeff Miller, President & CEO, Halliburton [Q2]“Our primary near-term objective is driving margin expansion.  Our largest near-term lever here is pricing.” – Bill Austin, Interim CEO & Chairman, Ranger Energy Services [Q2]“I'll give you two anecdotes.  One customer was a smaller customer, that we went and said that these need to be the new rig rates for us to continue, working beyond what we had committed to. They were pretty upset.  Used some pretty colorful language.  And we said, we're going to okay, well, we will finish up our jobs that we committed to, and we'll walk away.  Half an hour, they call back and agreed to it, right?  So clearly, our view is that they got on the phone, called around, and realized that there wasn't anything available.  And another one with a much bigger customer said that they wanted to add additional rigs.  They were trying to use that as a bargaining chip for basically a volume discount.  We very quickly said we'll talk about additional rigs only, until we get our first pricing, basically the first wave of price increases.  It's been a multiple conversation event, but I think we’re getting there.” – Stuart Bodden, President & CEO, Ranger Energy Services [Q3]ConclusionMercer Capital has its finger on the pulse of the oil and gas sector.  As upstream operators, mineral aggregators, and the OFS operators that support them regain their footing, we take a holistic perspective to bring you thoughtful analysis and commentary regarding the hydrocarbon stream. For more targeted energy sector analysis to meet your valuation needs, please contact the Mercer Capital Oil & Gas Team.
Desert Peak to Go Public via Merger With Falcon After IPO Attempt
Desert Peak to Go Public via Merger With Falcon After IPO Attempt
Desert Peak Minerals and Falcon Minerals Corporationrecently announced an all-stock merger, forming a pro form a ~$1.9 billion mineral aggregator company. This comes in the wake of Desert Peak’s attempted IPO in late 2021. In this post, we look at the transaction terms and rationale, the implied valuation for Desert Peak, and implications for the mineral/royalties space.Transaction OverviewThe merger will combine Falcon’s ~34,000 Eagle Ford and Appalachia net royalty acres with Desert Peak’s ~105,000 acre Delaware and Midland position, resulting in a combined company with ~139,000 net royalty acres. Approximately 76% of the company’s acreage position will be in the Permian, with 15% in the Eagle Ford and 9% in Appalachia. Pro forma Q3 2021 production was 13.5 mboe/d, which moves Falcon from the smallest (by production) publicly traded mineral aggregator in Mercer Capital’s coverage to number four, leapfrogging Dorchester and Brigham.The transaction is expected to close during the second quarter of 2022, at which time legacy Falcon shareholders would own ~27% of the company, while legacy Desert Peak shareholders would own ~73%. The combined company will be managed by the Desert Peak team and headquartered in Denver.Going forward, one of the key strategies of the company appears to be M&A. The company seeks “to become a consolidator of choice for large-scale, high-quality mineral and royalty positions” and touted its “strategic, disciplined, and opportunistic acquisition approach” in presentation materials.The company also highlighted its ESG credentials, noting the diversity of its workforce and structural economic disincentives for flaring gas. However, most ESG discussions focused on the often-neglected G – governance. Management incentive compensation is expected to be 100% in the form of equity with an emphasis on total shareholder returns, rather than relative returns or growth metrics.Desert Peak Implied ValuationDesert Peak was pursuing an IPO in late 2021, looking to raise $200 to $230 million at an implied enterprise value of $1.2 to $1.4 billion, based on Mercer Capital’s analysis of Desert Peak’s S-1 filing. However, the deal was postponedin November and ultimately withdrawn in January.Based on Falcon’s stock price immediately preceding the announcement, the merger terms imply an enterprise value of $1.4 billion for Desert Peak, slightly higher than the valuation implied by the top-end of the IPO range. However, Falcon’s stock price has slid since then, bringing Desert Peak’s implied valuation back in line with the mid-point of the IPO range.Implied valuations and relevant multiples are shown in the following table.IPO stock price reflects midpoint of $20 to $23 range indicated in Desert Peak’s S-1. Merger stock price reflects Falcon's closing stock price as of 1/11/2022 (immediately preceding merger announcement). Current stock price reflects Falcon's closing stock price as of 1/19/2022.IPO shares pro forma for anticipated IPO offering. Other figures reflect the number of Falcon shares to be issued to Desert Peak.IPO net debt pro forma for anticipated transaction proceeds, as indicated in Desert Peak’s S-1. Other figures reflect net debt as disclosed in the transaction press release.Metric per transaction press release (as of 9/30/2021).Metric per transaction presentation (as of 9/30/2021). Multiple calculated on a dollar per flowing barrel equivalent basis ($/boe/d).Metric per Desert Peak S-1 (pro forma as of 12/31/2020). Multiple calculated on a dollar per barrel equivalent basis ($/boe).Metric per Desert Peak S-1 (pro forma as of 12/31/2020).Metric per transaction presentation.ImplicationsDesert Peak's inability to complete its IPO highlights the lack of appeal of oil & gas assets among generalist investors, which is not welcome news for an industry facing capital headwinds and a dearth of IPO activity. However, Desert Peak was able to structure a new deal at essentially the same valuation should give mineral and royalty owners confidence that logical buyers can be found.ConclusionWe have assisted many clients with various valuation needs in the upstream oil and gas space for both conventional and unconventional plays in North America, and around the world. Contact a Mercer Capital professional to discuss your needs in confidence and learn more about how we can help you succeed.
What a Difference a Year Makes: Part II
What a Difference a Year Makes: Part II

Analyst Projections

In our prior Energy Valuation Insights post – What a Difference a Year Makes –  Mercer Capital’s Bryce Erickson dug into the key aspects of the energy industry during 2021, including oil and gas pricing, stock price performance, rig counts, production levels, capital spending, and LNG facility development.  It’s well worth a read!In today’s post, we continue the “what a difference a year makes” theme, but now with a focus on analyst projections, then-and-now (then being as of year-end 2020, and now being as of year-end 2021) and energy stock valuation multiples.For the purpose of our analysis, we utilized the Capital IQ system and identified publicly traded energy companies, trading on the NYSE and NASDAQ exchanges, and operating in three broad areas – exploration and production (E&P), oilfield services (OFS), and midstream.The resulting pool included 44 E&P, 32 OFS, and 29 midstream companies1,227 forward (i.e., for the next year) revenue estimates were included in the analysis – 666 as of year-end 2020, and 561 as of year-end 20211,735 forward EBITDA (earnings before interest, taxes depreciation and amortization) estimates were included in the analysis – 854 as of year-end 2020, and 881 as of year-end 2021Potential survivor bias was eliminated by including the same set of companies as of both year-end 2020 and 2021So, What Are the Analysts Expecting?Exploration & ProductionWe’ll start at the drill bit end of the industry – the E&P companies.  Revenue growth expectations (233 and 201 analyst estimates as of year-end 2020 and 2021, respectively) actually didn’t change significantly.  As of year-end 2020 the median estimated 1-year revenue growth was 25.8%, with only a small increase to 29.7% as of year-end 2021.  An improvement certainly, but by no means earth-shaking.  A bit more significant for the E&Ps was a 7.5 percentage point increase in the median estimated EBITDA margin, from 57.7% to 65.2%.  The real “move” in E&P estimates came from the combination of slightly improved revenue growth estimates and EBITDA margin estimates, buoyed by the rise in commodity prices.  Those two estimates “teamed-up” for a mere 17.0% median EBITDA growth estimate at year-end 2020, but a very significant 119.8% median EBITDA growth estimate at year-end 2021.Oilfield ServicesNext up we look to the service and machinery providers to the E&Ps – where we find a much more positive outlook today relative to a year ago.  Last year’s median revenue growth estimates sat in negative territory at -6.3%.  Sentiment was much improved at year-end 2021 with a median revenue growth estimate at 23.9%.  However, OFS EBITDA margins paint a different picture.  Despite the expectation for strong revenue growth, EBITDA margins are expected to actually decline slightly from a year-end 2020 median forecast of 12.8%,d to a current figure of 12.2%.  This implies that while demand and utilization will be strong, pricing power for oilfield service companies will slip somewhat.  The combination of revenue growth and EBITDA margin estimates, though, show a strong improvement in EBITDA growth expectations, from a median expected decline of 5.3% at year-end 2020 to a median expected growth of 34.0% at year-end 2021.  This is not as strong as EBITDA growth expectations among the E&Ps, but a very welcome increase all the same. MidstreamMidstream operators of course are the “Steady Eddies” of the energy industry – that in large part is due to the very nature of the services provided and the more contractual/commitment orientation of the midstream business.  As one would expect, the difference between 2020 and 2021 median analyst estimates are much less material for midstream companies.  Median revenue growth estimates were quite low at only 1.0% at year-end 2020, but improved to a median growth estimate of 7.5% as of year-end 2021.  EBITDA margin estimates actually declined a bit more than those for OFS companies, with a 3.3 percentage point dip from 42.5% at December 2020 to a 39.2% median at December 2021.  In combination, the revenue growth and EBITDA margin estimates result in the median EBITDA growth estimate of 2.1% in December 2020 and a median estimated growth of 9.0% as of December 2021. Valuation MultiplesLastly, in our comparison of year-end 2020 and year-end 2021 within the energy industry we look to valuation multiples across the three energy sectors.  Here we see how the combination of uncertainty of future operating results (risk) and growth expectations combine in the form of enterprise value multiples of EBITDA, on both a trailing (latest twelve months – LTM) and 1-year forward EBITDA basis.  Starting with the midstream companies, we see that modest improvement in revenue expectations and slight reduction in EBITDA margins combine with risk perceptions for fairly modest changes from 2020 to 2021 LTM and forward valuation multiples.  LTM midstream multiples edged up from 9.0x to 10.0x, while the Forward multiples showed an even more modest increase from 8.7x to 9.0x.The negative 2020 EBITDA growth expectations and much larger (than Midstream) 2021 EBITDA growth expectations result in a very different combination of 2020 to 2021 and LTM to forward OFS multiples.  Here we see the median LTM multiple jumping 34% from 2020 to 2021, while the forward multiple decreased by 24%.  That with 2020 forward multiples 32% greater than 2020 LTM multiples, and 2021 forward multiples 50% below 2021 LTM multiples.By far the largest swing in 2020 to 2021 and LTM to forward multiples comes from the E&P companies.  With only modest EBITDA growth expectations as of 2020, the E&P LTM and forward multiples are quite similar at 5.8x and 5.2x, respectively.  However, the 119.8% median estimated EBITDA growth at year-end 2021 results in a much larger LTM to forward differential of 6.7x – 9.7x LTM compared to 3.7x forward.  That high level of EBITDA growth expectations in 2021, compared to the much more modest growth expectation as of 2020 results in a 3.1x differential between 2020 LTM multiples and 2021 LTM multiples (5.8x versus 9.7x).  As with OFS forward multiples, the E&P forward multiples decreased markedly from 2020 to 2021, from 5.2x to 3.7x. In SummaryThe energy industry that was hammered in 2020 by the combined OPEC+ induced oil glut and COVID related oil demand decline showed a mixed bag of marginal and tepid operating result growth expectations at year-end 2020, but is showing much greater expectations as analysts look ahead into 2022.  However, it is the energy industry – so, be ready for the next cycle shift.Mercer Capital has significant experience valuing assets and companies in the energy industry. Our energy industry valuations have been reviewed and relied on by buyers, sellers, and Big 4 Auditors. These energy-related valuations have been utilized to support valuations for IRS Estate and Gift Tax, GAAP accounting, and litigation purposes.  We have performed energy industry valuations domestically throughout the United States and in foreign countries.Contact a Mercer Capital professional today to discuss your valuation needs in confidence.
What a Difference a Year Makes: Part I
What a Difference a Year Makes: Part I

Key Aspects of the Energy Industry in 2021

The close of 2021 marked the end of a long upward march for the energy sector.  With oil closing up the year at $75 (compared to $48 at the end of 2020) and gas at nearly $4 per mmbtu (compared to $2.36 at the end of 2020), the commodity markets driving the energy sector were much more economically attractive to producers.  Stock indices such as the XLE, which primarily tracks the broader energy sector, was up over 50% for 2021 and was by far the best performing sector.  Rig counts, although with more cautious deployment than in the past, rose along with prices and increased by 235 for the year (586 at year-end 2021 vs. 351 at year-end 2020).  Crude production rose to 11.7 million bbls/day with room to grow as inventories were about 7% below the five-year average.  OPEC+ also has signaled it will continue its scheduled output growth.All of this growth is coming alongside the ascent of wind and solar.  The Omicron variant raises uncertainty about the markets and took a cut into prices in December.  However, while COVID may dampen demand growth, most analysts believe it won’t stop it.Prices & Production“We expect Brent prices will average $71/b in December and $73/b in the first quarter of 2022 (1Q22). For 2022 as a whole, we expect that growth in production from OPEC+, of U.S. tight oil, and from other non-OPEC countries will outpace slowing growth in global oil consumption, especially in light of renewed concerns about COVID-19 variants. We expect Brent prices will remain near current levels in 2022, averaging $70/b.” – EIA – December 7, 2021 The steady climb of prices in 2021 reflected a rebound in demand that exceeded earlier expectations.  It also reflected a more cautious approach to bringing more production online and the curtailed capital environment as well.  However, that may not last much longer as more estimates accumulate that suggest capital spending for upstream producers will pick up in 2022. Perhaps even more impactful for upstream producers has been the rise of natural gas prices in 2021 as well.  After languishing for so long, prices not only exceeded  $3.00 per mmbtu they rose to over $5.00 for a brief period. These price levels have been unseen for many years and are anticipated to remain near $4.00 mmbtu in 2022, however, volatility is expected to be higher as well.  Production has increased, particularly in Appalachia and has now reached pre-pandemic levels. Perhaps in 2022 the restraint will come off on production efforts more than the past few years.  According to the Dallas Fed Energy Survey 75% of companies surveyed plan to spend more in 2022 vs. 49% in the same survey given at the end of 2020.  Cowen & Co. says the E&P companies it tracks plan to spend 13% more in 2022 vs. 2021 after significant drops of 48% in 2020 and 12% in 2019.  Much of this growth vigor is fueled by smaller E&P companies that have struggled so much in recent years.  However, there is still a lot of uncertainty with inflation and other issues which are keeping larger companies more conservative with their capital as reflected in comments like this: “Supply-chain issues continue to create logistical challenges, and it is difficult to plan and/or coordinate upstream operational activity.  Labor shortages have contributed to this issue as well.  Pandemic worries are definitely impacting the oil demand side, with resultant uncertainty with respect to commodity pricing and supply forecasting.” – Dallas Fed Respondent For larger companies, debt reduction and quality asset acquisitions are a higher priority as opposed to riding the drill bit. LNG Delays - But Rest Assured, It Is ComingOne of the outlets for production growth has been the development of LNG facilities along the Gulf Coast.  At the end of 2020, there were five (5) facilities under construction.  Unfortunately, as of the end of 2021, only one of those terminals got finished.  There are still four (4) terminals under construction and no other approved terminals (there are 13 of those) have gotten going as well.  This has inhibited production growth for natural gas as LNG is a major global demand growth outlet for U.S. production.  The pandemic has delayed bringing online over eight (8) Bcfd of processing capacity.  The Biden administration has also not made it any easier either.  However, more should come online in 2022 which should help continue the growth trend for gas in the U.S.Regulatory PrognosticationsSpeaking of the Biden administration, last year around the election we were discussing some potential policy and impacts of a Biden administration.  Several of those potentials have come to pass such as permit rejections, the stoppage of the Dakota Access Pipeline, and a decline in drilling on federal lands.One thing that has not borne out is the projection by some of a decline in oil production of as much as two million b/d by 2025.  Production has held strong so far as prices increased in 2021.  Considering the volatility in both regulation and markets, that’s pretty good in the prediction department.
EP First Quarter 2022 Eagle Ford
E&P First Quarter 2022

Eagle Ford

Eagle Ford // Oil prices rose through the quarter as increased demand was met with continued producer restraint.
The Best of 2021
The Best of 2021

Energy Valuation Insights’ Top Blog Posts

After an extraordinarily challenging 2020, 2021 gave Oil & Gas companies some respite and (perhaps most importantly) some optimism going into 2022.  As we enter the new year, we look back at to see what was popular with you ­– our readers.  Below is a list of some of our top posts of 2021.Solvency Opinions: Oil & Gas ConsiderationsIn this post,David Smith covers key aspects of solvency opinions.  Regardless of whether a company files for Chapter 11, is party to an M&A transaction, or executes some other form of capital restructuring – such as new equity funding rounds or dividend recaps – one fundamental question takes center stage: Will the company remain solvent?Recent SPAC Boom Largely Leaves Out Oil & Gas CompaniesWhile the mania around SPACs (special purpose acquisition companies) has subsided since its peak in early 2021, SPACs continue to be a key driver of capital markets activity. Alex Barry looks at oil & gas companies that were early adopters of the SPAC structure, the recent pivot of SPACs towards energy transition companies, and looks forward to see what the future might hold for the few remaining oil & gas-focused SPACs.Mineral Aggregator Valuation MultiplesAn important trend in the mineral and royalty ownership space has been the rise of mineral aggregators, which have largely supplanted the trusts as the primary method of publicly traded minerals ownership.  Due to a variety of corporate structures and complex capital structures, mineral aggregator values pulled from databases are often missing meaningful components, leading to skewed valuation multiples.  Mercer Capital has thoughtfully analyzed the corporate and capital structures of publicly traded mineral aggregators to derive meaningful valuation multiples on a historical and forward-looking basis.  Look back at data fromMarch, May, August, andNovemberof 2021.The Evolution of E&P ESG ScoresWhile oil & gas and ESG (environmental, social, and governance) investing may seem at odds with each other, operators have increasingly included ESG talking points in their management commentary, signaling a proactive initiative rather than reactive response.  Justin Ramirez discusses ESG criteria among E&P operators and looks at trends from 2016 to 2020.Upstream Producers Are Not Gouging–They’re Tentative. Here Are Three Reasons WhyAs commodity prices have risen and profits have rolled in, so have accusations of price gouging by oil & gas companies.  Despite higher prices, producers haven’t materially increased production or announced aggressive drilling plans.  Bryce Erickson identifies some of the reasons why, including supply and demand dynamics, rising costs, and capital headwinds.ConclusionWe look forward to 2022 and appreciate your interest in this blog.  May you and your family enjoy a happy and prosperous year!
Mercer Capital's 2021 Energy Purchase Price Allocation Study
Mercer Capital's 2021 Energy Purchase Price Allocation Study

In Case You Missed It

Did you miss Mercer Capital's 2021 Energy Purchase Price Allocation Study? If you did, before we move into 2022, take a look at the 2021 Study.This study researches and observes publicly available purchase price allocation data for three sub-sectors of the energy industry: (i) exploration & production; (ii) oilfield services; and (iii) midstream and downstream.  This study is unlike any other in terms of energy industry specificity and depth.The 2021 Energy Purchase Price Allocation Study provides a detailed analysis and overview of valuation and accounting trends in these sub-sectors of the energy space.  This study also enables key users and preparers of financial statements to better understand the asset mix, valuation methods, and useful life trends in the energy space as they pertain to business combinations under ASC 805 and GAAP fair value standards under ASC 820.  We utilized transactions that closed and reported their purchase allocation data in calendar year 2020.This study is a useful tool for management teams, investors, auditors, and even insurance underwriters as market participants grapple with ever-increasing market complexity.  It provides data and analytics for readers seeking to understand undergirding economics and deal rationale for individual transactions.  The study also assists in risk assessment and underwriting of assets involved in these sectors. Further, it helps readers to better comprehend financial statement impacts of business combinations.>> DOWNLOAD THE STUDY <<
Appalachian Production Stable Despite Price Volatility
Appalachian Production Stable Despite Price Volatility
The economics of Oil & Gas production vary by region. Mercer Capital focuses on trends in the Eagle Ford, Permian, Bakken, and Marcellus and Utica plays. In this post we take a closer look at the trends in the Marcellus and Utica.Production and Activity LevelsEstimated Appalachian production (on barrels of oil equivalent, or “boe,” basis) decreased approximately 1% year-over-year through December. Production in the Permian and Eagle Ford increased 14% and 4% year-over-year, respectively, while the Bakken’s production declined 1%. Despite a much-improved commodity price environment, Appalachian production was very stable, driven by producers’ capital discipline and the fact that the region was largely unaffected by Winter Storm Uri that disrupted power supplies throughout Texas in February 2021. There were 41 rigs in the Marcellus and Utica as of December 10th, up 37% from December 4th, 2020. Bakken, Eagle Ford, and Permian rig counts were up 145%, 91%, and 74%, respectively, over the same period. One may wonder why Appalachia production has been relatively flat while the region’s rig count has increased. The answer has to do with legacy production declines and new well production per rig. Based on the U.S. Energy Information Administration (“EIA”) data, the Marcellus and Utica need roughly 37 rigs running to offset existing production declines. Relative to last year, most of Appalachia’s additional rigs came online in January and February. Since then, the total rig count has generally ranged between 36 and 40 (in line with the maintenance level). As such, production growth will likely be modest without additional rigs. Commodity Price Volatility ReturnsOil prices slowly and steadily rose through the first two quarters of the year as the vaccine rollout, and lower COVID case counts spurred economic activity. Oil prices were more volatile in the third quarter as the Delta variant caused an increase in COVID cases and concerns regarding the economic recovery. U.S. COVID cases peaked in early September, giving oil prices a boost during the latter part of the quarter. The net result is that WTI front-month futures prices began and ended Q3 at about the same place – approximately $75/bbl. In October, the upward price momentum continued in the fourth quarter as WTI futures prices nearly reached $85/bbl.This optimism was short-lived as the discovery of the new Omicron variant sent oil prices plunging in November. Prices rebounded in December as research has shown that, while highly transmissible, the Omicron variant typically results in less severe illness relative to previous variants. As of December 14th, WTI front-month futures price settled at $70.52/bbl. Going forward, the EIA expects prices to be flat to down in the near term as “growth in production from OPEC+, of U.S. tight oil, and from other non-OPEC countries will outpace slowing growth in global oil consumption, especially in light of renewed concerns about COVID-19 variants.” Natural gas prices steadily increased during the first three quarters of the year, which the EIA primarily attributes to “growth in liquefied natural gas (LNG) exports, rising domestic natural gas consumption for sectors other than electric power, and relatively flat natural gas production.” So far in the fourth quarter, natural gas prices have been relatively volatile as inventories are lower than recent averages. However, recent mild weather has resulted in less gas used for heating. Financial PerformanceThe Appalachia public comp group saw relatively strong stock price performance over the past year (through December 14th). The beneficial commodity price environment was a significant tailwind to smaller, more leveraged producers like Antero Resources and Range Resources, whose stock prices increased 230% and 155%, respectively, during the past year, outperforming the broader E&P sector (as proxied by XOP, which rose 59% during the same period). Larger, less leveraged players like EQT and Coterra (formerly Cabot) were laggards, with their stock prices increasing by 53% and 16%, respectively.Senator Warren Lashes Out Over High Natural Gas PricesMassachusetts Senator Elizabeth Warren wrote a strongly worded letter to eleven natural gas producers, including Appalachia E&Ps EQT, Coterra, Antero Resources, Ascent Resources, Southwestern, and Range Resources. According to Senator Warren’s press release, the purpose of the letter was to “[turn] up the heat on big energy companies’ greed as they jack up natural gas prices, exporting record amounts to boost profits while Americans foot the bill” despite the fact that natural gas producers are simply price-takers, selling a commodity into a competitive market with essentially no control over prices.It is true that LNG exports from the United States have increased dramatically over the past several years. However, that has been driven by the construction and completion of LNG export facilities, resulting in part by continued resistance to pipelines that would connect the Marcellus and Utica regions to East Coast population centers. And while Senator Warren criticized producers for their greed, “putting their massive profits, share prices and dividends for investors … ahead of the needs of American consumers,” she did not thank E&P companies for their previous largesse (or lack of capital discipline) in which natural gas prices were often below $2/mmbtu and numerous natural gas producers went bankrupt.EQT publicly responded to Senator Warren’s letter. Despite the recent run-up in natural gas prices “as the economic engines of the world have reignited,” the company cited that current prices are “significantly below the 20-year average of approximately $5.70 per Mcf.” As a result of the shale revolution, “the United States consumer has benefited from, and continues to benefit from, some of the lowest natural gas prices in the world.” The remainder of EQT’s response was primarily focused on natural gas’s green credentials. Toby Rice, EQT’s CEO, wrote that the United States led the world in CO2 emissions reduction from 2005 to 2020 largely as a result of replacing coal power plants with natural gas power plants. If the world wants to reduce emissions, there are no alternatives with the scale and speed of switching power generation from coal to gas. But with 91% of coal-fired power generation located outside the United States, the transition will require exports of U.S. natural gas to countries without their supply.ConclusionAppalachia production was largely unaffected by the wild commodity price ride we’ve experienced, driven by investor emphasis on capital discipline, the current rig count, and uncertainty. However, with higher natural gas prices, global demand for a lower-carbon alternative to coal, and political pressure, it will be interesting to see if Appalachia producers maintain their restraint.We have assisted many clients with various valuation needs in the upstream oil and gas space for both conventional and unconventional plays in North America and worldwide. Contact a Mercer Capital professional to discuss your needs in confidence and learn more about how we can help you succeed.
M&A in Marcellus & Utica Basins
M&A in Marcellus & Utica Basins

Activity in 2021 Was Muted Relative to 2020

The three transactions in the Marcellus & Utica basins over the past year were just a trickle compared to the 16 transactions reported in the prior year for the Appalachian basins.  The number of transactions in 2020 was more than double the seven transactions in 2019, driven in part by the relative price stability of natural gas as compared to oil which would naturally tend to favor M&A activity in these gas-heavy basins.  One key observation of the transactions in 2020 was that companies were making critical decisions regarding where to operate on a forward-looking basis.  Companies, such as Shell, took the position of divesting their Appalachia assets, while other companies, such as EQT, chose to augment their Appalachian footprint.  The following table summarizes transaction activity in the Marcellus & Utica in 2020: Appalachia transactions announced so far in 2021 are shown in the following table: The decline in transaction activity in 2021 most likely indicates that anyone looking to get into or out of the Appalachian basins effectively did so in 2020, or was concerned with natural gas price volatility, which increased sharply in 2021 after several years of relative calm.  However, that is not to say that the activity in 2021 was any less interesting.  Notable changes in the statistics between the transactions in 2020 and 2021 include a sizable increase in the median and average deal values, price per acre, and price per production unit.  Based on the much smaller sample size of 2021, the magnitude of these differences probably doesn’t mean too much.  But one metric, production per acre (or MMcf/Acre), on an annualized basis, could be indicative of a greater focus on obtaining more productive assets in 2021 than the transactions observed in 2020. The following table summarizes the estimated annualized production per acre, including the median and average values, for the transactions in 2020 and 2021: Buyers in 2021 seemed to target producing rather than prospective, assets, as indicated by, as indicated by the median and average annualized MMcf/Acre metrics.  Irrespective of the smaller transaction count (sample size) in recent history, the minimum production density metric in 2021 (0.71 MMcf/Acre) was nearly 9% greater than the maximum metric observed in the 2020 transactions (0.65 MMcf/Acre), and 52% and 82% higher than the median (0.47 MMcf/Acre) and average ( 0.39 MMcf/Acre) metrics, respectively, observed among the transactions in 2020. Again, this back-of-the-napkin statistical analysis may fall far short of being arguably significant, technically speaking, but it’s pretty interesting as far as an eyeball test is concerned. EQT Corporation Adds to Core Marcellus Asset BaseOn May 6, EQT Corporation (NYSE: EQT)announced that it entered into a purchase agreement with Alta Resources Development, LLC (“Alta”), pursuant to which EQT would acquire all of the membership interests in Alta's upstream and midstream subsidiaries for approximately $2.93 billion.  EQT intended to finance the acquisition with $1.0 billion in cash, drawing upon its revolving credit facility and/or through one of more debt capital market transactions, and stock consideration consisting of approximately 105 million EQT common shares, representing $1.93 billion.  The asset was comprised of approximately 300,000 core acres positioned in the northeast Marcellus region.  Net production as of the transaction date was approximately 1.0 Bcfe per day, comprised of 100% dry gas.  The transaction also included 300-miles of owned and operated midstream gathering systems and a 100-mile freshwater system with 255 million gallons of storage capacity.  Toby Rice, President and CEO of EQT, stated that the acquisition represents an attractive entry into the northeast Marcellus while accelerating the company’s deleveraging path, providing attractive free cash flow per share accretion for EQT shareholders and adding highly economic inventory to the company’s robust portfolio.  Mr. Rice also noted the transaction increases the company’s long-term optionality, and should accelerate its path back to investment grade metrics while simultaneously achieving its shareholder return initiatives.Northern Oil and Gas, Inc. Acquires Non-Operated Appalachian AssetsOn February 3, Northern Oil and Gas (NYSEAM: NOG) agreed to acquire certain non-operated natural gas assets in the Appalachian basin from Reliance Marcellus, LLC (“Reliance”), a subsidiary of Reliance Industries, Ltd., for total consideration of $175 million in cash and approximately 3.25 million warrants to purchase shares of NOG common stock at an exercise price of $14.00 per share.  The transaction was expected to be funded through a combination of equity and debt financings and anticipated to be leverage neutral on a trailing basis and leverage accretive on a forward basis.  At the effective date of July 1, 2020, the acquired assets were producing approximately 120 MMcfe/d of natural gas equivalents, net to Northern Oil and Gas.  The assets were expected to produce approximately 100?110 MMcfe/d (or approximately 19,000 Boe/d) in 2021, net to Northern Oil and Gas, and consisted of approximately 64,000 net acres containing approximately 102.2 net producing wells, approximately 22.6 net wells in process, and approximately 231.1 net undrilled locations in the core of the Marcellus and Utica plays.  Furthermore, an inventory of 94 gross highly-economic, work-in-progress (“WIP”) wells was slated for completion over the following five years by EQT.  As of the transaction announcement, approximately $50 million of net development capital had already been deployed on the WIP wells, which was not subject to reimbursement by Northern Oil and Gas.  The acquisition complemented Northern Oil and Gas’s then-existing approximate 183,000 net acreage portfolio in the Williston and Permian basins.  As of year-end 2020, the acquired assets held an estimated 493 Bcf of proved reserves, of which approximately 55% were comprised of PDP reserves, with PV-10 of $269 million (at strip pricing as of January 20, 2021).Nick O’Grady, Northern Oil and Gas’s CEO, commented, “This transaction furthers our goal of becoming a national non-operated franchise with low leverage, strong free cash flow and a path towards returning capital to shareholders.  With this transaction, we expect increased opportunities to efficiently allocate capital and diversify risk, our commodity mix and geographic footprint.”ConclusionM&A transaction activity in the Marcellus & Utica shrank in number in 2021 relative to 2020.  However, the relatively greater magnitude of production density represented by the transactions in 2021 could prove to be a bellwether of more “transformational” transactions to come in 2022 as companies stake their claim in the gas and gas liquids rich basins of Appalachia.We have assisted many clients with various valuation needs in the upstream oil and gas industry in North America and around the world.  In addition to our corporate valuation services, Mercer Capital provides investment banking and transaction advisory services to a broad range of public and private companies and financial institutions.  We have relevant experience working with companies in the oil and gas space and can leverage our historical valuation and investment banking experience to help you navigate a critical transaction, providing timely, accurate and reliable results.  Contact a Mercer Capital professional to discuss your needs in confidence.
Mineral Aggregator Valuation Multiples Study Released (2)
Mineral Aggregator Valuation Multiples Study Released

With Market Data as of November 29, 2021

Mercer Capital has its finger on the pulse of the minerals market.  An important trend has been the rise of mineral aggregators, which have largely supplanted the trusts as the primary method of publicly traded minerals ownership.Due to a variety of corporate structures (including master limited partnerships and Up-Cs) and complex capital structures (including preferred equity and non-traded common units), mineral aggregator enterprise values pulled from databases are often missing meaningful components of value, leading to skewed valuation multiples.Mercer Capital has thoughtfully analyzed the corporate and capital structures of the publicly traded mineral aggregators to derive meaningful indications of enterprise value.  We have also calculated valuation multiples based on a variety of metrics, including distributions and reserves, as well as earnings and production on both a historical and forward-looking basis.Mineral Aggregator Valuation Multiples StudyMarket Data as of November 29, 2021Download Study
Themes from Q3 Earnings Calls
Themes from Q3 Earnings Calls

Part 1: E&P Operators

In Part I of our Themes from Q2 Earnings, an overarching narrative was an oil and gas industry reaching a relatively steady operational state, with efficiencies offsetting cost inflation and helping lead to growth in free cash flow despite the tumultuous past 18 to 24 months.  These factors allowed most E&P operators to deleverage, and in some cases, also resume or increase their return of capital (either via dividends or share buybacks) to shareholders.  In the latest earnings calls, these themes continue as the primary focus as we head towards year-end 2021.  Some of the talking points in the Q3 earnings calls continue on the same trajectory as in Q2, such as maintaining capital discipline with flat or low growth in production volumes.  However, there was more variance in the latest round of calls regarding E&P operators' possible approaches to fortify their value proposition to shareholders.Natural Gas ExportsAs noted in our recent blog post regarding natural gas prices and production levels, demand for U.S. LNG exports from European and Asian (primarily China) markets have resulted in elevated prices for natural gas despite the relatively high level of gas production coming from U.S. basins.  This particular topic came up in several of the Q3 calls."We've talked in the past about the nearly 550,000 barrel a day increase in petchem demand in China from 2021 to 2023 and over 110,000 barrels a day of European and North American PDH growth during that same time period.  What many did not anticipate was the global pressure for hydrocarbons this fall and winter that resulted in elevated LNG prices in Europe and Asia.  This is driving additional demand for LPG in these markets through its use in industrial heating and power applications in lieu of today's high cost of natural gas.  On a BTU equivalent basis, LPG is nearly half the price of LNG delivered in the Far East markets.  The impact from this incremental demand for LPG is a widening export arb." – David Cannelongo, Vice President of Liquids Marketing & Transportation, Antero Resources"We're going to continue to look at new opportunities from an LNG standpoint and are very well-positioned.  Again, it gets back to our transport, our export capacities, and just having that ability to transact, we can definitely be very nimble as we think about new opportunities." – Lance Terveen, Senior Vice President – Marketing, EOG ResourcesMany Paths to the Value PropositionPerhaps the most significant divergence in the Q3 E&P operator calls compared to the Q2 calls stemmed from how the management teams viewed their value proposition to shareholders.  Global energy prices were shaken in early 2020 with the onset of the COVID-19 pandemic, with prices retreating further when the discussions regarding renewal of the OPEC+ production/price cooperation pact, a 3-year plan that was set to expire at the end of Q1 2021, fell apart as Moscow refused to support Riyadh's demand for additional production cuts.  As energy prices recovered amid a background of heightened uncertainty in the global economic and financial markets, E&P operators tightened their belts and took this opportunity to enact highly disciplined capital programs in order to extract greater free cash flow from flat production levels.For some companies, the value proposition to shareholders remains focused on either increasing the intrinsic value per share via share repurchases or returns to shareholders through dividend programs."As we continue to trade at a material discount to our intrinsic per share value as we see it, we steadily increased our attention on share count reduction.  And Q3 was a good example of this.  Approximately 60% of free cash flow was returned to shareholders in the form of buybacks.  We continue to see a significant opportunity to retire additional shares in what we believe to be currently attractive prices.  And as a result, on October 25, earlier this week, the Board has increased our share repurchase authorization by $1 billion, now having a sizable share repurchase authorization at our disposal." – Nicholas Deluliis, President & CEO, CNX Resources"I don't want to get ahead of my Board, but I would say at Murphy, we're more tuned to dividend and getting our dividend back. We're a dividend payer for 60 years.  And that would be best for us.  And, of course, a variable dividend, I suppose, can come into that mix. And I would say at this share count, that would be the basis today." – David Looney, CFO, Murphy Oil For other E&P operators, the name of the game moving forward is flexibility to deliver returns to shareholders through share repurchases and dividend programs."In mid-September, our Board approved a $2 billion share repurchase program.  After that announcement, we repurchased over 268,000 shares at an average share price of $82 for a total cost of $22 million in the third quarter.  If we do not repurchase enough shares in the quarter to equal at least 50% of free cash flow for that particular quarter, then we will make our investors whole by distributing the rest of that free cash flow via a variable dividend.  This strategy gives us the ability to be flexible and opportunistic when distributing capital above and beyond our base dividend, but importantly, at least 50% of free cash flow will be returned." – Travis Stice, CEO, Diamondback Energy Perhaps most interestingly, a handful of companies cited additional sources of future shareholder value, setting their sights on opportunities to be had out in the field, be it through acquisition activity or plans to enhance their exploration program.[Regarding the November 3rd announcement of Continental Resources's agreement to purchase Delaware basin assets from Pioneer Natural Resources] "We focus every day on maximizing both shareholder and corporate returns. The Permian Basin acquisition will be an integral contributor to these shareholder return plans.  Possibly most importantly, this Permian transaction is projected to add up to 2% to our return on capital employed annually over the next five years.  The acquisition of these assets strongly supports the tenants of Continental's shareholder return on investment and return of investment, dividends and share repurchases." – William Berry, CEO, Continental Resources"After weathering two downturns during which we did not cut nor suspend the dividend, the new annual rate of $3 per share reflects the significant improvement in EOG's capital efficiency since the transition to premium drilling.  Going forward, we are confident in our ability to continue adding to our double-premium inventory without any need for expensive M&A by improving our existing assets and adding new plays from our deep pipeline of organic exploration prospects, developing high-return, low-cost reserves that meet our stringent double premium hurdle rate, expands our future free cash flow potential and supports EOG's commitment to sustainably growing our regular dividend." – Ezra Yacob, CEO, EOG ResourcesConclusionMercer Capital has its finger on the pulse of the E&P operator space.  As the oil and gas industry evolves through these pivotal times, we take a holistic perspective to bring you thoughtful analysis and commentary regarding the full hydrocarbon stream.  For more targeted energy sector analysis to meet your valuation needs, please contact the Mercer Capital Oil & Gas Team for further assistance.
Sharing Growth & Spotlight
Sharing Growth & Spotlight

Natural Gas & Renewables Join the D-CEO Awards Stage in Dallas

Mercer Capital’s energy team sponsored and attended the D-CEO 2021 Energy Awards in Dallas last week, October 26, 2021.  It was a great event and a good opportunity to connect with clients, peers, and industry leaders in the energy space.   Awards ranged from honoring top executives, including Scott Sheffield of Pioneer Energy, to private equity firm innovators like Pearl Energy Investments.Oil, Natural Gas, and RenewablesThe focus of the night was the interdisciplinary threads between oil, natural gas, and renewables.  “Sustainability and profitability are not mutually exclusive,” said Vikram Agrawal of EarthxCapital who participated on a panel alongside Joe Foran, CEO of Matador Resources.  According to the panelists, renewables and natural gas are to be watched as the energy mix needs evolve in the U.S. and around the world. As an example, natural gas fuels about 40% of our power in the U.S. according to Agrawal.If the move goes towards more electrification, as illustrated by the news this week that Hertz has ordered 100,000 Tesla electric vehicles, there will be a need for 20% - 40% more power in the next 20 years.  As we’ve discussed before, the current trajectory of renewables appears unable to meet these demand growth needs.  Therefore, cleaner-burning natural gas will be a key contributor.  One panelist mentioned the  exception was hydrogen as a potential contributor.  Interestingly, this was echoed in comments on the latest Dallas Fed Energy Survey:  “The more I become educated on EVs [electric vehicles] and the charging and battery disposal problems, the more I think they will have little effect on the market in the future.  My investigation turns more toward the hydrogen cell as the long-term solution.”No matter what the source, recent price growth suggests that more investments will be needed.  The panel also stated that oil and gas investment will drop 26% from pre-pandemic levels to $356 billion in 2021.  Various sources, including Exxon, suggest that this figure needs to increase to around $600 billion by 2040.Optimism for investment opportunities was not limited to upstream, but also infrastructure, with nearly $18 trillion in investment opportunities for energy transmission alone.Interesting Tidbits & StatisticsWithin the theme of investment opportunities, renewables, and natural gas, several interesting factoids from the evening emerged (in no particular order):1.Electric Vehicles and Charging StationsHow many electric vehicles are there for every charging station in the U.S.? The current ratio is 17Many think this ratio needs to be closer to 10 (there are about 42,000 charging stations in the U.S. right now – many at hotels and other overnight destinations)The Biden Administration suggests we need 500,000. Agrawal thinks the real number is 1,000,000 to 1,500,0002.Electric Cars Are Not a New ThingDid you know that 120 years ago, nearly one-third of our cars were electric?  Granted there were only 4,000 cars at the time.  Did you also know that Thomas Edison invented the first electric-powered car?3.Investment in the Space Is Picking UpSo far this year 35 SPACs acquired businesses worth $100 billion4.   What Do “Net Zero” or “Carbon Offsets” Really Mean? According to a Wall Street Journal article, only 5% of “carbon offsets” actually remove carbon.ConclusionThanks to our clients, friends, and partners that we saw at the event.  It was fabulous and nostalgic to be getting out again!  And thanks to D-CEO for putting on a great event.  Until next time!
Natural Gas Production Levels Are High, But So Are Prices
Natural Gas Production Levels Are High, But So Are Prices
There’s been much coverage of the run-up in oil prices since November 2020, from $37/barrel (WTI) to current prices in excess of $80/barrel.  That of course ignores the April to October 2020 $28/barrel recovery from the Covid/OPEC+/Russia-induced oil price death plunge during the February to April 2020 period. Now it seems that it’s natural gas’s turn at the price run-up game.While Henry Hub (a benchmark for natural gas prices) also showed a post-Covid recovery from its March to June 2020 lows (near $1.60/MMbtu) to prices generally in the $2.60 to $3.00 range from October 2020 to May 2021, it has since been on a run that has taken it to recent highs over $5.70.  So, what gives?  In this week’s blog post, we address the market forces that have led to higher natural gas prices despite near record U.S. natural gas production levels.Production Is High, So Why Are Prices Rising?Per U.S. Energy Information Administration (EIA) data, 3Q2021 U.S. natural gas production neared its prior peak level, and EIA analysts expect that production will reach new record highs during 3Q2022.  With such high production, basic economic theory would suggest that natural gas prices should be facing downward pressure.  However, there’s the demand side of the equation to consider as well.  Since the 2020 Covid-induced demand decline, the increase in natural gas demand has exceeded production recovery.  Therefore, a supply versus demand imbalance has pushed prices up at an unusual rate. Why Not Just Increase Production to Satisfy Demand? A natural question to be asked is, why wouldn’t the gas producers simply increase production to meet the heightened level of demand?  That’s where an interesting set of factors come into play, with one such factor being future gas price expectations.Why wouldn’t gas producers simply increase production to meet demand? Future gas price expectations.Tsvetana Paraskova, writing for OilPrice.com, notes that producers in Appalachia, America’s largest gas-producing basin, are expecting stronger pricing signals in the future curve for gas prices a year or two from now.  As such, to some extent, those producers are looking at to (i) invest now to boost production for which they’ll receive current prices, or (ii) delay that investment to boost production until later when they’re expecting to sell the same volumes at higher prices.  Depending on their level of confidence in those higher future prices, they may be significantly incentivized to hold off on those volume boosting investments. Furthermore, Peter McNally, with the consulting firm, Third Bridge, reminds us that the more recent trend among oil and gas investors in preferring more near-term return on investment (current distributions to investors), rather than more drilling (with larger distributions down the road), has pressured the producers to ease back on their drilling programs that would otherwise help maintain production levels.Where Is Demand Coming From?A natural question to be asked is, where is all the demand side pressure coming from?  The answer, in large part, is exports.  While the U.S. has exported natural gas via pipeline for many years, the capacity for LNG exports has ballooned in recent years and reached record levels in 2020 and 2021. Two regions are driving demand for U.S. LNG exports.  The first is Europe.  After the much colder than usual winter, natural gas inventories remain well below typical seasonal levels.  As a result of the lower inventories, Europeans are paying four to five times as much for natural gas relative to what is being paid in the U.S.  That creates quite the incentive for U.S. produced natural gas to be exported, rather than staying within the country.  The second is China.  Reuters reports that China has become concerned in regard to its country-wide fuel security and is facing a winter fuel supply gap.  That, in the midst of Asian gas prices that have increased more than 400% in 2021, has led to advanced talks between top Chinese energy companies and U.S. LNG exporters for the purpose of locking-in future U.S. LNG export volumes. What Does This Mean for the U.S.?As a result of the indicated supply and demand forces at play, Reuters reports that power crunches are already hitting large economies such as China and India.  While the impact in the U.S. (so far) has been relatively modest, expectations are for U.S. consumers to spend much more to heat their homes this winter.  In the U.S., nearly half of homes use natural gas for heating purposes, as natural gas has traditionally been the most economical source for heating residences.  The U.S. Department of Energy estimates that those homeowners will pay 30% more for natural gas this winter compared to last winter.What Are the Ripple Effects of Higher Natural Gas Prices?While home heating is a more straight-forward result of the higher natural gas prices, there are numerous ripple effects that are far less obvious.  Natural gas is a key input to a number of industries where higher natural gas costs will naturally be passed through to consumers.  Bozorgmehr Sharafedin, Susanna Twidale and Roslan Khasawneh, with Reuters, note several such industries including steel producers, fertilizer manufacturers, and glass makers having been forced to reduce production due to the higher natural gas prices.Industrial Energy Consumers of America, a trade group representing chemical, food and materials manufacturers has even urged the U.S. Department of Energy to limit U.S. LNG exports in order to ease their member firms’ energy-related expenses.  Food producers in particular are reporting shortages of CO2 (a byproduct of fertilizer production) that is used in packaging processes, meat processing, and even for putting the “fizz” in carbonated drinks and beer.  As a result, prices for those types of products are already on the rise.ConclusionAs indicated, the market forces at work in the supply and demand for U.S.-produced natural gas are many, and come from both domestic and foreign sources.  The current supply/demand gap has pushed natural gas prices to recent record levels, with the impacts being both obvious in winter heating costs, and not so obvious in higher food and beverage prices. Keep reading this blog as we continue to track natural gas pricing and other energy-related industry topics.Mercer Capital has significant experience valuing assets and companies in the energy industry. Our energy industry valuations have been reviewed and relied on by buyers, sellers and Big 4 Auditors. These energy related valuations have been utilized to support valuations for IRS Estate and Gift Tax, GAAP accounting, and litigation purposes.  We have performed energy industry valuations domestically throughout the United States and in foreign countries.Contact a Mercer Capital professional today to discuss your valuation needs in confidence.
Chesapeake Finds Vine Ripe for the Picking
Chesapeake Finds Vine Ripe for the Picking
In August, Chesapeake Energy Corporation announced that it would acquire Vine Energy Inc. in a stock-and-cash transaction valued at approximately $2.2 billion.  We previously discussed Vine’s IPO, which was the first upstream (non-minerals, non-SPAC) initial public offering since Berry Petroleum’s debut in mid-2017.  Vine’s decision to be acquired in a ~0% premium transaction less than five months after its IPO speaks to the difficulty for E&P companies to manage public market dynamics even in a much-improved commodity price environment.  In this post, we dig into the transaction rationale, look at relative value measures, and analyze how this transaction seems to indicate a shift in Chesapeake’s strategy.Transaction RationaleChesapeake’s acquisition generally follows the recent upstream M&A playbook: mostly stock, low-to no-premium, and a focus on cost synergies.Cash consideration of $1.20 per share represents 8% of the $15.00 total consideration per share.  It is somewhat curious that there’s a cash component to the purchase, especially for a company that recentlyemerged from bankruptcy in a transaction that doubles the company’s leverage.  However, even with the cash outlay and assumption of Vine’s debt, Chesapeake management indicates that the pro forma entity will have a relatively modest net debt to 2022E EBITDAX ratio of 0.6x.Based on market data, immediately prior to announcement, the transaction consideration represents a <1% premium to Vine’s stock price.  While that may not seem like a great deal for shareholders, the 92% stock consideration means that legacy Vine shareholders should benefit from any synergies achieved by the transaction.  On the announcement date, market reaction was generally positive, with both Vine and Chesapeake outperforming the broader upstream universe (as proxied by the SPDR S&P Oil & Gas Exploration & Production ETF, ticker XOP). As for those synergies, management expects to save $20 million per year on general & administrative and lease operating expenses, with another $30 million per year in capital efficiencies, resulting in an annual savings of $50 million per year. Valuation ConsiderationsRelative value measures for the transaction are shown in the following table: As with any transaction with a stock component, the transaction consideration is dynamic and fluctuates with the acquirer’s stock price.  The initial transaction consideration of $15 per share was only $1 higher than Vine’s IPO price.  But with the run-up in natural gas prices and continued exposure via stock consideration, Vine has recently traded at all-time highs and is now within its initial IPO offer range. Chesapeake Shifts Back to Natural Gas RootsChesapeake has historically focused on natural gas production.  However, in the wake of persistently low natural gas prices from roughly 2010-2020, the company sought to diversify its production mix and become more oil focused.  In pursuit of this goal, the company was particularly active on the M&A and A&D front, with actions including the sale of itsUtica assets in Ohio and acquisition of Eagle Ford producer WildHorse Development Corporation.  Ultimately, the company overextended itself and entered bankruptcy in mid-2020. After emerging from bankruptcy earlier this year, management indicated that investment activity would be focused on natural gas assets.  The timing seems apt with the recent increase in natural gas prices.  The acquisition of Vine will stem Chesapeake’s recent trend of production declines and materially increase its natural gas mix. ConclusionVine’s brief stint as a public company looks to be coming to an end.  With natural gas stealing the spotlight from crude oil, Chesapeake is seeking to return to its former glory as America’s natural gas champion.  The combination with Vine will make Chesapeake a dominate force in the Haynesville and support the company’s pivot away from oil.We have assisted many clients with various valuation needs in the upstream oil and gas space for both conventional and unconventional plays in North America, and around the world.  Contact a Mercer Capital professional to discuss your needs in confidence and learn more about how we can help you succeed.
The Evolution of E&P ESG Scores
The Evolution of E&P ESG Scores

Trends from 2016-2020

As quarterly earnings calls have come and gone over the past several years, the frequency with which environmental, social, and governance topics are explicitly discussed have been ever-increasing.  On the whole, ESG topics are sector and industry agnostic.  While not all ESG topics come into play equally for every sector and industry, there are always some elements, issues or characteristics of any given company or industry that could be put into at least one, if not all, of those three buckets.Within the E&P space–and the oil and gas sector overall–operators have increasingly included ESG talking points in their management commentary, signaling proactive initiative rather than reactive response. One could argue this approach helps to lead the discussion by addressing what they can do, are doing, and will do, as opposed to having to answer to why they are not taking actions to mitigate some issues that were determined or assumed to be a priority by an outside party.Regardless of the impetus for ESG topics entering the zeitgeist, the result is an increase in self-reporting by E&P operators as to what they’re doing to improve, or at least address, noted ESG concerns.Naturally, however, the noble action of self-reporting does not mean the stated or signaled information is accurate or fully reflects all known or knowable information. Of course, it should not be assumed that such information is inherently or purposefully misleading either. Sometimes you take it with a grain of salt; sometimes you empty the shaker or season to taste.Given the potential for obfuscation, though, it helps to have a more objective party discern what information is verifiable and accurate, as far as that may be determinable.  One such platform, S&P’s Global Market Intelligence, provides such ESG evaluation services, including the provision of ESG scores to gauge where companies stand with respect to their self-reporting.In this post, we take a brief look at several ESG criteria among E&P operators to see what trends may be present among the operators with the highest and lowest ESG scores, as provided by Global Market Intelligence.Total ESG ScoresIt is far beyond the scope of this article to explain the machinations and processes that underlie the production of the ESG scores determined by Global Market Intelligence.  For simplicity, we consider the ESG scores in an ordinal and relative way.  For example, if Company A and Company B have ESG scores of 10 and 20, respectively, it is not to say that the self-reporting by Company B is twice as good as Company A’s reporting, but simply that Company B reports more information which can be verified.The other side of the coin is that, in theory, a company could be a model example of ESG stewardship, but still have an ESG score of 0 if it doesn’t self-report or may not provide information that is readily verifiable. This would not be a likely scenario, but again, “in theory…”.Note that, in addition to a company’s “Total” ESG score, there are scores for the respective E, S and G groups, with more granular scores for specific criteria within each of those three buckets.  We will refer to the Total ESG scores, as well as scores for three criteria that represent the environmental, social, and governance groups, respectively.We utilized the Global Market Intelligence platform to screen for U.S. E&P operators with market capitalizations over $10 million (as of October 6), with 124 resulting companies.  We then pared this list down to 12 operators that consistently had annual Total ESG scores from 2016 to 2020 (the latest data available), presented as follows:Click here to expand the image aboveGenerally, the list is presented in ascending order, with the lower-scoring operators towards the top and higher-scoring operators towards the bottom.As may be gleaned from the chart above, the three lowest scoring E&P operators, on average, were Diamondback Energy, Continental Resources, and Coterra Energy.1The three highest scoring operators, on average, were Hess Corporation, ConocoPhillips, and Ovintiv (formerly Encana Corporation).We note that the ESG scores among the lowest-scoring companies all declined from 2016 to 2020, with Continental Resources’ and Coterra Energy’s scores among those with the greatest decline among the entire group of companies presented.  The ESG scores for ConocoPhillips and Hess Corporation were approximately at the 3rd quartile with respect to their “growth”, while Ovintiv’s ESG scores showed a moderate decline from 2016 to 2020.  Although we do not discuss Pioneer Natural Resources in depth here, we do note that it exhibited the greatest growth in its ESG score from 2016 to 2020.E, S, and GAs mentioned earlier, each of the environmental, social, and governance groups have respective subsets of criteria which are surveyed, analyzed, scored, and weighted by Global Market Intelligence.  For example: criteria within the environmental group includes items such as “biodiversity,” “climate strategy,” and “water related risks”; the social group includes criteria such as “social impacts on communities,” “human capital development,” and “human rights”; and the governance group includes criteria such as “brand management,” “marketing practices,” and “supply chain management.”One environmental criterion we looked at was climate strategy, 2  with the company ESG scores as follows:Click here to expand the image aboveOnly 3 companies had ESG scores for this criterion that indicated improvement from 2016 to 2020.  However, the growth between these two periods masks the development of these scores in the interceding periods.  Notably, the score for Diamondback Energy dipped in 2018 and 2019, but returned to the levels seen in 2016 and 2017.  Furthermore, several companies, including EOG Resources, Pioneer Natural Resources, Marathon Oil, and Ovintiv all showed significant improvement in the score from 2019 to 2020.Last, but not least, we reach the criterion selected representing the governance topics: policy influence.3Click here to expand the image aboveAs you will notice, all companies had “NA” in place of scores in 2016, indicating this criterion was not included on the Global Market Intelligence survey that year.  We note that these scores objectively focus on the extent of the verifiable public disclosure related to the companies’ contributions to political campaigns, lobby groups, and trade associations which may influence the policies affecting industry operations and regulations; these scores do not indicate levels of financial contribution or subjective perspectives regarding levels of influence in promoting or interfering with any particular policy.On the HorizonMoving forward, it will be interesting to compare the objective ESG scores with the quantity and quality of the information divulged and discussed in E&P operators’ earnings calls.  Presumably, the ESG scores should rise in tandem with the greater levels of discussion and disclosures in the calls.  We may find out soon enough with the upcoming earnings call season, as Diamondback Energy, Continental Resources, EOG Resources, Pioneer Natural Resources, Marathon Oil, and EQT Corporation regularly make appearances in our quarterly blog post, Earnings Calls - E&P Operators.ConclusionMercer Capital has its finger on the pulse of the E&P operator space.  As the oil and gas industry evolves through these pivotal times, we take a holistic perspective to bring you thoughtful analysis and commentary regarding the full hydrocarbon stream.  For more targeted energy sector analysis to meet your valuation needs, please contact the Mercer Capital Oil & Gas Team for further assistance.1 We note that the results of our company screen included E&P operators which may have had an “na” in place of a Total ESG score in one of the years from 2016 to 2020, in which case these companies were excluded from the companies listed above.  There are several reasons this may occur (most likely, a lack of self-reporting for whatever reason in that particular year), but we selected the presented companies to focus on E&P operators which have made a concerted effort to self-report with consistency in the recent past.2 From Global Market Intelligence: “Most industries are likely to be impacted by climate change, albeit to a varying degree; consequently, they face a need to design strategies commensurate to the scale of the challenge for their industry. While most focus on the risks associated with a changing climate, some seek to identify and seize the business opportunities linked to this global challenge.  The questions in this criterion have been developed in alignment with the CDP methodology as part of a collaboration between us and CDP https://www.cdproject.net.”  We note that CDP is a not-for-profit charity that runs a global disclosure system for investors, companies, cities, states and regions to manage their environmental impacts.3 From Global Market Intelligence: “Although companies legitimately represent themselves in legislative, political and public discourse, excessive contributions to political campaigns, lobbying expenditures and contributions to trade associations and other tax-exempt groups may damage companies’ reputations and creates risks of corruption.  In this criterion, we evaluate the amount of money companies are allocating to organizations whose primary role is to create or influence public policy, legislation and regulations. We also ask for the largest contributions to such groups, and we assess the public disclosure on these two aspects.”
What Is a Reserve Report?
What Is a Reserve Report?
In this blog post we discuss the most important information contained in a reserve report, the assumptions used to create it, and what factors should be changed to arrive at Fair Value[1] or Fair Market Value[2].Why Is a Reserve Report Important?A reserve report is a fascinating disclosure of information. This is, in part, because the disclosures reveal the strategies and financial confidence an E&P company believes about itself in the near future. Strategies include capital budgeting decisions, future investment decisions, and cash flow expectations.For investors, these disclosures assist in comparing projects across different reserve plays and perhaps where the economics are better for returns on investment than others.However, not all the information in a reserve report is forward-looking, nor is it representative of Fair Value  or Fair Market Value. For a public company, disclosures are made under a certain set of reporting parameters to promote comparability across different reserve reports. Disclosures do not take into account certain important future expectations that many investors would consider to estimate Fair Value or Fair Market Value.What Is a Reserve Report?Simply put, a reserve report is a reporting of remaining quantities of minerals which can be recoverable over a period of time. Rules of 2009define these remaining quantities of mineral as reserves. The calculation of reserves can be very subjective, therefore the SEC has provided, among these rules, the following definitions, rules and guidance for estimating oil and gas reserves:Reserves are “the estimated remaining quantities of oil and gas and related substances anticipated to be economically producible;The estimate is “as of a given date”; andThe reserve “is formed by application of development projects to known accumulations”. In other words, production must exist in or around the current project.“In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production of oil and gas”There also must be “installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.”Therefore, a reserve report details the information and assumptions used to calculate a company’s cash flow from specific projects which extract minerals from the ground and deliver to the market in a legal manner. In short, for an E&P company, a reserve report is a project-specific forecast. If the project is large enough, it can, for all intents and purposes, become a company forecast.What Is the Purpose of a Reserve Report?Many companies create forecasts. Forecasts create an internal vision, a plan for the near future and a goal for employees to strive to obtain. Internal reserve reports are no different from forecasts in most respects, except they are focused on specific projects.Externally, reserve reports are primarily done to satisfy disclosure requirements related to financial transactions. These would include capital financing, due diligence requirements, public disclosure requirements, etc.Publicly traded companies generally hire an independent petroleum engineering firm to update their reserve reports each year and are generally included as part of an annual report. Like an audit report for GAAP financial statements, independent petroleum engineers provide certification reserve reports.Investors can learn much about the outlook for the future production and development plans based upon the details contained in reserve reports. Remember, these reserve reports are project-specific forecasts. Forecasts are used to plan and encourage a company goal.How Are Reserve Reports Prepared?Reserve reports can be prepared many different ways.  However, for the reports to be deemed certified, they must be prepared in a certain manner.  Similar to generally accepted accounting principles (GAAP) for financial statements, the SEC has prepared reporting guidance for reserve reports with the intended purpose of providing “investors with a more meaningful and comprehensive understanding of oil and gas reserves, which should help investors evaluate the relative value of oil and gas companies.” Therefore, the purpose of SEC reporting guidelines is to assist with project comparability between oil and gas companies.What Is in a Reserve Report?Reserve reports contain the predictable and reasonably estimable revenue, expense, and capital investment factors that impact cash flow for a given project. This includes the following:Current well production: Wells producing reserves.Future well production: Wells that will be drilled and have a high degree of certainty that they will be producing within five years.Working interest assumption: The ownership percentage the Company has within each well and project.Royalty interest assumptions: The royalty interest paid to the land owner to produce on their property.Five-year production plan: All the wells the Company plans to drill and have the financial capacity to drill in the next five years.Production decline rates: The rate of decline in producing minerals as time passes. Minerals are a depleting asset when producing them and over time the production rate declines without reinvestment to stimulate more production. This is also known as a decline curve.Mineral price deck: The price at which the minerals are assumed to be sold in the market place.  SEC rules state companies should use the average of the first day of the month price for the previous 12 months. Essentially, reserve reports use historical prices to project future revenue.Production taxes: Some states charge taxes for the production of minerals.  The rates vary based on the state and county, as well as the type of mineral produced.Operating expenses for the wells: This includes all expenses anticipated to operate the project. This does not include corporate overhead expenses. Generally, this is asset-specific operating expenses.Capital expenditures: Cash that will be needed to fund new wells, stimulate or repair existing wells, infrastructure builds to move minerals to market and cost of plugging and abandoning wells that are not economical.Pre-tax cash flow: After calculating the projected revenues and subtracting the projected expenses and capital expenditures, the result is a pre-tax cash flow, by year, for the project.Present value factor: The annual pre-tax cash flows are then adjusted to present dollars through a present value calculation. The discount rate used in the calculation is 10%. This discount rate is an SEC rule, commonly known as PV 10. The overall assumption in preparing a reserve report is that the company has the financial ability to execute the plan presented in the reserve report. They have the approval of company executives, they have secured the talent and capabilities to operate the project, and have the financial capacity to complete it. Without the existence of these expectations, a reserve report could not be certified by an independent reserve engineer.ConclusionMercer Capital has significant experience valuing assets and companies in the energy industry. Because drilling economics vary by region it is imperative that your valuation specialist understands the local economics faced by your E&P company.  Our oil and gas valuations have been reviewed and relied on by buyers and sellers and Big 4 Auditors. These oil and gas related valuations have been utilized to support valuations for IRS Estate and Gift Tax, GAAP accounting, and litigation purposes.  We have performed oil and gas valuations and associated oil and gas reserves domestically throughout the United States and in foreign countries.Contact a Mercer Capital professional today to discuss your valuation needs in confidence.Endnotes[1] “The price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.” – FASB Glossary[2] “The price at which the property would change hands between a willing buyer and a willing seller, neither being under any compulsion to buy or to sell and both having reasonable knowledge of relevant facts” – U.S. Treasury regulations 26 C.F.R. sec. 20.2031-1(b)
EP Fourth Quarter 2021 Appalachian Basin
E&P Fourth Quarter 2021

Appalachian Basin

Appalachian Basin // The fourth quarter of 2021 marked a recent milestone in a long upward march for energy prices.
Bakken Recovery Falters
Bakken Recovery Falters
The economics of Oil & Gas production vary by region. Mercer Capital focuses on trends in the Eagle Ford, Permian, Bakken, and Marcellus and Utica plays. The cost of producing oil and gas depends on the geological makeup of the reserve, depth of reserve, and cost to transport the raw crude to market. We can observe different costs in different regions depending on these factors. This quarter we take a closer look at the Bakken.Production and Activity LevelsEstimated Bakken production (on a barrels of oil equivalent, or “boe” basis) decreased approximately 4% year-over-year through September.  Production in the Permian and Appalachia increased 10% and 3% year-over-year, respectively, while the Eagle Ford’s production declined 2%.  While production in the Bakken rebounded sharply once wells were brought back online aftercurtailments in mid-2020, it has generally trended lower during 2021.  Production in the Eagle Ford and Permian was meaningfully impacted in February 2021, driven by Winter Storm Uri that disrupted power supplies throughout Texas. As of September 17th, there were 23 rigs in the Bakken up 156% from September 11, 2020.  Eagle Ford, Permian, and Appalachia rig counts were up 300%, 109%, and 34%, respectively, over the same period. One may wonder why Bakken production has been on the decline given substantial rig count growth, while Permian production has continued to increase despite a more moderate increase in rigs.  The answer has to do with legacy production declines and new well production per rig.  Based on data from the U.S. Energy Information Administration, the Bakken needs roughly 19 rigs running to offset existing production declines.  That number for the Permian is approximately 200 rigs.  The Bakken’s rig count only recently broke above that maintenance level of drilling, whereas the Permian has had over 200 active drilling rigs since February 2021.  Current activity in the Bakken should stem the recent production declines, but growth will likely be modest without additional rigs. Oil Stabilizes while Natural Gas SoarsAfter a significant run-up in the first two quarters of the year, oil prices were largely range-bound during the third quarter of 2021, with front-month futures prices for West Texas Intermediate (WTI) generally oscillating between $65/bbl and $75/bbl.  Rising COVID-19 cases in the U.S. caused the Delta variant to put a damper on travel activity and associated fuel consumption.  However, producers seem to be maintaining their capital discipline even in light of higher prices, which is limiting production growth.  Henry Hub natural gas front-month futures prices began the quarter at approximately $3.63/mmbtu but broke above $5.00/mmbtu in September.  The current run-up in natural gas prices has some concerned about what the winter may hold, when prices generally increase due to heating demand.  In Europe, declining coal capacity and less-than-expected wind generation from North Sea wind turbines have contributed to surging natural gas prices, and the situation is beginning to impact industrial production. However, the current commodity price environment may be short-lived.  Commodity futures prices are in backwardation (meaning that current prices are higher than future prices), implying some near-term tightness that is expected to subside.  This sentiment is echoed by the U.S. Energy Information Administration, which stated in their September 2021 Short-term Energy Outlookthat “growth in production from OPEC+, U.S. tight oil, and other non-OPEC countries will outpace slowing growth in global oil consumption” and would likely lead to lower oil prices. Financial PerformanceThe Bakken public comp group saw strong stock price performance over the past year (through September 20th), with all constituents outperforming the broader E&P sector (as proxied by XOP).  Continental and Whiting prices increased 175% and 151% year-over-year, compared to the XOP’s increase of 78%.  Oasis, which emerged from bankruptcy in November 2020, is up 191% from its initial closing price post-bankruptcy.  However, this impressive stock price performance is probably more reflective of the dire straits of these companies last year.  Both Whiting and Oasis declared bankruptcy in 2020 and appear to have benefited from a cleaned-up capital structure.Keystone XL Finally CancelledThe Keystone XL pipeline, originally proposed in 2008, was finally cancelled by its developer, Canadian midstream company TC Energy.  President Biden revoked a key permit needed for the project on his first day in office.The proposed pipeline caused significant controversy during its planning stages as it provided takeaway capacity for production from Alberta oil sands (which is more energy intensive, and thus less sustainable, than other forms of hydrocarbon extraction) and its path through Nebraska’s environmentally sensitive Sandhills region and Ogallala Aquifer.  Keystone XL also would have provided additional pipeline capacity out of the Bakken, which could become very needed if the also-controversial Dakota Access Pipeline gets shutdown.ConclusionWhile the Bakken saw strong production increases in the wake of mid-2020’s commodity price rout, that recovery appears to have faltered in 2021.  Production has generally been on the decline this year, though the recent increase in rigs operating in the basin should stem this decrease and provide for modest production growth going forward.  However, companies’ current emphasis on returning cash to shareholders may lead to less investment than has been seen in previous periods with similar commodity price environments.We have assisted many clients with various valuation needs in the upstream oil and gas space for both conventional and unconventional plays in North America, and around the world.  Contact a Mercer Capital professional to discuss your needs in confidence and learn more about how we can help you succeed.
Bakken M&A
Bakken M&A

Transaction Volume and Deal Size Rebound in 2021

Over the last year, deal activity in the Bakken has been steadily increasing after a challenging 2020.  Eight of the nine deals referenced below occurred in the last eight months as the price environment has turned more favorable.  As the industry seems optimistic that the worst of COVID-19 is behind us, deal activity may continue to increase into next year, but there is always hesitation, especially with the Delta variant on the rise.Recent Transactions in the BakkenA table detailing E&P transaction activity in the Bakken over the last twelve months is shown below.  Relative to 2019-2020, deal count was unchanged, but median deal size increased by roughly $480 million, which was lead by the $5.6 billion Devon-WPX transaction.Click here to expand the chart aboveOasis Adds Strategic Acreage in Core AreaOn May 3, 2021, Oasis Petroleum announced that it entered a definitive agreement to acquire select Williston Basin assets from Diamondback Energy in a cash transaction valued at approximately $745 million.  The effective date of the acquisition will be April 1, 2021, and the deal has yet to officially close.  The purchase consideration is expected to be financed by cash, revolver borrowings, and a bridge loan.  Transaction highlights include:Production (2021 Q1) – 27 Mboe/dAcreage – 95,000 net acres in Dunn, McLean, McKenzie counties, ND200 drilling locationsProved Reserves - 80.2 mmboe A pro forma table of the transaction is shown below: Diamondback has built a reputation of being focused on the Permian Basin, but in late 2020, the company acquired QEP Resources which gave them exposure to Williston acreage.  It took them roughly six months to sell their Bakken acreage package to Oasis, returning them to their pure-play Permian status. Equinor Lets Go of Its Bakken PositionOn February 10, 2021, Equinor announced that it was selling its Bakken asset portfolio to Grayson Mill Energy for $900 million.  Grayson Mill Energy is a Houston-based exploration and production company backed by Encap Investments, a private equity firm that has raised over $38 billion of capital.  An exit from the Bakken, which Equinor entered in 2011 by acquiring Brigham Exploration Company for $4.7 billion, follows the sale of its operated assets in the Eagle Ford for $325 million to Repsol in November 2019.  The deal closed on April 27, 2021 and included the following:242,000 net acres, and associated midstream assets48,000 Boep/d as of Q4 2020 In parallel with the transaction, Equinor Marketing and Trading entered into a term purchase agreement for crude offtake with Grayson Mill Energy.  Al Cook, Equinor’s executive vice president of Development & Production, referenced that the company is focused on improving the profitability of its international portfolio.ConclusionM&A transaction activity in the Bakken was steady through year-to-date 2021 and consisted of notable strategic acquisitions and exits in the basin.  Deal activity in the Bakken will be important to monitor as companies shift their focus to other basins and are forced to prioritize other initiatives.We have assisted many clients with various valuation needs in the upstream oil and gas industry in North America and around the world.  In addition to our corporate valuation services, Mercer Capital provides investment banking and transaction advisory services to a broad range of public and private companies and financial institutions.  We have relevant experience working with companies in the oil and gas space and can leverage our historical valuation and investment banking experience to help you navigate a critical transaction, providing timely, accurate and reliable results.  Contact a Mercer Capital professional to discuss your needs in confidence.
Oilfield Water Management
Oilfield Water Management

Clean Future Act Regulatory Concerns

In the midst of the COVID pandemic, the rise of the Delta-variant, and general summer distractions, not a lot of attention has been given to the 117th Congress’ H.R. 1512 – aka the “Climate Leadership and Environmental Action for our Nation’s Future Act” or the “CLEAN Future Act.”  The Act was first presented as a draft for discussion purposes in January 2020.  After more than a year of hearings and stakeholder input, it was introduced as H.R. 1512 in March 2021.  The Act’s stated purpose is:“To build a clean and prosperous future by addressing the climate crisis, protecting the health and welfare of all Americans, and putting the Nation on the path to a net-zero greenhouse gas economy by 2050, and for other purposes.”As broad as that stated purpose is, it’s not surprising just how far-reaching the implications of the nearly one-thousand-page-long Act are for many sectors of the U.S. economy.  While Congress is a long way away from any bipartisan climate legislation being enacted, the Act provides some insight regarding the plans of the House Democrat Leadership for a clean energy future.  It also potentially serves as a “red flag” to many industry participants that will be materially impacted by those plans.Of particular interest to the Oilfield Water Management sector, is Section 625 of the Act.  In that section, the Environmental Protection Agency would be ordered to determine whether certain oil and gas production byproducts, including produced water, meet the criteria to be identified as hazardous waste.  The legislation in fact, mandates that the EPA must make its determination within a year after the Act becomes law.Per the EPA’s April 2019 study publication, Management of Exploration, Development and Production Wastes: Factors Informing a Decision on the Need for Regulatory Action, produced water is defined as “the water (brine) brought up from the hydrocarbon bearing strata during the extraction of oil and gas. It can include formation water, injection water, and any chemicals added downhole or during the oil/water separation process.”  Since 1988, EPA has held that oilfield-produced water should be regulated as non-hazardous waste.  As such, produced water has been subject to the Resource Conservation and Recovery Act’s (RCRA) much less restrictive Section D provisions regarding non-hazardous waste, instead of RCRA Section C’s much more restrictive provisions regarding hazardous waste.Per a June 2021 report by Rice University’s Baker Institute for Public Policy, if the EPA’s Act-directed review of the 1988 produced water’s non-hazardous classification is revised to a hazardous classification, an enormous disruption in oilfield water management would result.  The report specifies that severe disposal capacity constraints would be brought into play.At the current time, oilfield produced water disposal is available at an estimated 180,000 Class II disposal wells located throughout the U.S.  If the Act were to lead the EPA to reclassify produced water as hazardous waste, all produced water would have to be disposed of in Class I wells, of which there are far fewer.  The EPA’s data on Class I wells indicates that approximately 800 such wells are in existence; however, the wells are located in only 10 states due to geological requirements.  The majority of those Class I wells are located in Texas and Louisiana.  The EPA also indicates that only 17% of the Class I wells are available for hazardous waste disposal.  Adding to the limited Class I well availability matter, the University of Wisconsin Eau Claire reports that those hazardous waste  disposal wells are located at a mere 51 facilities.                                                                                                                                                                             Source: EPA                             The cost of transporting Eagle Ford and Permian Basin produced water (in excess of 10 million barrels per day), for example, hundreds for miles to Class I facilities on the Texas and Louisiana Gulf Coast would be prohibitive to many producers.  As a result, a substantial reduction in U.S. oil and gas production would be a natural and expected consequence, with the economic and industry ripple effect of such reduced production being enormous.  Gabriel Collins, the Baker Botts Fellow in Energy and Environmental Regulatory Affairs at the Baker Institute, notes that any such re-classification would very likely lead to multi-system disruptions severe enough to make achieving the Act’s climate, energy, environmental, and social objectives impossible.While the Act is awaiting action by the U.S. House of Representatives, it’s well worth Oilfield Water Management industry participants keeping a close eye on it.  Although Congress’ attention has been focused on COVID relief and is now focused on infrastructure matters, the CLEAN Future Act will eventually come to the forefront, with potentially far-reaching impacts if unchanged from its current form.ConclusionMercer Capital closely monitors the Oilfield Water Management and other areas of the Oilfield Services industry.  We’re always happy to answer your OFS-related, or more general valuation-related questions.  Please contact a Mercer Capital professional to discuss your needs in confidence.
Mineral Aggregator Valuation Multiples Study Released (1)
Mineral Aggregator Valuation Multiples Study Released

With Market Data as of August 24, 2021

Mercer Capital has its finger on the pulse of the minerals market.  An important trend has been the rise of mineral aggregators, which have largely supplanted the trusts as the primary method of publicly traded minerals ownership.Due to a variety of corporate structures (including master limited partnerships and Up-Cs) and complex capital structures (including preferred equity and non-traded common units), mineral aggregator enterprise values pulled from databases are often missing meaningful components of value, leading to skewed valuation multiples.Mercer Capital has thoughtfully analyzed the corporate and capital structures of the publicly traded mineral aggregators to derive meaningful indications of enterprise value.  We have also calculated valuation multiples based on a variety of metrics, including distributions and reserves, as well as earnings and production on both a historical and forward-looking basis.Mineral Aggregator Valuation MultiplesDownload Study
Themes from Q2 Earnings Calls
Themes from Q2 Earnings Calls

Part 2: Mineral Aggregators

Last week, we reviewed the second quarter earnings calls for a select group of E&P companies and briefly discussed the macroeconomic factors affecting the oil and gas industry. In this post, we focus on the key takeaways from mineral aggregator second quarter 2021 earnings calls.Operators Maintaining Drill Bit DisciplineAggregators keep a close eye on E&P companies as they often reap the benefits of the drill bit, but also fall victim to capital discipline initiatives.  In the second quarter, many aggregators made note of operators’ disciplined approach as prices and rig counts continued to rise.“Our portfolio has benefited as bigger and better capitalized operators have taken over operatorship of our minerals to enable more consistent and disciplined development. Our focus on the highest rate of return undeveloped locations throughout our history ensures that our mineral position migrates to the top of any operator's drilling inventory.” – Ben Brigham, Executive Chairman & Director, Brigham Minerals“Despite the increase in rig count through the second quarter, we do anticipate that trend to flatten through the remainder of the year, as operators maintain their capital discipline.” – Jeff Wood, President & CFO, Black Stone Minerals“Operators in the U.S. continue to practice discipline with their drilling activity even in the face of significantly higher commodity prices.” – Bob Ravnaas, Chairman & CEO, Kimbell Royalty PartnersCapitalizing on Favorable Price EnvironmentIndustry participants remain optimistic as prices have increased significantly over the last year.  Some aggregators were heavily hedged, and others, like Brigham Minerals, are reaping the benefits of their unhedged position.“In fact, this is the best macro setup I've seen in my career, and I've lived through numerous cycles. Benefiting from our diversified portfolio of high-quality mineral assets, our shareholders are positioned to benefit from what I believe is very likely a long ramp of elevated pricing for oil, NGL and natural gas prices. This is particularly true given that unlike some of our peers, we are unhedged.” – Bud Brigham, Founder & Executive Chairman, Brigham Minerals“Oil prices are now well above pre-COVID levels, but the U.S. land rig count is 39% below year end 2019 levels. Furthermore, natural gas prices are trading at multiyear highs, driven primarily by increased power demand in the U.S. and surging exports of LNG to Europe and Asia. Given that a significant portion of our daily production is natural gas, we expect this improved pricing to benefit our cash available for distribution in Q3 2021 and into the winter months based on the current strip pricing.” – Bob Ravnaas, Chairman & CEO, Kimbell Royalty Partners“The increase in royalty volumes was mainly due to the Midland and Delaware properties but we also saw nice increases outside of our major shale plays as well, but seen a remarkable rebound in commodity prices since the middle of last year and are currently well above pre-pandemic price levels.” – Tom Carter, Chairman & CEO, Black Stone MineralsDistributions Ramping UpAggregators have built a reputation of acting as a yield vehicle with the ability to reinvest, unlike traditional royalty trusts.  Their popularity increased as they maintained healthy distributions over the years, however the challenging environment in 2020 put most payouts in jeopardy.  With the uptick in prices and a more optimistic outlook, aggregators seem confident to return to historical payout levels.“The $0.31 per common unit distribution this quarter reflects a 75% payout of cash available for distribution. We will use the retained amount, 25%, to pay down a portion of the outstanding borrowings under Kimbell’s credit facility.” – Davis Ravnaas, President, CFO & Chairman, Kimbell Royalty Partners“This allowed us to maintain a 100% distribution in the second quarter of 2020 and importantly enter 2021 unhedged with our investors fully exposed to the run-up in commodity prices as the economic reopening took hold toward the end of last year and more fully during the first quarter of this year associated with the vaccine rollout.” – Robert Roosa, CEO & Director, Brigham Minerals“We generated $72.1 million of distributable cash flow for the second quarter or $0.35 per unit. That gave us a lot of flexibility to increase our distribution while still holding some cash and reserve for further debt repayment.” – Jeff Wood, President & CFO, Black Stone Minerals Conclusion Aggregators seemed optimistic across the board in the second quarter of 2021.  Prices have rebounded, and distribution policies are returning to normal, which in their minds creates good shareholder sentiment.  However, the continued capital discipline of E&P operators may affect aggregators in the short to intermediate term.Conclusion Mercer Capital has its finger on the pulse of the minerals market.  An important trend has been the rise of mineral aggregators, which have largely supplanted the trusts as the primary method of publicly traded minerals ownership.  Contact a Mercer Capital professional to discuss your needs in confidence.
DUC Clock Ticks On Cheap Production: Low-Cost Cash Flow Won’t Last
DUC Clock Ticks On Cheap Production: Low-Cost Cash Flow Won’t Last
As we await second quarter earnings for publicly traded upstream producers, there are several markers and trends that suggest cash flows and profits will swell. Investment austerity and the recently resulting profits will almost certainly be bandied about on management calls. However, what might not be touted as loudly will be how much longer this can last? Existing U.S. production, much of it horizontal shale, is declining fast, operational costs and inflationary pressure are rising again, and the only way to augment production is through some combination of drilling and fracking.Cash Flow Crowned KingAccording to the latest Dallas Fed Energy Survey, business conditions remain about as optimistic as they were in the first quarter whilst oil and gas production has jumped. In the meantime, U.S. shale companies are on the precipice of delivering superior profits in 2021: in the neighborhood of $60 billion according to Rystad. How are they doing that? A combination of revenue boosts and near static investment levels. Analysts are pleased and management teams are crowing about cash. The industry should be able to keep it up, but only for a finite period. How long is that? Nobody knows for sure, but a good proxy may be the shrinking drilled but uncompleted (DUC) count of wells in the U.S. Overall DUC counts peaked in June of 2020 at 8,965, with the Permian leading the way. June 2021 statistics show DUCs at 6,252 or a 2,713 (30%) drop in one year. Just last month 269 DUCs disappeared with nearly half of those coming out of the Permian. This matters because DUC wells are much cheaper to bring online than fully undeveloped locations. Around half the drilling costs are already sunk and therefore it is incrementally cheap to complete (frack) and then produce from a DUC well. It’s low hanging fruit and producers with high DUC counts can profitably take advantage of recent price surges. However, these easily accessed volumes can’t be tapped forever. Last month’s DUC drawdown pace leaves less than a two-year backlog of DUC’s remaining, and it’s worth remembering that companies like to keep some level of inventory on their books, so the more realistic timing may be before 2022 ends. Inventory On The DeclineAll this is in conjunction with permit counts way below even 2019 levels (although rising – particularly among private companies). There’s likely going to be supply shortages in the future, as most producers in the Dallas Fed Survey suggest - but who will pick up that slack? OPEC may not be the only answer here. Granted, not every OPEC country has the spigot capability Saudi Arabia does and some other OPEC+ members have not been above cheating on their production limits in the past.Nonetheless, global inventories continue to decline. The U.S. Energy Information Administration’s short term energy outlook expects production to catch up due to OPEC+ recent production boost announcements, but nobody exactly knows what that will look like in the U.S. The EIA acknowledged that pricing thresholds at which significantly more rigs are deployed are a key uncertainty in their forecasts. There’s no certainty the U.S. shale industry will be able to pick up the demand slack either. They are preparing to live on what they have already drilled. Producers are under immense pressure to keep capital expenditure budgets under wraps and focus on investor returns. As such not much external capital is chasing the sector right now. A good example is this respondent to the Dallas Fed’s Survey: “We have relationships with approximately 400 institutional investors and close relationships with 100. Approximately one is willing to give new capital to oil and gas investment…This underinvestment coupled with steep shale declines will cause prices to rocket in the next two to three years. I don’t think anyone is prepared for it, but U.S. producers cannot increase capital expenditures: the OPEC+ sword of Damocles still threatens another oil price collapse the instant that large publics announce capital expenditure increases.” Pretty said. As a result industry analysts at Wood Mackenzie say U.S. crude production will grow very modestly during 2021 and likely 2022. OPEC+ is adding production, but not a lot – only 400,000 barrels per day being added back compared to the nearly 10 million per day cut in 2020. That leads to price pressure and the market has been catching on. Valuations on the AscentThese industry forces have contributed to the E&P sector having an outstanding year from a stock price and valuation perspective. Returns have outpaced most other sectors, and Permian operators have performed at the top of the sector. However, it is important to note that much of this gain is recovery from years of prior losses.An interesting observation (and consistent theme of mine) is that proven undeveloped reserves (PUDs) are the biggest beneficiary of this value boost. As production from existing wells declines, the value from tomorrow’s wells is getting a big bump. Mergers and acquisitions in the past year at what now appear to be attractive valuations, often paid very little if anything for PUDs, but buyers got them anyway. They are gaining valuation steam now. What were out of the money options are now moving into the money. Acreage values are intrinsically going up in West Texas (both Delaware and Midland basins), South Texas (Eagle Ford) and recovering in other areas such as the Anadarko basin in Oklahoma.Companies like Diamondback Energy have acquired acreage recently (QEP and Guidon deals) that surround or is contiguous with legacy acreage positions. This will come in handy when new wells come into view of capex budgets, and as I mentioned – there is a visible path whereby they could come into view in the next couple of years with oil above $70 per barrel.Investors appear to be cautious in view of OPEC+ perceived sword of Damocles hanging overhead, which is logical. However, the fundamentals remain lopsided towards high prices for some time, barring another catastrophic event, which of course could always be lurking around the corner.Originally appeared on Forbes.com.
How to Value an Oilfield Services Company
How to Value an Oilfield Services Company
As the volatility continues with oil field service companies (the OSX has nearly doubled since November 2020), valuation and techniques associated therewith are important to consider right now.  Therefore, this week we are reposting our blog post and whitepaper as it pertains to how to understand and value oil field service companies. When valuing a business, it is critical to understand the subject company’s position in the market, its operations, and its financial condition. A thorough understanding of the oil and gas industry and the role of oilfield service (“OFS”) companies is important in establishing a credible value for a business operating in the space. Our blog strives to strike a balance between current happenings in the oil and gas industry and the valuation impacts these events have on companies operating in the industry. After setting the scene for what an OFS company does and their role in the energy sector, this post gives a peek under the hood at considerations used in valuing an OFS company.Oil and Gas Supply ChainThe oil and gas industry is divided into three main sectors:Upstream (Exploration and Production)Midstream (Pipelines and Other Transportation)Downstream (Refineries)Source: Energy Education Exploration and production (E&P) companies search for reserves of hydrocarbons where they can drill wells in order to retrieve crude oil, natural gas, and natural gas liquids. To do this, E&P companies utilize oilfield service (OFS) companies to help with various aspects of the process including pumping and fracking, land contract drilling, and equipment manufacturers. E&P companies then sell the commodities to midstream companies who use gathering pipelines to transport the oil and gas to refineries. Finally, refiners convert raw crude and natural gas into products of value. Oilfield Services OperationsE&P companies may own the rights to the hydrocarbons below the surface, but they can’t move them down the supply chain without the help from OFS companies in the extraction process. We can think of various OFS companies being subcontractors in the upstream process much like a general home builder might bring in people specially trained to set the foundation or wire electrical or plumbing. Because the services provided often require sophisticated technology or extensive technical experience, it stands to reason OFS companies would be able to charge a premium price. Thus, OFS would appear to be insulated from the commodity pricing that is inherent in the industry. However, E&P companies are the ones contracting these companies, and if oil prices decline enough, they are pressured to decrease production (and capex budgets), reigning in activity for OFS companies. This is where the specific service provided matters.Regardless of service provided, or industry for that matter, there are certain aspects of a business that should always be considered.As previously shared in May of 2019, there are a variety of different services provided by OFS companies. Companies that fall into the category of OFS can be very different from one another as the industry is fragmented with many niche operators. For example, companies servicing existing production are less impacted by changes in commodity prices than OFS companies that service drilling, as these activities are the first to decrease. Regardless of service provided, or industry for that matter, there are certain aspects of a business that should always be considered.Oilfield Equipment and Service Financial AnalysisA financial analyst has certain diagnostic markers that tell much about the condition of a business both at a given point of time (balance sheet) and periodically (income statement).Balance Sheet. The balance sheet of an OFS company is considerably different from others in the energy sector. E&P companies have substantial assets attributed to their reserves. Refiners predominantly have high inventory and fixed assets. OFS companies will depend on the type of product or service, but generally, they tend to have a working capital balance that consists more of accounts receivable than inventory, like other service-oriented businesses. According to RMA’s annual statement studies, A/R made up 22.3% of assets while inventory was 9.3% for Drilling Oil and Gas Wells (NAICS #213111).[1] These figures were 26.6% and 10.8%, respectively for Support Activities for O&G Operations (#213112). Notably, drilling operations had a higher concentration of fixed assets (46.8%) compared to other support services which comprised 35.7% of assets. Broadly speaking, this illustrates the different considerations within the OFS sector as far as the asset mix is concerned.Income Statement. The development of ongoing earning power is one of the most critical steps in the valuation process, especially for businesses operating in a volatile industry environment.  Cost of goods sold is a significant consideration for other subsectors in the energy space, particularly as the product moves down the supply chain towards the consumer. This is not the case for OFS companies. RMA does not even break out a figure for gross profit, but instead combines everything under operating expenses. Still, OFS companies deal with significant operating leverage. If expenses are less tied to commodity prices that means costs may be more fixed in nature. That means when activity decreases and revenues decline, expenses don’t decline in lock-step resulting in margin compression and profitability concerns. While the balance sheet does not directly look at income, it can help determine sources of return. Fixed-asset heavy companies like drillers tend to be more concerned with utilization rates as the more their assets are deployed, the more money they will earn. On the other hand, predominantly service-based companies that rely on their technology and expertise tend to be more concerned with the market-determined prices they are able to charge and terms they are able to negotiate. Additionally, OFS companies may have significant intangible value that may not be reflected on the balance sheet. Intangible assets developed internally are accounted for differently than those that are acquired, and a diligent analyst should be cognizant of assets recorded or not recorded in developing an indication of value.How to Value OFS?There are fundamentally three commonly accepted approaches to value: asset-based, market, and income.  Each approach incorporates procedures that may enhance awareness about specific business attributes that may be relevant to determining an indication of value. Ultimately, the concluded valuation will reflect consideration of one or more of these approaches (and perhaps several underlying methods) as being most indicative of value.The Asset-Based ApproachThe asset-based approach generally represents the market value of a company’s assets minus the market value of its liabilities.The asset-based approach can be applied in different ways, but in general, it represents the market value of a company’s assets minus the market value of its liabilities. Investors make investments based on perceived required rates of return, so the asset-based approach is not instructive for all businesses. However, the capital intensive nature of certain OFS companies does lend some credence to this method, generally setting a floor on value. If companies have paid off significant portions of their debt load incurred financing its equipment, the valuation equation (assets = liabilities + equity) tilts towards more equity and higher asset approach indications of value. Crucially, as time goes on and debt is serviced, the holding value of the assets must be reassessed.  Price paid, net of accumulated depreciation may appear on the balance sheet, but if the equipment or technology begins to suffer from obsolescence, it will have less value in the marketplace. For example, due to the shale revolution in the United States and the increased demand for horizontal drilling, equipment and services that facilitate vertical drilling have less market value than it did less than a decade ago. Ultimately, the asset-based approach is typically not the sole (or even primary) indicator of value, but it is certainly informative.The Income ApproachThe income approach can be applied in several different ways. Generally, analysts develop a measure of ongoing earnings or cash flow, then apply a multiple to those earnings based on market risk and returns. An estimate of ongoing earnings can be capitalized in order to calculate the net present value of an enterprise.  The income approach allows for the consideration of characteristics specific to the subject business, such as its level of risk and its growth prospects relative to the market through the use of a capitalization rate. Stated plainly, there are three factors that impact value in this method: cash flows, growth, and risk. Increasing the first two are accretive to value, while higher risk lowers a company’s value.The income approach allows for the consideration of characteristics specific to the subject business.To determine an ongoing level of earnings, scrutiny must be applied to historical earnings. First, analysts must consider the concentration of revenues by customers.  A widely diversified customer base is typically worth more than a concentrated one.  Additionally, an analyst should adjust for non-recurring and non-normal income and expenses which will not affect future earnings. For example, disposing of assets utilized in the business is not considered an ongoing source of return and should be removed from the company’s reported income for the period when the disposition occurred. The time period must also be considered. Assuming cash flows from last year will continue into the future may be short-sighted in the energy sector. Instead of using a single period, a multi-period approach is preferable due to the industry’s inherent volatility, both in observing historical performance and projecting into the future. Discounted cash flow (DCF) analyses are an important tool, but factors such as seasonality, cyclicality, and volatility all call for a longer projection period.After developing the earnings to be capitalized, attention is given to the multiple to be applied.  The multiple is derived in consideration of both risk and growth, which varies across different companies, industries, and investors. When valuing an OFS company, customer concentration is of particular concern to both risk and growth. Developing a discount rate entails more than applying an industry beta and attaching some generic company risk premium. Analysts must look deeper into the financial metrics addressed earlier and consider their market position. Are they financially stable or over-levered by either fixed costs or debt? Are they a sole provider or one of many? If more players are entering the market, prices charged may be lower than those historically observed. If a company stops investing in its equipment and technology, demand for the company’s products and services declines. Again, metrics such as utilization and day rates are important to analyze when developing a discount rate.Income is the main driver of value of a business as the goal is to generate a reasonable return (income) on its assets. People don’t hang a sign above their door and go into business if they don’t think they will eventually turn a profit. Still, differences of opinion on risk and growth can occur, and analysts can employ a market approach as another way to consider value.The Market ApproachAs the name implies, the market approach utilizes market data from comparable public companies or transactions of similar companies in developing an indication of value. In many ways, this approach goes straight to the heart of value: a company is worth what someone is willing to pay for it. The OFS subsector is a fragmented industry with many niche, specialty operators. This type of market lends itself to significant acquisition activity.However, transactions must be considered with caution. First, motivation plays a role, where a financially weak company may not be able to command a high price, but one that provides synergies to an acquirer might sell for a premium. Transactions must also be made with comparable companies. With many different types of companies falling under the OFS umbrella, analysts must be wary of comparing apples to oranges. While they work in the same subsector, there are clearly important differences between equipment manufacturers and pumpers and frackers. Untangling the underlying earnings sources of these businesses is important when looking at guideline transactions as well as directly comparing to guideline companies.In many ways, the market approach goes straight to the heart of value: a company is worth what someone is willing to pay for it.Larger diversified players, such as Schlumberger and Halliburton, are more likely to provide similar services to companies an analyst might value, but their size, sophistication, and diversification of services likely renders them incomparable to smaller players. Given the relative considerations and nuances, taking their multiples and applying a large fundamental adjustment on it is crude at best and may miss the mark when determining a proper conclusion of value.Analysts using a market-based approach should also be judicious in utilizing the appropriate multiple and ensuring it can be properly applied. Industries focus on different metrics and it is important to consider the underlying business model. For E&P companies, EV/EBITDAX may be more insightful as capital expenditure costs are significant and can be throttled down in times of declining crude prices. For OFS companies, potentially relevant multiples include EV/Revenue and EV/Book Value of Invested Capital, but there is no magic number, and these useful metrics cannot be used in isolation. Ultimately, analysts must evaluate the level of risk and growth that is implied by these multiples, which tends to be more important than the multiples used.The market approach must also consider trajectory and location. There’s a difference between servicing vertical wells that have been producing for decades as opposed to the hydraulic fracturing and long horizontal wells in the Delaware Basin. Distinctions must also be drawn between onshore and offshore as breakeven economics are similar (don’t produce if you can’t earn a profit), but costs related to production vary significantly.Ultimately, the market-based approach is not a perfect method by any means, but it is certainly insightful. Clearly, the more comparable the companies and the transactions are, the more meaningful the indication of value will be.  When comparable companies are available, the market approach should be considered in determining the value of an OFS company.Synthesis of Valuation ApproachesA proper valuation will factor, to varying degrees, the indications of value developed utilizing the three approaches outlined. A valuation, however, is much more than the calculations that result in the final answer. It is the underlying analysis of a business and its unique characteristics that provide relevance and credibility to these calculations. This is why industry “rules of thumb” or back of the napkin calculations are dangerous to rely on in any meaningful transaction. Such calculation shortcuts fail to consider the specific characteristics of the business and, as such, often fail to deliver insightful indications of value.A thorough approach utilizing the valuation approaches described above can provide significant benefits. The framework provided here can facilitate a meaningful indication of value that can be further refined after taking into account special considerations of the OFS industry that make it unique from other subsectors of the oil and gas industry.ConclusionWe have assisted many clients with various valuation needs in the oil and gas space for both conventional and unconventional plays around the world.  Contact a Mercer Capital professional to discuss your needs in confidence and learn more about how we can help you succeed.[1] 2018-2019 RMA Statement Studies. NAICS #213111 and 213112. Companies with greater than $25 million in sales.Originally posted on Mercer Capital's Energy Valuation Insights Blog June 3, 2019
Pioneer Natural Resources Pay to Play
Pioneer Natural Resources Pay to Play

A Tale of Two Transactions

As noted in our June 2021 blog post covering Permian M&A activity, M&A transactions picked up in the twelve months ended mid-June relative to the twelve-month period preceding it. Perhaps more importantly, there seemed to be an inflection point in transaction multiples that hinged around the U.S. elections in November 2020.Among all the transactions that occurred over this period, one pair jumped out involving a common buyer and for which valuation metrics were available. These related to Pioneer’s acquisition of Parsley Energy in October 2020 and DoublePoint Energy in April 2021, with implied transaction metrics well above the average and median values in the the respective sub-periods of the reviewed period.  Statistics of the valuation metrics for the transactions occurring between mid-June 2020 to mid-June 2021 and the bifurcated sub-periods, both including and excluding Pioneer transaction data, are as follows:Click Here to Enlarge the ImageWe note that, as compared to the transactions table in the aforementioned Permian M&A activity blog post, the transaction counts and statistics presented exclude four transactions for which acquired assets were working interests, as opposed to a property or corporate acquisition.  We also note that only one of the four excluded transactions involving the acquisition of a working interest had any useful transaction data available, and the metrics for this one transaction tended to be outliers (on the high side) in the context of the full set of transactions.Tech talk aside, the main point here is Pioneer consistently paid top dollar for its acquisitions from the perspective of the transactions’ valuation metrics.  Why?Easy Answer: Pioneer Is a Large Strategic BuyerIn Pioneer’s October 2020 press release covering its acquisition of Parsley Energyand April press release for its acquisition of DoublePoint Energy, the strategic nature of the acquisitions was cited.  Prominent in both releases was mention of significant synergies and “unmatched scale” with respect to Pioneer’s footprint in the Permian play.Regarding the Parsley acquisition, Pioneer’s President and CEO, Scott D. Sheffield, stated, “This combination is expected to drive annual synergies of $325 million and to be accretive to cash flow per share, free cash flow per share, earnings per share and corporate returns beginning in the first year.…”  It was further noted that, “The combined company will be the leading Permian independent exploration and production company with a premium asset base of approximately 930,000 net acres [representing an approximately 37% increase over its pre-transaction net acreage] with no federal acreage and a production base of 328thousand barrels oil equivalent per day (“MBoepd”) and 558 MBoepd as of the second quarter of 2020.  Additionally, based on year-end 2019 proved reserves, this transaction will increase Pioneer’s proved reserves by approximately 65%.”Similarly, synergies were noted in the DoublePoint acquisition, including expectations annual cost savings over the next 10 years of $175 million, stemming from increased operational efficiencies and reduced G&A and interest expenses, with a total present value of savings of approximately $1 billion.  This transaction also expanded Pioneer’s Permian footprint by an additional 97,000 net acres to over 1 million total net acres in its core Permian position.  This addition implies an increase of 10% over its 930,000 total net acreage holdings following the Parsley Energy acquisition, and further fortifies the company’s position as a premier Permian E&P operator.While the strategic argument makes sense fundamentally, arguably any transaction involving an existing E&P company entering or expanding their presence in the Permian could be deemed a “strategic” acquisition.  Let’s dive a little deeper into the numbers behind Pioneer’s acquisitions to see if there may be another differentiating factor.Deeper Answer: Production DensityIn our analysis of Permian M&A activity over the past twelve months, we presented deal values and valuation metrics such as deal value per acre and per production (Boepd).  As might be gleaned from those metrics, our data set included the net acreage and production values associated with the acquisitions, though these specific data points were not presented outright.Utilizing the full set of data to examine the transactions, we developed and reviewed certain indicators beyond the presented valuation metrics.  In particular, we calculated the implied annual production (total implied Boe) per acquired acre for each transaction.  We’ll refer to this as “production density.”  The following table presents the full data set which will be referenced:Click Here to Enlarge the ImagePioneer’s acquisition of Parsley Energy indicated a production density factor of 267 Boe/acre.  Among the six transactions that occurred from July to October 2020, this was the second highest value, being only 7 Boe/acre lower than the highest indicated value implied by the Devon Energy-WPX Energy transaction.  Conversely, this production density factor of 267 Boe/acre was 26% greater than the next highest factor of 212 Boe/acre implied in the ConocoPhillips acquisition of Concho Resources, which was announced the day prior to the Parsley acquisition announcement.Among the transactions announced from November 2020 through mid-June of this year, the production density factor of the Pioneer-DoublePoint Energy acquisition was 376 Boe/acre, which was just over 13% higher than the production density of the next highest value of 332 Boe/acre implied by the Vencer Energy-Hunt Oil acquisition, and was the highest value among all the acquisitions in the Permian listed over the full 12-month period ended mid-June.ConclusionIn our prior analysis of Permian M&A activity from mid-June 2020 to mid-June 2021, several points came to light:Transaction multiples appeared to have an inflection point, with significantly lower multiples indicated from the transactions announced after October 2020 relative to the indicated multiples for transactions announced prior to November 2020.Given the publicly available information, Pioneer was the only buyer in both sub-periods noted (for which useful transaction data was available).The transaction multiples stemming from the Pioneer acquisitions were among the highest, if not the highest, in the respective sub-periods, making them among the highest multiples for the entire 12-month period reviewed. While commodity prices could have been a factor, we note that WTI futures as of April 2021 were, on average, 30% higher than WTI futures as of October 2020 when looking at a 12-month span consecutively for nine annual periods that followed the respective measurement dates.  On one hand, this could be interpreted to mean that valuations should have been greater in the latter sub-period (with higher futures prices).  On the other hand, the higher prices in the future might have been  indicative of uncertainty regarding the Biden Administration’s rhetoric and possible actions that would more than likely prove to be headwinds to the oil and gas industry overall.  Commodity prices notwithstanding, the data available and subsequent information gleaned from it suggest Pioneer was able to act on two prime opportunities that would further enhance the quality of its acreage and production portfolio. We have assisted many clients with various valuation needs in the full stream of the oil and gas space for both conventional and unconventional plays in North America, and around the world.  Contact a Mercer Capital professional to discuss your needs in confidence and learn more about how we can help you succeed.
Does Vine Debut Portend Ripe Market for More E&P IPOs?
Does Vine Debut Portend Ripe Market for More E&P IPOs?
It’s been tough out there for equity capital markets bankers covering the upstream sector.  Since 2016, there have only been five U.S. exploration & production company IPOs. [1]  The dearth of activity is driven by a number of factors, including poor historical returns from the space, special purpose acquisition companies (SPACs) supplanting the traditional IPO process, and environmental, social, and governance (ESG) pressures resulting in less capital availability. Three U.S. E&P IPOs took place in late 2016 and early 2017.  Berry Petroleum, a California producer focused on conventional production methods, went public in mid-2018.  Nearly three years would pass until the next IPO: Vine Energy. Vine IPOVine Energy, a pure-play Haynesville gas producer, broke this nearly three-year dry spell with their IPO in March of this year.  However, Vine had a rough start as a public company.  The IPO priced at $14 per share, below the anticipated offering price of $16 to $19 per share indicated in Vine’s S-1.  Once trading began, there was no typical IPO pop, as the stock opened at $13.75.  The stock continued to trade down over the next several weeks, closing below $11 in mid-April. However, Vine’s stock price performance since the nadir has been relatively strong.  The stock price rose to almost $16 in late June, up more than 44% from its low.  Overall, the stock is up 8% from its IPO price, outperforming the broader E&P sector (as proxied by XOP, the SPDR S&P Oil & Gas Exploration & Production ETF), though still lagging the S&P 500. Are More E&P IPOs Coming?While we don’t have a crystal ball, there several are factors that could lead to additional E&P IPOs over the next several years.Restraint Leading to Returns: E&P companies were maligned for a “drill, baby, drill” mentality which led to huge amounts of capital being deployed to generate suboptimal returns. However, they seemed to have learned their lesson and are now showing capital discipline, even in light of a much-improved commodity price environment.  The result is that shale drillers are actually delivering free cash flow.  That appears to be impacting stock prices, as the year-to-date performance (through 7/13/2021) of XOP has trounced the S&P 500 (shown in the following chart).  If this performance holds, investors who previously shunned the industry may begin dipping their toes back in with increased allocations to the sector.Need for Private Equity to Exit: Between 2015 and 2019, private equity funds raised approximately $86 billion of capital to deploy on U.S. oil & gas assets. However, that capital raising has slowed, and traditional oil & gas PE sponsors (including Riverstone, EnCap, and NGP) have begun focusing on energy transition investments.  With less private equity capital in the ecosystem, and public E&Ps showing restraint with respect to capital spending, public markets may be the best exit opportunity for certain larger PE-backed companies. It Might Be Another Long Dry Spell Before We See Another E&P IPOLack of Public S-1 Filings: The IPO process is an involved and lengthy affair. One of the first steps required to go public is filing an S-1, which is the initial registration form for new securities required by the SEC.  The S-1, which is usually filed well in advance of an actual public offering, describes the company’s operations and includes financial information.  According to data from Capital IQ, there do not appear to be any U.S. E&P companies with active registration statements for material sized (>$50 million) offerings.  The most recent S-1 filings for uncompleted offerings are from Tapstone Energy and EnVen Energy Corporation.  However, both of those registration statements have been withdrawn.  With no E&P companies currently teed up to go public, it will likely be a while before one makes it through the process.Less Need for Growth Capital: As previously discussed, with many shale drillers generating free cash flow, there is less need for growth capital to support operating activities. As such, private operators may eschew the scrutiny and pressure of public markets and remain private.Continued ESG Pressures:  With increasing emphasis on ESG issues, it could be challenging to generate the typical level of investor appetite necessary to successfully execute an IPO, especially among large institutional investors who typically anchor many IPO processes.SPAC Alternative:  SPACs have emerged as a viable alternative to the traditional IPO process. Several E&P companies were early adopters of SPACs as a means to go public, including Centennial, Alta Mesa, and Magnolia.  While many energy-focused SPACs indicate that they are seeking opportunities in the energy transition space, there are a handful that may be seeking to acquire E&P companies.ConclusionVine’s public market debut brought an end to a long-running drought of E&P IPOs, though it may be more of an anomaly than a harbinger of things to come.  With no public S-1 filings among upstream energy companies and continued investor focus on ESG issues, we don’t expect to see any new public E&P companies any time soon.We have assisted many clients with various valuation needs in the upstream oil and gas space for both conventional and unconventional plays in North America, and around the world.  Contact a Mercer Capital professional to discuss your needs in confidence and learn more about how we can help you succeed.[1] We note that there have been other upstream companies that have gone public via a SPAC (e.g., Centennial, Alta Mesa, and Magnolia) as well as mineral-focused companies that have had traditional IPOs (e.g., Brigham Minerals and Kimbell Royalty Partners).  However, this post is focused on traditional IPOs of exploration & production companies.
EP Third Quarter 2021 Bakken
E&P Third Quarter 2021

Bakken

Bakken // Oil prices were relatively stable in Q3 2021 following a significant run-up in the first two quarters.
Permian Production Pushes Higher
Permian Production Pushes Higher
The economics of Oil & Gas production vary by region. Mercer Capital focuses on trends in the Eagle Ford, Permian, Bakken, and Marcellus and Utica plays. The cost of producing oil and gas depends on the geological makeup of the reserve, depth of reserve, and cost to transport the raw crude to market. We can observe different costs in different regions depending on these factors. In this post, we take a closer look at the Permian.Production and Activity LevelsEstimated Permian production increased approximately 8% year-over-year through June, though current production remains below the peak observed in March 2020.  Production in Appalachia increased 5% year-over-year, while the Eagle Ford’s production was essentially flat.  The largest production gain was observed in the Bakken (up 26%), as the Bakken saw a high level of shut-in wells(in response to low commodity prices) which have subsequently been brought back online.  Permian production has generally been increasing over the past year, but there was a meaningful decline in February driven by Winter Storm Uri that disrupted power supplies throughout Texas. The Permian’s production increase is the result of more drilling activity in the basin.  There were 237 rigs in the Permian as of June 18th, up 73% from June 12, 2020.  Bakken and Eagle Ford rig counts were up 55% and 146%, respectively, while the Appalachia rig count was down 3%. Permian production should continue to increase modestly over the next several months based on the current rig count, legacy production declines, and new-well production per rig. Commodity Prices Grind HigherThe second quarter of 2021 saw rising commodity prices, driven largely by accelerating travel and economic activity amid the vaccine rollout and fewer COVID cases in many parts of the world.  Front-month WTI futures began the quarter at ~$60/bbl and broke above $70/bbl before the end of the quarter.  The rise in prices was generally slow and steady, with the exception of a dip in mid-May, though that was likely driven by short-term dislocations caused by the shutdown of the Colonial Pipelinein response to a ransomware attack.  Henry Hub natural gas front-month futures prices began the quarter at approximately $2.60/mmbtu and have been above $3/mmbtu for all of June thus far. However, the current commodity price environment may be short-lived.  WTI futures prices are in backwardation (meaning that current prices are higher than future prices), implying some near-term tightness that is expected to subside.  This sentiment is echoed by the U.S. Energy Information Administration, which stated that “continuing growth in production from OPEC+ and accelerating growth in U.S. tight oil production—along with other supply growth—will outpace decelerating growth in global oil consumption and contribute to declining oil prices” in their June 2021 Short-term Energy Outlook.Financial PerformanceIn a nice change of pace for energy investors, the Permian public comp group saw strong stock price performance over the past year (through June 22nd).  All of the Permian companies except Pioneer outperformed the broader E&P sector, as proxied by XOP (which was up 73% during the past twelve months).  That stock price performance is probably more reflective of the dire straits of some companies last year in the aftermath of the Saudi/Russian price war and COVID-19 lockdowns, as small, leveraged companies like Centennial and Laredo have had the biggest gains.  However, stock prices for all of the Permian comp group companies remain below all-time highs.Federal Lands Drilling Ban Could Shift Production Within the BasinPart of President Biden’s environmental platform was banning new oil and gas permitting on public lands.  An initial action under this platform was a 60-day moratorium on permitting activity, though that was recently blocked by a federal judge.  While many think a ban would haverelatively modest impacts at a macro level, the impacts could be more severe for companies and areas with a high level of exposure to federal lands.The Federal Reserve Bank of Dallas performed an analysis to look at the potential impact to the Permian Basin.  Under a restrictive policy scenario, production growth would slow (relative to no change in policy), though overall production from the basin is still expected to increase.[1] However, approximately half of New Mexico’s Oil & Gas production comes from federal acreage.  As such, the impacts to New Mexico are much more acute under a restrictive policy scenario.  The consequence is a shifting of drilling activity (and associated employment and spending) from New Mexico to Texas. ConclusionThe Permian was not immune to the impacts of historically low oil prices observed in 2020, though it has proven to be resilient.  Production, while still below peak levels, is growing, and growth is generally expected to continue.  Activity levels are improving, though companies’ current emphasis on returning cash to shareholders may lead to less investment than has been seen in previous periods with similar commodity price environments.We have assisted many clients with various valuation needs in the upstream oil and gas space for both conventional and unconventional plays in North America, and around the world.  Contact a Mercer Capital professional to discuss your needs in confidence and learn more about how we can help you succeed.[1] The Dallas Fed describes the policy scenarios as follows:Reference Case: This serves as the benchmark and assumes little-changed leasing, permitting and drilling from first-quarter 2021 levels.Hybrid Case: It assumes no new federal leasing, but existing leaseholders continue receiving drilling permits. Permit reviews are more rigorous, leading to slower approvals and a costlier operating environment beginning in 2022. Based on companies’ public statements, firms that hold acreage across the basin gradually relocate drilling rigs and completion crews to their nonfederal locations.Restrictive Case: No new federal permits or extensions are granted starting in 2023. This is when the most-recently issued permits will expire. The existing permitting freeze adversely affects production in the near-term due to a lack of approvals of permit modifications and pipeline rights-of-way. As in the Hybrid Case, companies shift their focus to nonfederal acreage.
Permian M&A Update: A Buyer's Market
Permian M&A Update: A Buyer's Market

Pocketbooks Open for More Deals and Larger Positions

Transaction activity in the Permian Basin picked up in earnest this past year, indicating greater optimism in extracting value from the West Texas and Southeast New Mexico basin.A table detailing E&P transaction activity in the Permian over the last twelve months is shown below.  Relative to 2019-2020, deal count increased by five transactions, representing an increase of 23% over the 22 transactions in the prior period. Furthermore, median deal size nearly tripled from $138 million to $405 million, period-over-period.  The median acreage among these transactions increased 2.5x from 14,500 acres to 36,250 acres (not shown below).  Given the concurrent increase in transaction values and greater acreages acquired, the median price per net acre was down a slight 4% period-over-period.The big story though, was production.  The median production among transactions from June 2018 to June 2019 was 2,167 barrel-oil-equivalent per day (“Boepd”); while over the past twelve months, the median production value was 8,950 Boepd (not shown).  As buyers “purchased in bulk” this period relative to the prior twelve-month period, the median transaction value per production unit declined nearly 41% from $53,584 per Boepd to $31,886 per Boepd.  Transactions came in waves.  There was one transaction announced regarding Permian properties between June and August 2020.  September saw three deal announcements, and 10 transactions were announced during Q4 2020.  Activity fell silent in Q1 2021 as the industry waited for the Biden Administration to settle in Washington.  Deal announcements then resumed in earnest in Q2 as WTI crude oil and Henry Hub natural gas prices showed signs of fairly stable upward trajectories, with the exception of a temporary spike in gas prices due to the mid-February freeze.Click here to expand the imageLooking a bit closer at the data, it appears there may have been an inflection point in deal valuations over the past twelve months.  First and foremost, there was a notable concentration of larger-than-average deals, in terms of transaction values, from July to October 2020.  Except for the Pioneer Natural Resources DoublePoint Energy transaction in early April, all deal values after October 2020 pale in comparison to those in the early period.  As presented in the comparative statistical tables below, bifurcating the presented metrics further between the periods of July to October 2020 and November 2020 to the present reveals the potential pivot in valuations.The post-October median transaction value declined 95% to just $294 million from the pre-November median value of $5.6 billion.  However, more tellingly, the cost per acre nearly halved with the median metric value declining from $20,449/acre in the July-October 2020 transactions to $10,482/acre in the post-October transactions.  If you remove the outlier value of the Northern Oil and Gas transaction ($180,303/acre), the nearly 50% decline is slightly reduced to an indicated decline of 45% in the price per acre.  I am not a gambler, but without soliciting direct commentary from the respective management of the buyers listed above, I would wager that the inbound Biden Administration and the uncertainty surrounding potential regulatory changes were a significant factor in this valuation decline.Click here to expand the imageOne noteworthy pair of transactions, which may receive further Mercer Capital analysis sooner than later, relates to acquisitions made by Pioneer Natural Resources, including the October 2020 announcement of a definitive agreement to acquire Parsley Energy and its April 2021 announcement of a definitive agreement to purchase the leasehold interests and related assets of DoublePoint Energy.  Pioneer was the only buyer to appear more than once on our list of transactions with a major transaction before November and one after (for which deal metrics were available), with indications of significant increases in the cost-per-net-acre and cost-per-Boepd valuation metrics.Northern Oil and Gas Enters the Delaware BasinIn September 2020, Northern Oil and Gas announced its entrance into the Permian with its acquisition of non-operated working interests in Lea County, New Mexico from an undisclosed seller.  The deal consisted of 66 net acres, with an initial 1.1 net wells proposed to be spud in late-2020 to early-2021 and production expected to start in Q2 2021.  The total acquisition costs (including well development costs) were expected to be $11.9 million.  At first blush, these metrics indicate a cost per net acre of approximately $180,300, which suggests a notable premium.The next highest cost per net acre value among the transactions listed was $67,000 forthe Pioneer Natural Resources-DoublePoint Energy dealannounced in April.  A premium was paid as far as net acreage acquired is concerned.  However, at the expected peak production rate of 1,400 Boepd, the cost per production unit was $8,500 per Boepd, the second-lowest metric after Contango Oil & Gas’s acquisition in late November, and one-third of the minimum $-per-Boepd metric among the transactions listed in the June 2019-2020 season.  Despite recent volatility in the industry due to energy prices and domestic regulatory changes–whether real or proposed–the economics of the Permian have remained attractive enough to induce Northern Oil and Gas, a stalwart Bakken E&P company, to try its hand in Southeast New Mexico.Vencer Energy Acquires Hunt Oil Company’s Midland Basin AssetsIn late April, Vencer Energy, the U.S. upstream Oil & Gas subsidiary of the Dutch energy and commodity trading giant, Vitol, announced its first investment in the Midland Basin.  While the total transaction value was not disclosed, the acquisition included approximately 44,000 net acres with a total estimated production of 40,000 Boepd.  This represents an estimated total annualized production of approximately 332 Boe per net acre.  This “production density” value (annualized production per net acre) is the second-highest value among the listed transactions, only behind the comparable metric of 376 Boe per net acre indicated from the Pioneer-Double Point deal (with acquired/estimated production of 100,000 Boepd across 97,000 net acres).Ben Marshall, Head of Americas – Vitol, commented on the transaction: “This is an important day for Vencer as it establishes itself as a significant shale producer in the U.S. Lower 48.  We expect U.S. oil to be an important part of global energy balances for years to come, and we believe this is an opportune time for investment into an entry platform in the Americas.  This acquisition represents an initial step to building a larger, durable platform in the U.S. Lower 48.”ConclusionM&A transaction activity in the Permian was a bit of a roller coaster over the past year in terms of deal timing, but the overall story is one of resurgence over the past twelve months relative to the twelve months before it.  Still, despite a renewed interest in acquiring greater acreage and production positions, even greater changes could be on the horizon.  This past week, it came to light that Shell was reviewing its Permian holdings for potential sale, according to certain people familiar with the matter.  However, it is pure speculation at this juncture as to what option(s) Shell may pursue regarding the partial or full sale of the company’s estimated more-than-$10 billion of Permian holdings. Assuming any dispositions, though, this news could portend even more opportunities for continued buy-in into the Permian by existing regional E&P companies and potential new entrants.
How to Value Oil Companies in the Biden Era
How to Value Oil Companies in the Biden Era
Like a small boat navigating a big sea, oil & gas valuations are impacted by a plethora of factors that can change almost instantly. Some factors help in arriving at a shareholder’s destination, others do not.  Some factors the crew can control, others not so much (and some factors are more predictable than others). As this vessel heads for the destination shores of high returns, it must navigate through natural economic influencers such as production risk, commodity prices, supply logistics and demand changes. In addition, it also must face regulatory shifts that the Biden Administration is and could generate in the future such as tax changes, policy shifts and more. Most likely, these policies will create some volatility and headlines, but in the aggregate will not change valuations much. Let us examine a few of these regulatory items and how they might change the course of an oil and gas company’s valuation going forward.HeadwindsThere are several recent policy actions, and some that are being debated that are affecting the industry, primarily by disincentivizing new U.S. production. Actionsalready taken include a moratorium on federal oil & gas drilling permits and a construction stoppage of the Keystone XL pipeline. While it can grab a headline, from a valuation perspective it should not be a direction changing headwind. Most drilling is not done on federal lands, and a lot of companies with existing permits that will allow multiple years of drilling. Even if this becomes an enduring policy, the impact would likely be a revision too, rather than a material reduction of planned drilling activity.There are also some long-standing tax incentives that may be ended as well: the intangible drilling cost deduction and the percentage depletion allowance. Theintangible drilling cost deduction (which expenses as opposed to capitalizes certain drilling costs) has been around for over 100 years, and thepercentage depletion allowance (15% reduction in gross income of a productive well) has also been around nearly that long. The rationale behind both is to encourage investment by allowing tax breaks for development activity by delaying or decreasing cash taxes in any given year. This is an enjoyed benefit for investors and has allowed cash flows to either be higher or come faster than if the tax breaks were nonexistent. This is considered a headwind for the industry However, since many upstream companies are not cash taxpayers these days, and capital expenditure budgets have already been slashed in the past year, this issue (if it comes to pass) may end up being not much more consequential than a slight breeze.Another matter on U.S. producers’ radar is the expectation that Iranian oil sanctions will be lifted. Iran’s president Hassan Rouhani has said that a broad outline to end sanctions has been reached. Since November 2020 Iran’s crude and condensate exports have already gone up and the global market must contend with another 500 thousand barrels a day of exports. The good news is that the market may have already priced this in and WTI is still over $68 per barrel with Brent Crude over $70.TailwindsNot everything coming out of Washington is detrimental to upstream producers. In fact, some of it may end up being materially beneficial over the course of time. One example is the budget proposal to utilize federal funds for plugging old wells. Biden’s $2 trillion infrastructure proposal includes $16 billion for cleaning up disused wells and mines. Long a balance sheet issue for producers, this can has been kicked down the road for decades. The opportunity to be addressed from a subsidized standpoint would be a welcome development for producers. Even if it is executed inefficiently (North Dakota plugged 280 wells for $66 million: approximately $236k per well) as many government actions can be, it could help producers clean up over 50,000 “orphan” wells that can be over 100 years old in some cases. Considering the beating that oilfield service companies have taken in recent years, this initiative could be a shot in the arm for them as well.The other major tailwind is less about a direct policy, but more an indirect derivative of it. As the Biden Administration restricts drilling on federal lands, the supply of oil is (at least somewhat) constrained. Coupled with the multi-trillion dollar federal budget being proposed, these bring about inflationary pressures that are positive for commodities such as oil. As Sir Isaac Newton once said: “For every action there is an equal and opposite reaction.” Oil and gas companies have been consistently sailing towards capital discipline for several years now, as growth is out of favor in comparison to free cash flow. This strategy is expected to start showing fruit as cash flow and dividends become more prevalent in the industry, something that investors have been awaiting.Tempests on The Horizon?One area where headwinds and tailwinds could clash into a storm system is how inflationary pressures could impact production costs. As commodity prices rise, labor and material costs will impact production (particularly new drilling costs). There are varying opinions as to how much and how long the impact of inflation will be, but most analysts I have read agree that it is either coming or already here. One thing to consider is that while oil prices are global, development costs will be more constrained to the U.S.. Another disturbance will also be the costs of mineral rights payments as the shift of production moves to private lands and away from federal lands. Those items could counterbalance some of the expected commodity price gains and are something that should be on management teams’ radars.Mythical KrakensThere are two things that have been mentioned that could have seismic effects on the industry: banning fracking and limiting LNG exports. However, at this point the odds are low enough to place them in the fabled category. There have been state level fracking policies for years already (New York for example), but nothing about banning fracking has ever gone very far federally. Still, some voices who echo this idea are now close to the Biden Administration. Even with the 50/50 Senate split, most think Senator Manchin (D-WV) would never let it happen.The other idea is to choke the nascent Gulf Coast LNG export industry for ESG or other related priorities. However, that is also highly unlikely. A few months ago Energy Secretary Jennifer Granholm said:“[U.S. LNG is often headed to] countries that would otherwise be using very carbon-intensive fuels, it does have the impact of reducing internationally carbon emissions. However, I will say there is an opportunity here, as well, to really start to deploy some technologies with respect to natural gas in the Gulf and other places that we are siting these facilities for that we are obligated to do under the law.”While an argument can be made that there may be some environmental reasons for shutting this down, pragmatically there is little to no way it will happen anytime soon. If it did somehow, the natural gas business in the US would take yet another ship sinking blow.Heading For Home: High ReturnsWhile upsetting a few, the Government’s action is mostly having the effect of accelerating a lot of things investors have pressed for some time now. Capital discipline is positive for prices. Prices have crept up for months, but announcements for more aggressive drilling plans have been sparse. Matador added a rig in February, but the stock price quickly dropped 5%. Most US producers are more wary of OPEC and Russia than they are of the Biden Administration. Besides, many producers have multiple years of drilling inventory already permitted so federal permit moratoriums do not stop drilling in any substantive sense. Capital has already fled the industry, some for economic reasons, some for more ideological reasons. However, if the prices keep going up and cash flow returns become the norm in an inflationary economy, this vessel could make itself a popular destination for high returns in the future.Originally appeared on Forbes.com.
Mineral Aggregator Valuation Multiples Study Released
Mineral Aggregator Valuation Multiples Study Released

With Market Data as of May 26, 2021

Mercer Capital has its finger on the pulse of the minerals market.  An important trend has been the rise of mineral aggregators, which have largely supplanted the trusts as the primary method of publicly traded minerals ownership.Due to a variety of corporate structures (including master limited partnerships and Up-Cs) and complex capital structures (including preferred equity and non-traded common units), mineral aggregator enterprise values pulled from databases are often missing meaningful components of value, leading to skewed valuation multiples.Mercer Capital has thoughtfully analyzed the corporate and capital structures of the publicly traded mineral aggregators to derive meaningful indications of enterprise value.  We have also calculated valuation multiples based on a variety of metrics, including distributions and reserves, as well as earnings and production on both a historical and forward-looking basis.Mineral Aggregator Valuation MultiplesDownload Study
Themes from Q1 2021 Earnings Calls (1)
Themes from Q1 2021 Earnings Calls

Part 2: Mineral Aggregators

Last week, we reviewed the first quarter earnings calls for a select group of E&P companies and briefly discussed the macroeconomic factors affecting the oil and gas industry.  In this post, we focus on the key takeaways from mineral aggregator first quarter 2021 earnings calls.Favorable M&A OutlookTransaction volume was largely muted throughout 2020 as the depressed pricing environment drove bid-ask spreads wider.  Buyers were offering what they believed was supportable based on current market conditions, and sellers were convinced that their assets were being undervalued.  This led to sellers holding onto assets for dear life unless they were forced to liquidate.  As mineral aggregators have the reputation to reinvest capital, participants on the earnings calls were intrigued to learn about their strategy in what many believe may be a price recovery environment.“We had a stock price where we didn't really feel like the equity was a usable acquisition currency, and I think sellers still had higher expectations than the environment warranted.  And so with prices and equity recovering, and frankly where sellers were sitting on those assets for another 12 to 18 months, we think the environment is just getting much more constructive.” –Jeffrey Wood, President & CFO, Black Stone Minerals“Since the third quarter of last year, we've continued deploying capital to mineral acquisitions and believe the assets we've acquired over the past three quarters will generate differentiated performance over the next several years.  We will continue to employ our disciplined underwriting of deals to enhance shareholder value and at the same time see more of our acquisitions internally funded via retained cash.” –Bud Brigham, Founder & Executive Chairman, Brigham MineralsHedgingHedging strategies differed among the aggregators.  Some companies, like Black Stone and Viper, executed hedges that mitigated risk in 2020, but have been a detriment to recent financial performance.  On the contrary, Brigham Minerals stated that their hedging portfolio was minimal which allowed them to participate in the positive pricing environment seen in the first quarter.“As most of you are aware, we have always been active hedgers of our commodity risk. Those hedges benefited us greatly last year when prices cratered, but also tempered the impact of the dramatic rise in prices for us during the first quarter.” –Jeffrey Wood, President & CFO, Black Stone Minerals“First, we did not need to panic at any point during the rollercoaster year of 2020 and execute hedges, which today are currently serving as strong headwinds to numerous companies in the energy space. Here at Brigham, we are managers of a premier mineral portfolio, non-commodity traders and we prefer to give our investors full exposure to the commodity.” –Bud Brigham, Founder & Executive Chairman, Brigham Minerals“Also, we believe our hedging strategy is a prudent methodology for managing the company’s future price risks on oil and natural gas. Having substantial hedges in place on a rolling two-year basis before the price shocks that occurred in 2020 proves to be a very effective risk mitigation strategy.” –Davis Ravnaas, President, CFO & Chairman, Kimbell Royalty Partners“We had a lot of ‘21 hedges put on this year that are unfortunately, underwater because of the recovery. But I think as you think about 2022 and beyond, putting some sort of floor under the low end of distributable cash flow is something we’re thinking about.” –Kaes Van’t Hof, President, Viper Energy PartnersDebt SituationAggregators continued to pay down debt and improve liquidity, which was a major priority heading into the new year.  Relationships with lenders was a concern during 2020, but Jeffrey Wood, President and CFO of Black Stone Minerals, stated that the company was able to execute a favorable extension to their existing debt facility.  This is a positive sign for the industry moving forward.  Aggregators will continue to allocate free cash flow between debt paydown and shareholder return as the year progresses.“After the end of the quarter, we finalized an extension of our existing revolving credit facility last week. We added 2 years to the maturity date of that facility, which is now November of 2024.  It's been a very difficult bank market over the past year, so we're really happy to get this extension done with relatively minor modifications to the terms of the facility and we appreciate the continued support from our long-term lending relationships.”–Jeffrey Wood, President & CFO, Black Stone Minerals“As we have done in previous quarters, the company utilized 25% of its Q4 2020 cash available for distribution to pay down a portion of the credit facility in Q1 2020. Since May 2020, the company has paid down approximately $25 million in debt by allocating a portion of its cash flow to debt paid down.  We expect to continue to allocate 25% of our cash available for distribution for debt pay down in the future.” –Davis Ravnaas, President, CFO & Chairman, Kimbell Royalty Partners“As a result, Viper generated almost $55 million in net cash from operating activities, which enabled us to reduce debt by $27 million during the quarter. We have now reduced total debt by over $136 million, or roughly 20%, over the past 12 months.” –Travis Stice, CEO, Viper Energy PartnersConclusionIt is safe to say that sentiment among the participants was positive in the first quarter earnings calls, especially relative to last year.  Aggregators seemed to grind through 2020 and flip the script for a new year.  Although a price recovery may be in sight, challenges remain, specifically with the Biden Administration taking office.  The calls largely glossed over political implications of the new administration but those issues may come into focus as the year unfolds.Mercer Capital has its finger on the pulse of the minerals market.  An important trend has been the rise of mineral aggregators, which have largely supplanted the trusts as the primary method of publicly traded minerals ownership.  Contact a Mercer Capital professional to discuss your needs in confidence.
Themes from Q1 2021 Earnings Calls
Themes from Q1 2021 Earnings Calls

Part I: E&P Operators

Things appear to be on the upswing, albeit with cautious optimism, in the exploration and production (“E&P”) space.Most of the eight E&P operators we tracked reported that operations in the first quarter were relatively stable.  This was in spite of winter storm Uri, which wreaked havoc from New Mexico and Texas northeast through upstate New York and New England.It may be worth examining the effects of Uri on E&P operators’ Q1 performance more in-depth, with a focus on how natural gas prices may have affected revenues vs. any associated increase in operating expenses or the intangible costs stemming from marketing and sales disruptions.Regardless of Uri’s net effect on financial performance, the ultimate trending phrase in E&P operators’ earnings calls was “positive free cash flow,” indicating continued upward trajectory out of the crude abyss.Deleveraging remains a primary goal for many operators.  Several have resumed their dividend programs, while others have announced special (i.e., non-recurring) dividends to project their positive outlook to investors.In tandem with this bullish perspective, few E&P operators seemed overly concerned with the potential tax implications stemming from regulatory changes brought forth by the Biden Administration.ESGContinuing the trend we saw in the 2020 Q3 and Q4 E&P operator earnings calls, the Q1 earnings calls featured increased discussions regarding ESG topics.  For some operators, the commentary covered basic items such as reduced greenhouse gas ("GHG") emissions and quarter-over-quarter reductions in flaring.  Other operators had more comprehensive talking points related to ESG topics in the context of company operations on a forward-looking basis.“In March, we issued a press release announcing changes to our executive compensation program and outlining our new greenhouse gas emissions reductions targets.  Comprehensive changes to our executive compensation program included accountability for achieving both quantitative and qualitative ESG goals in the near and medium term.”–Joe Gatto, President & CEO, Callon Petroleum“[This year] we introduced methane-related KPIs into our executive compensation program.  We've committed to make a substantial multi-year community investment of $30 million over the next six years to widen the path for the middle class in our local community while growing the local talent pipeline.  We have redoubled our efforts to spend local and hire locally.  100% of our new hires will be from our area of operation and will maintain that - we will maintain at least 90% local contract workforce.” –Yemi Akinkugbe, Chief Excellence Officer, CNX Resources“This year will also be an exciting year for Antero's ESG initiatives as we make progress toward our 2025 best in class goals.  These … include achieving net zero carbon emissions, reducing our industry leading GHG intensity and methane leak loss rates.  We also plan to complete and publish our TCFD analysis with our 2020 ESG performance results later in 2021.”–Glen Warren, CFO, Antero ResourcesReturn of Capital to ShareholdersIn recent earnings calls, many E&P operators suggested that they would resume dividend and share buyback programs when positive free cash flow, and in some cases higher-priority deleveraging initiatives, made it conducive to do so.  As noted in the introduction, this time has come for many operators in Q1.“We reinstated a quarterly dividend of $0.11 per share, … this is double our previously issued dividend, which has been temporarily suspended at the onset of the global pandemic.  We believe this is expected to be sustainable given our strong cash flow generation and interest expense savings from our significant debt reduction.”–William Berry, CEO, Continental Resources“Going forward, our goal is to continue growing the regular dividend.  We have never called for suspending the dividend and we remain committed to its sustainability. … Now, EOG is positioned to address other free cash flow priorities by returning additional cash to shareholders.  The $1 per share special dividend [announced May 6] follows through these consistent long-tailed priorities.”–Tim Driggers, CFO, EOG Resources“So, for the quarter we repurchased 1.5 million shares at an average price of $12.26 per share at a total cost of $18 million.  We still have ample capacity of around $240 million under our existing stock repurchase program…”–Nick Deluliis, CEO, CNX ResourcesProposed Tax ChangesAmong the potential energy tax changes under the Biden-Harris Administration,the most prominent talking point discussed by E&P operators in the Q1 earnings calls was the proposed change to disallow the reduction of taxable income stemming from intangible drilling costs (“IDCs”), and the subsequent increase in taxes and reduction in future free cash flow.  The discussion and response to questions about these proposed tax changes overwhelmingly suggest that most of the operators we tracked do not foresee any material tax payments for at least the next four years, due primarily to substantial net operating losses (“NOLs”) that may be used to offset future taxes.“We are not a cash taxpayer in the U.S. this year.  And at prevailing commodity prices, we don't expect to be paying U.S. cash federal income taxes until the latter part of this decade.  This holds true even if the tax rules for IDCs are changed or if the corporate tax rate has increased.  We have significant tax attributes in the form of NOLs in addition to foreign tax credits.  These attributes will be used to offset future taxes.”–Dane Whitehead, CFO, Marathon Oil“Our plan through '26, we're not material cash taxpayers during that plan.  Most of it's the way we treat sort of the NOLs and utilize those as regards to the cash taxes that we would have to pay, and managing and optimizing that versus sort of the IDCs and the other attributes that you have on the tax side.  So, the color we've given to date is no material cash taxes through 2026 is the current plan.”–Don Rush, CFO, CNX Resources“We have substantial NOL carryforwards at a federal and a state level.  So, if you look at it in a current regime, putting off a free cash flow at the level that we are, certainly, you convert to cash taxes at some point.  We see it being five to seven years in the future in a current regime.”–John Hart, CFO, Continental ResourcesOn the HorizonWhile we selected three primary themes among the Q1 E&P operator earnings calls, several other notable topics were also discussed.  Perhaps chief among them, the general consensus is that significant production growth is not desirable at this juncture.  Steady operations is the name of the game at the moment.  Furthermore, operators are seeing inflation in field service provider costs, which are expected to continue growing, though it remains to be seen just how those may affect future margins.ConclusionMercer Capital has its finger on the pulse of the E&P operator space.  With increased volatility in the energy sector these days, we take a holistic perspective to bring you thoughtful analysis and commentary regarding the full hydrocarbon stream.  For more targeted energy sector analysis to meet your valuation needs, please contact the Mercer Capital Oil & Gas Team for further assistance.
Recent SPAC Boom Largely Leaves Out Oil & Gas Companies
Recent SPAC Boom Largely Leaves Out Oil & Gas Companies
The rise of SPACs, or special purpose acquisition companies, has been the hottest trend in capital markets during the past year.  However, after years of poor returns and increasing investor emphasis on ESG (environmental, social, and governance) issues, oil & gas companies were largely left out of the recent SPAC mania.We look at a few oil & gas companies that were early adopters of the SPAC structure, the recent pivot of SPACs towards energy transition companies, and take a look forward to see what the future might hold for the few remaining oil & gas-focused SPACs.Previous Energy SPAC TransactionsEnergy companies were early adopters of the SPAC structure as a means to go public.Private equity firm Riverstone was one of the first to launch an energy-focused SPAC with Silver Run Acquisition Corp. in 2016.  The SPAC combined with Centennial Resource Production later in the year and renamed itself Centennial Resource Development.  Riverstone followed with Silver Run Acquisition Corp. II in 2017, which acquired Alta Mesa Holdings and Kingfisher Midstream to form Alta Mesa Resources.  However, Alta Mesa filed for bankruptcy in 2019.  Another early energy SPAC suffered the same fate.  KLR Energy Acquisition Corp., which went public shortly after Silver Run in 2016, acquired Rosehill Resources and filed for bankruptcy in 2020.Fortunately, some have fared better.   TPG Pace Energy Holdings merged with Magnolia Oil & Gas in 2018.  Currently, the Eagle Ford operator’s stock price is well above the initial SPAC IPO price of $10.  Vantage Energy Acquisition Corp., sponsored by energy-focused private equity firm NGP, announced acquisition of QEP’s Bakken assets for $1.725 billion in 2018.  The transaction later fell through, and Vantage liquidated, with shareholders receiving $10.22 per share.  QEP’s Bakken assets wererecently acquired by Oasis (from QEP’s new owner Diamondback) for $745 million.The Pivot Toward Energy TransitionGiven the troubled performance of oil & gas SPACs, overall poor returns from the sector, and increasing emphasis on ESG issues, several SPACs that were originally targeting oil & gas companies have pivoted and acquired (or announced acquisitions of) “energy transition” companies.Apollo touted its expertise “in the upstream, midstream and energy services sectors” in Spartan Energy Acquisition Company’s prospectus, though ultimately acquired electric vehicle manufacturer Fisker.  Switchback Energy Acquisition Corporation, sponsored by NGP (which previously sponsored Vantage), was rumored to be targeting companies in the minerals space, but recently completed its acquisition of ChargePoint, which develops electric vehicle charging stations.  And Alussa Energy Acquisition Corp., headed by James Musselman (former CEO of offshore E&P company Kosmos), has announced its planned acquisition of FREYR, a Norwegian battery manufacturer.The trend of capital moving away from traditional oil & gas companies and toward energy transition companies does not look like it will abate soon.  Several private equity funds historically focused on oil & gas have sponsored SPACs specifically targeting energy transition companies.Riverstone has moved away from the Silver Run naming convention and now has three “Decarbonization Plus” entities that are publicly traded, with a fourth that has filed an S-1.  While the entities reserve the right to seek a business combination with a company operating in any sector, I think it’s safe to assume that an acquisition of a company focused on developing hydrocarbons is off the table.First Reserve, which has historically invested in traditional oil & gas companies, launched their first SPAC, First Reserve Sustainable Growth Corp., in March.  As the name implies, the SPAC’sstated focus areawill be “opportunities and companies that focus on solutions, processes, and technologies that facilitate, improve, or complement the ongoing energy transition toward a low- or no-carbon emitting future.”After NGP’s success with Switchback’s acquisition of ChargePoint, it sponsored Switchback II, which intends to search for target companies “in the broad energy transition or sustainability arena targeting industries that require innovative solutions to decarbonize, in order to meet critical emission reduction objectives.”  That language wasn’t included in the original Switchback prospectus.  Another NGP SPAC, Switchback III, has a similar language in itsS-1but has not yet gone public.Warburg Pincus sponsored two SPACs that went public in March.  While no specific industry focus was discussed in the prospectuses, the documents did specifically state that “oil and gas companies are not anticipated to be the target.”  This is consistent with Warburg’s recent transition away from investment in the oil & gas sector.Is SPAC Capital Available for Oil & Gas Companies?While most recent energy-focused SPACs are seeking business combinations in the energy transition space, there are a few remaining SPACs that may target more traditional oil & gas companies or assets.East Resources Acquisition Company went public in July 2020, raising $345 million.  It is headed by Terry Pegula, who sold his previous company, Appalachian operator East Resources, Inc., to Shell for $4.7 billion in 2010.  The SPAC’s prospectus states that “there is a unique and timely opportunity to achieve attractive returns by acquiring and exploiting oil and natural gas exploration and production (‘E&P’) assets in proven basins with extensive production history and limited geologic risk.”In November 2020, Breeze Holdings Acquisition Corp. raised $115 million.  Managed by several former EXCO executives, the SPAC intends “to focus on assets used in exploring, developing, producing, transporting, storing, gathering, processing, fractionating, refining, distributing or marketing of natural gas, natural gas liquids, crude oil or refined products in North America.”Most recently, Flame Acquisition Corp. raised $287.5 million in February 2021.  The SPAC intends to target“a business in the energy industry, primarily targeting the upstream exploration and production (‘E&P’) sector, midstream sector and companies focused on new advancing technologies that are transformative and provide the potential for and means to achieve greater profitability in the broader energy sector,” adding that “many businesses in the E&P industry or broader energy value chain could benefit from access to the public markets but have been unable to do so.”  The company is headed by James Flores, the former CEO of Sable Permian.  Gregory Pipkin, former head of Barclays’ upstream investment banking team, is a member of the board.It remains to be seen whether these SPACs will endure their oil & gas focus or try to capitalize on the trend towards renewables (like so many other energy-focused SPACs).  However, with multiple SPACs targeting that space and increasing investor skepticism regarding lofty growth projections (as evidenced by the stock price performance of former SPACs Nikola, Hyliion, Romeo Power, and XL Fleet, among others), the acquisition of oil & gas assets at an attractive valuation may be well received by investors.ConclusionThe increasing popularity of SPACs helped push tremendous amounts of capital toward energy transition companies, with traditional oil & gas companies largely sitting on the sidelines.  However, the tide may be turning, as SPAC IPOs have slowed and some energy transition company valuations have come crashing down from their previous (stratospheric) levels.  While SPACs aren’t the complete solution to the dearth of capital available to oil & gas companies, a well-received transaction by one of the few remaining oil & gas-focused SPACs would certainly be a welcome development.Mercer Capital cannot help you sponsor a SPAC, though we have assisted many clients with various valuation needs in the upstream oil and gas space for both conventional and unconventional plays in North America, and around the world.  Contact a Mercer Capital professional to discuss your needs in confidence and learn more about how we can help you succeed.
Out of the Crude Abyss
Out of the Crude Abyss
It has been almost a year since crude prices went into the abyss on last April 20th. What a day that was: OPEC’s shoe had already dropped, and the realities of COVID-19’s short term consequences panicked the global oil market into a historic backlog. Crude tankers were stranded on the seas, storage filled up, and for a short while production had nowhere to go.The havoc wreaked on markets was severe. Demand was projected to drop between 20% and 35% by some (consumption actually dropped about 22% per the EIA). Reserve lives for some major producers dropped by around 10 years and between them reported losses north of $60 billion in 2020. To be fair, there are a couple of ways to look at this: one is a market decline in interest in these commodities; another could be rooted in the demand from investors for more nimble balance sheets coupled with the growing ability to develop acreage relatively quickly. Beyond the decline of reserves, (both through production decline and economic characterization), the bankruptcy casualty counts also skyrocketed as I have discussed before. According to the latest Haynes & Boone data, the count was 35 new bankruptcies in the second and third quarters of 2020 and over $50 billion in total debt going into bankruptcy for the full year.What a difference a year makes.Recently WTI closed at over $63, and it has spent most of the past month at or above $60. Many analysts now predict oil to stay in the $60’s (or higher) for the rest of 2021 (EIA on the other hand projects the mid-$50’s). It appears that low prices may have been a cure for low prices.   The Dallas Fed came out with their quarterly Energy Survey a few weeks ago and its results were quite shocking to many. Its business activity index was at its highest reading ever in the five-year history of the survey. Guarded optimism among industry players is creeping back into the picture: “We are optimistic that we will have a weaning of excess oil supply, and more importantly, suppliers of oil and gas, that will lead to a slightly higher sustainable price.” said a respondent to the Dallas Fed. The S&P’s SPDR Oil and Gas Production ETF which dropped to around $30 (split adjusted) in March 2020 is now trading around $80. Production and CapEx spending are emerging as well in response to rising demand. Global oil demand and supply are moving towards balance in the second half of this year, per the IEA’s latest monthly report. In fact, producers may then need to pump a further 2 million bbl/d to meet the demand. OPEC, which has been withholding supply in tandem with other producers including Russia, this week raised its forecast for global oil demand this year. OPEC expects demand to rise by 70,000 bbl/d from last month's forecast and global demand is likely to rise by 5.95 million bbl/d in 2021, it said. Upstream Economics: Back In BlackIt must be relieving to be “let loose from the noose” of low prices. A lot of producers should be singing AC/DC nowadays. It is now profitable to drill a lot more wells than a year ago. Heck, back then existing wells were not profitable, much less undrilled ones. In terms of reserve metrics, I have said before that value erosion usually starts at the bottom categories of a reserve report and moves upwards. Value accretion moves in reverse. The increased pricing is making larger swaths of reserves economic again. Even so, one thing that is different this time around may be the cautiousness of investors and producers to jump back on the drill bit right away. Investors have already been pulling valuations down as their standard tilted more towards shorter term returns as opposed to longer term reserves. Additionally, the Fed Survey was littered with comments expressing concern about the Biden administration’s policies being more aggressive towards regulation and ESG, thus promoting caution for aggressive drilling. In fact, the American Petroleum Institute (of all organizations) is now considering carbon pricing frameworks. Lastly, OPEC+ could yank the rug out from shale producers again if they are perceived as ramping up too quickly, according to Pioneer’s CEO. (It is notable though that Pioneer just bought West Texas producer DoublePoint for $6.4 billion. That’s approximately $30,000 per flowing barrel and $40,000 per undeveloped acre). Next StepsSo where does this leave us? Well, in a lot better place for producers and investors than last year – that’s to be sure. The companies that have hung in this past year and made it are starting to see some improvement. That’s also good because those that utilized PPP money have been in need of price help once the government subsidies ran out.   In addition, with all of the attention towards electric vehicles replacing the combustion engine, we must remind ourselves that only 1% of the U.S. light fleet is EV and that light vehicles only make up 25% of crude oil use. Demand will not be chopped out from oil’s feet just yet.Markets are fast moving and unforgiving at times, but it appears with $60+ oil prices for 2021, that the upstream business can now start to slow down, look around, and evaluate what direction to go next.Originally appeared on Forbes.com.
M&A Focus: The Pioneer-DoublePoint Deal
M&A Focus: The Pioneer-DoublePoint Deal
After what felt like an eternity of quiet transaction activity in the O&G industry, the M&A market in 2021 has been off to a more active start in 2021.According to S&P Global Market Intelligence, the industry announced 117 whole-company and minority stake deals in the first quarter of 2021, an increase of 28 transactions from the same period last year.  The combined deal value has also increased from $3.86 billion to $26.4 billion, as supermajors like Exxon Mobil Corp., Royal Dutch Shell PLC and Equinor ASA divested assets and corporate consolidation continued.  The trend continued early in the second quarter.In this post, we discuss the Pioneer-DoublePoint transaction (the “Transaction”) that could foreshadow for more M&A activity to come.Transaction Summary & Asset DetailsOn April 1, 2021, Double Eagle III Midco 2 LLC, wholly owned by DoublePoint Energy, LLC, announced that it entered a definitive purchase agreement to sell all leasehold interest, subsidiaries, and related assets to Pioneer Natural Resources Company (PXD) in a transaction valued at $6.4 billion.  DoublePoint is a Fort Worth, Texas-based upstream oil and gas company that is backed by equity commitments from funds managed by affiliates of Apollo Global Management, Quantum Energy Partners, Magnetar Capital, and Blackstone Credit.According to Piconeer’s Investor Presentation, the Transaction adds approximately 100,000 Tier 1 Midland Basin net acres to Pioneer’s existing assets.  The bolt-on acquisition will lead to the combined company owning approximately 920,000 net acres in the Midland Basin, making it the largest producer in that area.  The deal is expected to close in the second quarter of 2021.The purchase price is comprised of the following:Approximately 27.2mm shares of Pioneer stock (PXD) based on Pioneer’s closing share price as of 4/1/2021 ($164.60). After closing, PXD shareholders will own approximately 89% of the combined company and existing DoublePoint owners will own approximately 11%.Cash of $1.0bnApproximately $0.9bn of liabilities that includes debt of $650mm at 7.75% and approximately $300mm of reserve-based lending and working capitalPer PXD Investor PresentationThe Transaction implies the following valuation metrics: Pioneer anticipates approximately $175 mm in annual synergies related to G&A, interest, and operations.  The company expects to save approximately $15 mm in G&A by reducing DoublePoint’s expense by 60% in the second half of 2021.  Pioneer also plans to refinance DoublePoint’s bonds after closing to save roughly $60mm.  Last, the company projects about $100 mm in operational savings.  According to Pioneer’s Investor Presentation, the acquired acreage is highly contiguous and largely undeveloped, adding greater than 1,200 high-return locations.  Although the exact amount Pioneer attributed to PDPs and PUDs is unknown, this suggests that PXD most likely associated option value to the undeveloped acreage in their purchase consideration. Mixed Market Signals Investors responded relatively well the day of the announcement (prior to the press release), as PXD’s share price increased 3.64%, closing at $164.60 on April 1.  However, the stock has since produced mixed signals.  The next trading day, April 5, the stock closed at $152.18, a 7.55% decrease from the announcement.  The stock closed at $147.10 on April 21, a 10.63% decrease from April 1.  The company has still performed well in 2021, as PXD share price is up 29.63% year-to-date.  PXD has followed similar trends to the broad E&P value index (as proxied by the SPDR S&P Oil & Gas Exploration & Production ETF, ticker XOP) since the beginning of year, so this decrease may be geared more towards industry sentiment rather than deal reaction. On April 5, 2021 Fitch Ratings released a statement that Pioneer’s ratings are unaffected by the company’s deal announcement with DoublePoint.  On April 22, 2021 Fitch affirmed Pioneer’s long-term issuer default ratings and unsecured debt ratings at BBB.  Fitch also assigned a BBB rating to Pioneer’s 364-day unsecured revolving credit facility.  Fitch notes that their rating outlook for PXD is stable.  Pioneer’s credit rating outlook is a testament to its strong balance sheet and 2021 estimated net debt / EBITDAX of 0.9x. ConclusionThe Pioneer-DoublePoint transaction could set the stage for an active M&A market relative to a quiet 2020.  Also, Pioneer’s Fitch Rating could serve as a positive signal for utilizing leverage in future deals.  It will also be interesting to monitor deal values as it relates to what buyers are willing to pay for specific producing and non-producing assets (to the extent that the information is disclosed).  If an industry recovery is in sight, transaction activity could continue its healthy pace, but also has the potential to soften if uncertainty looms, causing the bid-ask spread to widen if buyers and sellers are not on the same page.We have assisted many clients with various valuation needs in the upstream oil and gas industry in North America and around the world.  In addition to our corporate valuation services, Mercer Capital provides transaction advisory services to a broad range of public and private companies and financial institutions.  We have relevant experience working with companies in the oil and gas space and can leverage our historical valuation and experience to help you navigate a critical transaction, providing timely, accurate and reliable results.  Contact a Mercer Capital professional to discuss your needs in confidence.
Solvency Opinions: Oil & Gas Considerations
Solvency Opinions: Oil & Gas Considerations
The Key QuestionAs 2020 progressed, a record number of oil & gas operators and related oil field service companies filed for Chapter 11 bankruptcy, which provides for the reorganization of the firm as opposed to full liquidation (Chapter 7).  In addition, consolidation by way of merger and acquisition (“M&A”) activity occurred, albeit such activity was at a 10-year low in 2020. Regardless of whether a company files for Chapter 11, is party to an M&A transaction, or executes some other form of capital restructuring – such as new equity funding rounds or dividend recaps – one fundamental question takes center stage: Will the company remain solvent?The Four TestsAs noted in our overview of solvency opinions last November, leveraged transactions that occurred pre-COVID-19 will continue to be scrutinized, with many bankruptcy courts considering the issue of solvency retroactively.  Due to increased energy price volatility in the first and second quarter of 2020, many operational and dividend programs were suspended.As oil & gas prices have stabilized and appreciated over the past one to two quarters (in its April Short-Term-Energy Outlook report, EIA projects WTI and Brent to average $58.89 and $62.28 per barrel, respectively), a large number of oil & gas operators have significantly reduced their debt, and are considering or have resumed their operational plans and dividend programs, albeit perhaps not exactly as before their suspension.Emerging from the chaos of 2020 with lower leverage, leaner and more efficient operations, higher commodity prices, and the continued low interest rate environment, it is not unreasonable to think that oil & gas companies may consider increasing leverage again as operations continue to recover or expand and boards approve the return of capital to shareholders by way of resuming regular or even special dividends.Often, a board contemplating such actions will be required to obtain a solvency opinion at the direction of its lenders or corporate counsel to provide evidence that the board exercised its duty of care to make an informed decision should the decision later be challenged.A solvency opinion, typically performed by an independent financial advisor, addresses four questions:Does the fair value of the company’s assets exceed its liabilities after giving effect to the proposed action?Will the company be able to pay its debts (or refinance them) as they mature?Will the company be left with inadequate capital?Does the fair value of the company’s assets exceed its liabilities and capital surplus to fund the transaction?A solvency opinion addresses these questions using four primary tests:Test 1: The Balance Sheet Test – Does the fair value and present fair salable value of the Company’s total assets exceed the Company’s total liabilities, including all identified contingent liabilities? The balance sheet test takes the fair value of the subject firm on a total invested capital basis and subtracts its liabilities. Test 2: The Cash Flow Test – Will the Company be able to pay its liabilities, including any identified contingent liabilities, as they become due or mature? The cash flow test examines whether projected cash flows are sufficient for debt service.  This is typically analyzed along three general dimensions, including the determination of the company’s revolving credit facility to manage cash flow needs over the forecast, the possible violation of any applicable covenants, and the likely ability to refinance any remaining debt balances at their maturity. Test 3: The Capital Adequacy Test – Does the Company have unreasonably small capital with which to operate the business in which it is engaged, as management has indicated such businesses are now conducted and as management has indicated such businesses are proposed to be conducted following the transaction? The capital adequacy test is related to the cash flow test and examines a company’s ability to service its debt with sufficient margin after giving effect to the proposed transaction.  While there is no bright line test for defining “unreasonably small capital”, we typically evaluate this concept based upon pro forma and projected leverage multiples utilizing management’s projections as a baseline scenario and alternative downside scenarios to determine if there is “unreasonably small capital” under more stressed conditions. Test 4: The Capital Surplus Test – Does the fair value of the Company’s assets exceed the sum of (a) its total liabilities (including identified contingent liabilities) and (b) its capital (as calculated pursuant to Section 154 of the Delaware General Corporation Law) The capital surplus test replicates the valuation analysis prescribed under the balance sheet test, but includes the par value of the company’s stock (or entire consideration received for the stock if no par value is given), in the amount subtracted from the fair value of the company’s assets.Solvency Considerations within Oil & GasPerforming a solvency opinion requires careful consideration of numerous factors even when everything clearly appears to be more or less favorable in a proposed transaction that involves increasing leverage.  It may be opportune to pursue a dividend recap as debt is cheap and the company is already exhibiting strong growth in an industry potentially starting to recover.  A company may increase leverage despite already having sufficient cash on hand for a special distribution, but it wants to maintain flexibility to act on unexpected growth opportunities that may arise.  Perhaps the company’s trajectory is so great that even its downside case(s) would be a lofty goal of the next closest competitor.  Still, the independent financial advisor must maintain a critical eye, taking a medium- to long-term perspective with a skeptic lens, to determine that the company may reasonably remain solvent.Now, consider the oil & gas sector in 2020.  Under the assumption that additional debt is needed just to survive, never mind paying special dividends, many additional questions to approaching the company’s baseline forecast and downside scenarios arise:If the fair value of the company’s assets is already greatly diminished in the current down cycle, how much should you temper – if at all – the downside future scenario(s) when conducting the capital adequacy test? An appropriate stress test scenario for a company at the top or mid-point of the business cycle may look far different from an appropriate stress at the bottom of the cycle.How will the balance sheet test fare given the concurrent decrease in asset fair value and increase in liabilities? Even if the capital adequacy and balance sheet tests do not raise any red flags on their own, the cash flow test may reveal significant concerns.  Is there enough flexibility with the existing revolver to address cash flow needs over the forecast, or will it need to be increased?  Could the revolver even be increased, if needed?Can the company financially perform well enough over the next three to five years that future (likely) higher interest rates won’t be overly burdensome if the company must refinance maturing debts?And while due diligence and financial feasibility studies are expected to be performed beforehand, what covenant violations are likely to occur and when (in the context of the forecast scenario)? Will the new debt be “covenant-light” and relatively toothless, or will the company find itself that much more constrained when the fangs sink in and the situation is already likely to be dire? While conversations regarding these questions and their implications may likely expose sensitive topics, these discussions must be candid if the independent advisor is to develop a well-founded and defensible opinion on the prospects of solvency. Mercer Capital renders solvency opinions on behalf of private equity firms, independent committees, lenders and other stakeholders that are contemplating a transaction in which a significant amount of debt is assumed to fund shareholder dividends, an LBO, acquisition or other such transaction that materially levers the company’s capital structure.  For more information or if we can assist you, please contact us.
Eagle Ford Benefits From Commodity Price Increases Despite Challenges
Eagle Ford Benefits From Commodity Price Increases Despite Challenges
The economics of oil and gas production vary by region. Mercer Capital focuses on trends in the Eagle Ford, Permian, Bakken, and Marcellus and Utica plays. The cost of producing oil and gas depends on the geological makeup of the reserve, depth of reserve, and cost to transport the raw crude to market. We can observe different costs in different regions depending on these factors. This quarter we take a closer look at the Eagle Ford.Production and Activity LevelsEstimated Eagle Ford production declined approximately 23% year-over-year through March.  This is the most severe decline observed for all of Mercer Capital’s coverage areas, with production in the Bakken, Permian, and Appalachia down 19%, down 8%, and up 3%, respectively.  In the immediate aftermath of the Saudi/Russian price war and historic rout in oil prices, the Eagle Ford’s production decline was less severe than what was seen in the Bakken, though the rebound in the Eagle Ford was also more muted.  During the fourth quarter of 2020, Eagle Ford production trended downward once again and appears to have been materially impacted in February 2021 by the cold weather that disrupted power supplies throughout Texas. However, the Eagle Ford’s rig count has generally been rising over the past six months.  Total rigs in the Eagle Ford stood at 31 as of March 26, down over 50% from the prior year, but more than 3x higher than the low of 9 rigs observed in September 2020.  Bakken, Permian, and Appalachia rig counts were down 71%, 42%, and 19% year-over-year, though have all rebounded from the September lows (though not as dramatically as the Eagle Ford’s rise since then). While recent data has been noisy, and the Eagle Ford’s current rig count should keep production relatively flat, based on legacy production declines and new-well production per rig. Commodity Prices Stabilize, Though Uncertain Demand Dynamics RemainThe first quarter of 2021 was relatively good for commodity prices, though they exhibited more volatility than in recent quarters.  Front-month WTI futures began the quarter at ~$48/bbl and increased to a peak of $66/bbl before ending the quarter at ~$59/bbl.  Henry Hub natural gas front-month futures prices broke above $3/mmbtu in February 2021, though regional spot prices were much more volatile as cold weather disrupted gas production and transmission while also increasing demand for heat and electricity.Financial PerformanceThe Eagle Ford public comp group had a banner year for stock price performance over the past twelve months, with Penn Virginia, Silverbow, Mongolia, and EOG up 334%, 215%, 187%, and 102%, respectively.  All except EOG outperformed the broader E&P sector, as proxied by XOP (which was up 157% during the past twelve months).  However, that stock price performance is largely driven by the exceptionally low starting point in March 2020, as the Saudi/Russian price war and reduced demand due to COVID-19 lockdowns created significant concern among investors regarding the financial position of E&P companies, especially those with significant leverage.  Stock prices for the four companies remain below all-time highs.EOG Doubles Down on “Double Premium” LocationsIn their Q4 2020 earnings call and presentation, EOG touted its inventory of “Double Premium” locations, which meet EOG’s new return hurdle of 60% Direct After-Tax Rate of Return (ATROR) at $40 oil and $2.50 natural gas.  While not clearly defined, EOG describes Direct ATROR as including “the costs associated with drilling and completion operations and well site facilities.”  All-In ATROR, which is more akin to a full-cycle calculation, “includes such costs as well as (i) the costs associated with other facilities, lease acquisitions, delay rentals and gathering and processing operations and (ii) geological and geophysical costs, exploration G&A costs, capitalized interest and other miscellaneous costs.”  Per EOG’s presentation, roughly half of EOG’s 11,500 premium locations fit the underwriting criteria to be classified as “double premium.”However, E&P companies have long been criticized for touting well-level IRRs and other bespoke financial metrics that imply phenomenal economics, but don’t seem to result in corresponding corporate-level returns. We’ll see if EOG’s more stringent underwriting standards translate to shareholder returns.ConclusionThe Eagle Ford was among the regions hardest hit by low commodity prices.  The recent increase in rig count bodes well for stemming production declines, though more rigs are likely needed for material production growth given natural declines in existing production.  However, with investors and E&P management teams focused on returns rather than growth, current commodity prices may not lead to the expansion in the activity that’s been seen in previous cycles.We have assisted many clients with various valuation needs in the upstream oil and gas space for both conventional and unconventional plays in North America, and around the world.  Contact a Mercer Capital professional to discuss your needs in confidence and learn more about how we can help you succeed.
EP Second Quarter 2021 Permian Basin
E&P Second Quarter 2021

Permian Basin

Permian Basin // The second quarter of 2021 saw rising commodity prices across the board, with WTI and Henry Hub surpassing $70/bbl and $3.50/ mmbtu, respectively.
Eagle Ford M&A
Eagle Ford M&A

Transaction Activity Slows Amid Challenges of 2020

Over the last year, deal activity in the Eagle Ford was relatively muted after the impact that the Saudi-Russian conflict and COVID-19 had on the price environment.  M&A deals were largely halted in the second quarter of 2020 as companies turned to survival mode amid challenging realities.  Frankly, transaction due diligence was most likely last on companies’ agendas.  However, announced, and rumored transactions in the Eagle Ford picked up, relative to early 2020, towards the second half of the year as a price recovery began to take hold.Recent Transactions in the Eagle FordA table detailing E&P transaction activity in the Eagle Ford over the last twelve months is shown below.  Relative to 2019, deal count decreased by four, and median deal size declined by approximately $74 million, however it is important to note the small sample of disclosed deal metrics.Chevron Adds to Eagle Ford Play and Global Portfolio with Noble AcquisitionOn July 20, 2020, Chevron announced that it was acquiring Noble Energy, Inc. in an all-stock transaction valued at $10.38 per Noble share, based on the price of Chevron’s stock before the announcement and an exchange ratio of 0.1191 Chevron shares per Noble share, representing an approximate premium of nearly 12% on a 10-day average based on the closing prices as of July 17, 2020.  The total enterprise value of the deal (including debt) was pegged at $13 billion in the transaction press release.  The deal closed on October 5, 2020, marking the completion of the first big-dollar energy deal since the market turmoil began in March 2020.  The acquisition makes Chevron the second U.S. shale oil producer behind EOG Resources, Inc.  Noble’s international plays also add 1 Bcf of international natural gas reserve to Chevron’s portfolio.  Noble Energy’s domestic plays include the Permian Basin, Denver-Julesburg Basin, and the Eagle Ford.Ovintiv Further Deleverages with Eagle Ford Asset SaleOn March 24, 2021, Ovintiv Inc. agreed to sell its South Texas assets for $880 million to Validus Energy (portfolio company of Pontem Energy Capital), a privately owned operator.  The transaction occurred roughly two weeks after sources rumored that Ovintiv was in advanced discussions to divest its Eagle Ford assets.  The deal announcement comes shortly after Ovintiv’s debt reduction initiative outlined in February 2021, which includes generating approximately $1 billion by divesting certain domestic and international assets.  In 2019, Ovintiv’s debt increased to nearly $7 billion after its purchase of Newfield Exploration.  The company aims to reduce debt by 35% to about $4.5 billion by 2022 in order to gain investor confidence.  The company announced that the transaction will allow them to reach the debt target by the middle of next year.  Ovintiv has divested two geographic positions in consecutive quarters, with the first sale being their Duvernay position in Q4 2020.  The company’s Eagle Ford position was purchased for $3.1 billion in 2014 from Freeport-McMoRan Inc.  The company expects the deal to close in the second quarter of 2021.ConclusionM&A transaction activity in the Eagle Ford was fairly quiet throughout 2020 before Chevron’s $13 billion deal with Noble Energy.  The Chevron-Noble Energy transaction and the Ovintiv-Validus deal could be foreshadowing a busier M&A market in 2021, whether companies try to bolt onto previous acreage, or are forced to divest to pay down debt.Mercer Capital has assisted many clients with various valuation needs in the upstream oil and gas industry in North America and around the world.  In addition to our corporate valuation services, we provide investment banking and transaction advisory services to a broad range of public and private companies and financial institutions.  Our Professionals also have relevant experience working with companies in the oil and gas space and can leverage our historical valuation and investment banking experience to help you navigate a critical transaction, providing timely, accurate, and reliable results.  Contact a Mercer Capital professional to discuss your needs in confidence
Chasing Waterfalls: How Volatile Equity Structures Are Changing Returns
Chasing Waterfalls: How Volatile Equity Structures Are Changing Returns
Oil and gas asset values have experienced tremendous volatility over the past year. They have almost returned to where they started in 2020. However, most investors have experienced that unpredictable possibility differently than their assets have since they are not actually participating directly in assets. I am not just talking about debt leverage effects here either. Instead, people are investing in an entity that, in turn, owns and operates a group of assets. These equity and entity structures can change volatility exposure depending on how it is constructed. This includes what is known by multiple names, but generally called an equity distribution waterfall. Investopedia defines a distribution waterfall as “a way to allocate investment returns or capital gains among participants of a group or pooled investment.” The operative word there is “allocate.”Distribution waterfalls are mechanisms to allocate not only profit but also risk. Frequently found in joint venture arrangements and other financing structures such as DrillCos, distribution waterfalls have become a popular arrangement in recent years. The possibilities of an equity allocation are technically and practically endless yet generally negotiable. However, they often follow a typical framework. First, there is usually language in agreements for return of capital provisions, often followed by a preferred return provision. Lastly, residual returns are then usually subject to some form of payout split between investors. Some investors provide capital at the outset of the project which is a key economic factor for the distribution waterfall. Other investors provide non-capital contributions such as management expertise, technology, or assets in-kind. These different contributions can be beneficial to the entity by improving capital efficiency, synergizing expertise, creating optionality in varying respects or accelerating development timing.Things get interesting when contributions convert into distributions from a sale or liquidity event. Each investor can have different return profiles depending on the waterfall structure. Incentives can vary too. Sometimes they can be aligned, other times not so much. Take a hypothetical and simplified example; An upstream partnership is formed between an investor with mostly capital and a knowledgeable management team. $10 million of capital is provided to fund the assets in a domestic play with $9 million contributed by the investor and $1 million by the management team. No debt is procured. Each investor agrees that the distribution waterfall will begin with a return of each investor’s capital pro-rata, then secondly earn a 7% preferred return, lastly, residual cash flow is split 70/30. The management team runs the business and is reasonably compensated during this time. In five years, they sell the assets for $13.5 million.[caption id="attachment_36425" align="alignnone" width="777"]Hypothetical example of the waterfall analysis | Source: Mercer Capital[/caption] The returns for the partners might look something like this: [caption id="attachment_36429" align="alignnone" width="618"]Hypothetical example of the waterfall analysis | Source: Mercer Capital[/caption] At first glance, this appears pretty simple. The payout made it only through the first two tiers of the waterfall with no residual cash flow to split in the 70/30 tranche. Everyone makes out the same. However, look at what happens when the total equity returns notch up to say $20 million in that same five-year period in this structure: [caption id="attachment_36427" align="alignnone" width="640"]Hypothetical example of the waterfall analysis | Source: Mercer Capital[/caption] Both investors benefit in this scenario, but now the management team (general partner) has much higher relative return metrics relative to its original investment. In fact, they’ve more than doubled the limited partners’ returns from an IRR perspective and had over one turn better from a cash-on-cash perspective. That is great, however, this example assumes strong returns. That has not been the reality for most oil and gas ventures in the past year. What happens when asset values go down? First, holding periods are sometimes extended if they can be to attempt to ride out the storm. In addition, further investments, and capital expenditures typically get trimmed, which can conserve cash but this can also generate strain on business plans, growth and holding periods leading to disagreements between management and investors on which path to take. Take the same example and assume a $5 million total return pot: [caption id="attachment_36428" align="alignnone" width="614"]Hypothetical example of the waterfall analysis | Source: Mercer Capital[/caption] The limited partner in this example has lost 9x as much as the general partner management team because they had that much more to lose. Now, most parties prefer not to absorb that type of loss so what can also happen is the parties can extent holding periods in the hope that the time value optionality can prove fruitful to higher asset values later down the line. This can work, but not always. The math is relatively straightforward in a liquidity event. But what about transactions that occur prior to a liquidity event? How do you account for the different payoff structures for components of the capital stock? This is increasingly relevant as liquidity events have been deferred considering market conditions, and management teams are having difficult conversations with sponsors as portfolio companies are being consolidated (often referred to as “SmashCos”). NGP did this last year with some of its portfolio companies. Quantum Energy Partners did this for two of its Haynesville Midstream companies as well. This brings up a delicate issue of how to re-allocate management’s equity ownership. The payoff structure of the waterfall is critical, as the value of a capital component does not necessarily equal its value under a liquidation scenario today. Just like stock options, certain capital components have optionality that results in incremental value over what is implied by the company’s current value. I have dealt with these option pricing models and scenario analyses, and sometimes they can reflect significant value beyond what a simple waterfall allocation might imply. What is clear is that returns for the same asset can diverge quickly among different equity classes can end up being dramatically different over the course of an investment. Therefore, how they are set up can heavily influence the sometimes-delicate dance between equity holders. When asset values are high, then tensions among investors tend to ease, but in environments such as what we have seen recently, it can exacerbate them too. Originally appeared on Forbes.com on March 10, 2021.
Mineral Aggregator Valuation Multiples Analysis
Mineral Aggregator Valuation Multiples Analysis

Market Data as of March 12, 2021

Mercer Capital has its finger on the pulse of the minerals market.  An important trend has been the rise of mineral aggregators, which have largely supplanted the trusts as the primary method of publicly-traded minerals ownership.Due to a variety of corporate structures (including master limited partnerships and Up-Cs) and complex capital structures (including preferred equity and non-traded common units), mineral aggregator enterprise values pulled from databases are often missing meaningful components of value, leading to skewed valuation multiples.Mercer Capital has thoughtfully analyzed the corporate and capital structures of the publicly traded mineral aggregators to derive meaningful indications of enterprise value.  We have also calculated valuation multiples based on a variety of metrics, including distributions and reserves, as well as earnings and production on both a historical and forward-looking basis. Download our report below. Mineral Aggregator Valuation MultiplesDownload Analysis
Themes from Q4 2020 Earnings Calls (1)
Themes from Q4 2020 Earnings Calls

Mineral Aggregators

Last week, we reviewed the fourth-quarter earnings calls for a select group of E&P companies and briefly discussed the macroeconomic factors affecting the oil and gas industry.  In this post, we focus on the key takeaways from mineral aggregators' fourth-quarter 2020 earnings calls.Status of M&A Activity Transaction activity was quiet for the majority of 2020 as commodity prices plummeted and companies entered survival mode.  Aggregators explained that the bid-ask spread between buyers and sellers was wide throughout the year, but some believe that 2021 will offer a more active M&A environment due to their favorable outlook of an industry recovery.I think what we saw in late '19 and all of '20 is that the sellers, many of whom had acquired their assets in a different commodity environment and more active M&A environment, more expensive M&A environment, frankly. We're not looking to part with those assets in a cheaper, less expensive, less active M&A environment. And so, you just – you had a bit of a mismatch between sellers and buyers who had had their cost of capital beat up pretty hard. – Jeffrey Wood, President & CEO, Black Stone MineralsThe acquisition market was slow in 2020 as sellers did not want to part with assets at low prices, buyers were dealing with the high cost of capital and limited new capital availability and/or unwillingness to take on additional debt. – Tom Carter, CEO & Chairman of the Board, Black Stone MineralsWhen you look at the buyer and the seller, where you had an unsustainable, for example, commodity price period, it makes it more difficult for either the buyer or the seller to transact. And so that has been an impediment, but I think coming out on the other side of that cycle, having been at a more – a less volatile environment at a more constructive macro environment should be beneficial. – Bud Brigham, Founder & Executive Chairman, Brigham MineralsI think it’s all trending in a rational direction on the M&A front and I expect – not only us but also our other public peers to benefit from that. And then the other thing I’d say is people are getting used to selling for equity. We’re not going to lever up this business. – Davis Ravnaas, President, CFO & VP of Business Development, Kimbell Royalty PartnersRig Count & Production Recovery in SightAggregators were pleased to see a production and rig count recovery in sight.  Production curtailments were put in place in response to the challenging price environment beginning in Q2, but many believe that the worst is behind the industry.  Production levels remain down year-over-year, but companies are optimistic that they will continue to rise.In the fourth quarter, we began to see a strong recovery in drilling activity on our acreage, with a 30% increase in our rig count, coupled with good sequential improvements in commodity prices and revenue. We are optimistic about 2021 and the continuation of improvements in drilling activity, which is demonstrated by a 14% increase in the Baker Hughes Lower 48 rig count in February 2021 relative to year-end 2020. – Bob Ravnaas, Chairman & CEO, Kimbell Royalty PartnersAs of year-end, there were 38 rigs active on our acreage, and the count has grown to 50 rigs by the end of January. This is above the 29 rigs operating on us at the end of the third quarter, but it's down sharply from activity levels we saw a year ago. – Tom Carter, CEO & Chairman of the Board, Black Stone MineralsWe saw the rig count in those basins in the mid-500s in February of last year and then saw them decrease to around 150 rigs during the third quarter. In the fourth quarter, we saw a 40% rebound in the rig fleet, followed by a further 15% increase so far in the first quarter of 2021. As a result, we sit today up approximately 70% from the low point, but still around 300 rigs short of February a year ago. – Bud Brigham, Founder & Executive Chairman, Brigham MineralsViper also benefited from third-party operated well performance and timing of wells being turned to production outperforming our prior conservative expectations, which had been lowered due to the uncertainty presented by the volatile oil prices experienced early last year. – Travis Stice, CEO, Viper Energy PartnersAggregators Acting on Priorities Since mid-2020, a central theme of E&P companies and aggregators was to shore up balance sheets.  Most aggregators delivered on their deleveraging agenda, whereas others, like Brigham Minerals, had no debt and were able to capitalize on the low-price environment.  Aggregators are optimistic that their leverage levels will not be of concern entering the new year.Our first strategic priority was to further strengthen our liquidity and balance sheet position. We moved very early on in the year with aggressive actions to reduce our costs and reduce our debt.  Over the course of the year, we paid down a total of $273 million of outstanding borrowings under our credit facility, funded by the proceeds from 2 asset sales that we completed in July, and from retained cash flow. – Tom Carter, CEO & Chairman of the Board, Black Stone MineralsThe company paid down $21 million of debt in 2020, and we plan to continue to allocate 25% of cash available for distribution to pay down a portion of our credit facility each quarter. – Bob Ravnaas, President, CFO & Chairman, Kimbell Royalty PartnersThe truly unique nature of Viper's business model is highlighted by the fact that during the fourth quarter alone, we were able to declare a $0.14 distribution, repurchase over 2 million units, and repay over $40 million in debt. Over the past nine months, we have now reduced total debt by $110 million or roughly 16% over this period. – Travis Stice, CEO, Viper Energy PartnersIn an entirely differentiated position, Brigham entered this disruption with no debt and flushed with cash. Having lived through tremendous volatility in the past, we were compelled to take bold action to compound value for our shareholders when others could not or did not want to. – Bud Brigham, Founder & Executive Chairman, Brigham MineralsConclusionBud Brigham, Founder and Executive Chairman of Brigham Minerals, summed up the last year in a nutshell on the company’s fourth-quarter earnings call, “The entirety of 2020 was filled with unprecedented volatility, triggered by the COVID-19 pandemic and the OPEC crisis from crude oil pricing to rig counts to frac crews as well as individual company performance. We started 2020 with $60 oil.  Amazingly, it briefly went negative, and then oil spent most of the year around $40 to $45 per barrel. Markets have been healing. And today, we sit here with oil above $60 per barrel.”  Aggregators seem ready to turn the page and enter 2021 with bullish hopes of a full industry recovery.Mercer Capital has its finger on the pulse of the minerals market.  An important trend has been the rise of mineral aggregators, which have largely supplanted the trusts as the primary method of publicly-traded minerals ownership.  Mercer Capital has thoughtfully analyzed the corporate and capital structures of the publicly traded mineral aggregators.  Contact a Mercer Capital professional to discuss your needs in confidence.
Themes from Q4 2020 Earnings Calls
Themes from Q4 2020 Earnings Calls

E&P Operators

As discussed in our recent blog post regarding tempered mineral and royalty valuations despite recent oil price gains, sentiment towards the oil & gas sector turned bullish as the fourth quarter progressed, with WTI crude spot prices surpassing $40/barrel and – more importantly – generally staying the course on an upward trajectory to close out the year.  Over the fourth quarter, WTI spot prices rose 21% from $40.05/barrel at the close of September 30 to $48.35/barrel at December 31.  Similarly, Brent spot prices increased 27% from $40.30/barrel to $51.22/barrel over the fourth quarter.One key factor supporting this price appreciation was OPEC’s decision to not flood the global market with crude oil.  The election in November concluded with the election of Biden to the White House, a Democratic majority in the House, and uncertainty in the Senate as Georgia would have runoff elections in early January with its two seats – both held by Republican candidates – challenged by Democratic candidates.Despite little indication as to what, precisely, the legislative branch would look like following the Georgia Senate runoff elections, the national election results up to that point made it clear that the oil & gas industry would most likely face headwinds from Washington D.C. with respect to industry operations.  Energy prices, however, did not seem to reflect a change in course either way.  In this post, we capture the key takeaways from fourth quarter 2020 earnings calls from E&P operators.Heightened Caution Regarding Price VolatilityThroughout the earnings calls, the absence of COVID-19 as a factor of uncertainty was particularly striking.  The majority of references to the pandemic were in passing, usually to provide context of the operational status in the fourth quarter 2020 relative to the same period in the prior year.  Only one company executive, Harold Hamm of Continental, directly cited the role of public optimism regarding vaccinations as a driving factor behind the recent rebalancing of global crude oil inventories.It appears as though the impact of the COVID pandemic on energy demand is no longer considered as much of a wildcard in E&P operators’ forecasts as it was earlier in the year.While the pandemic is no longer a surprise, with operators fairly optimistic about short-term (1 to 3 years) projections, there is still the poignant memory of crude oil futures prices dipping into negative territory nearly a year ago.  Yes, it has almost been a year already.  The memory is indeed still very fresh, and operators are looking to protect themselves accordingly, whether via hedging or with greater conservatism regarding return of capital to shareholders by way of dividends.“Our hedge book really helps on just the comfort and confidence and what these cash flows look like for the next several years with approximately 90% [of volumes hedged] in 2021.  We already have a material position in 2022.  And then if you look at 2023 and 2024, it's getting close to almost being 50% hedged…”–Don Rush, CFO, CNX Resources Corp.“Historically, [Occidental Petroleum has not] regularly engaged in hedging, preferring to realize the prices over the cycle, that delivers the most buyer shareholders.  But we did…take on an oil hedge in 2020 that had a collar in 2020, but then it also had a call provision in 2021.”–Rob Peterson, CFO, Occidental Petroleum Corp.“[We are] sticking with our priorities of managing capital expenditures supportive [of a] flatter production profile, then combined with protective hedges allows for maximum free cash flow generation, strong liquidity and debt reduction in long-term price recovery...”–Roger Jenkins, CEO, Murphy Oil Corp.“Our primary focus will be debt pay down, but we are also focused on the eventual reinstating of our dividend…  At this time, we would like to build more protection against price volatility by paying down debt, but our management and the board are aligned in wanting to see the return of a sustainable and growing dividend sometime in the near future.”–John Hart, CFO, Continental Resources, Inc.Positive Free Cash Flow Despite the price volatility leading up to the fourth quarter, many operators either posted annual free cash flows well in advance of projections, or at least finished 2020 on a positive note.“2020 marked the most successful year we've seen as an E&P and, frankly, as a public company going back to the late 1990s, as measured by free cash flow…Our original guidance for 2020 free cash flow is around $135 million, compared to over the $356 million that we actually posted.”–Nick Deluliis, President & CEO, CNX Resources Corp.“Our fifth consecutive year of free cash flow, we said, we'd generate $200 million.  We generated nearly 40% more, $275 million.”–William Berry, CEO, Continental Resources, Inc.“Even as activity levels increased in the fourth quarter and we returned to paying deferred dividends and cash, we still generated approximately $800 million of free cash flow…”–Rob Peterson, CFO, Occidental Petroleum Corp.“Free cash flow during the quarter was $155 million.” –Glen Warren, Jr., Antero Resources Corp.ESGCompared to our review of themes in the third quarter E&P earnings calls, the fourth quarter earnings calls had a bit more discussion concerning ESG initiatives, including plans of action beyond “we expect to publish our ESG plan soon.”“Our enhanced oil recovery projects [have] turned into an ability for us to create a new business that not only will add additional value for our shareholders over time but reduces emissions in the world.  We'll be the leaders in helping to test direct air capture technology, put it in place, make it operational and commercial, and that will provide an opportunity for others to expand it in the world.”–Vicki Hollub, President & CEO, Occidental Petroleum Corp.“From a big picture perspective, if you look at sustainability and ESG…we translate what that means into really three crucial legs.  One, you got to be transparent…  Two, tangible, okay, these things, these targets, these metrics need to be measured.  They need to be tangible.  Like what did we actually deliver on?  And then the third piece of this is actions, right.  I think it's pretty simple across those three, but despite all the talk and the volume of stuff that's being bantered about across those metrics, I think those three things are lacking quite a bit.  We want to be in the camp of, ‘Hey, here's what we're going to do, transparently.  Here's what we're going to measure and accomplish tangibly.  And then here's what our actions were that were consistent with those two things.’” –Nick Deluliis, President & CEO, CNX Resources Corp.“Our operations team continues work on minimizing our environmental impact such as building a new produced water handling system, as well as utilizing bi-fuel hydraulic frac spreads on all well completions in Canada, which results in considerable CO2 emissions reductions.  While smaller changes individually, they add up to a larger impact over time.” –Roger Jenkins, CEO, Murphy Oil Corp.On the HorizonThroughout 2020, the oil and gas sector was rife with uncertainty regarding the COVID pandemic and its short- and long-term impacts on the energy markets.  From some perspectives, there were 47 E&P operator bankruptcy filings in 2020.  The worst year in the past 5 years in terms of the number of E&P operator bankruptcy filings was 2016, with 70 filings.  However, some E&P operators proved that operational and capital discipline could still result in free cash flow sufficient to reduce debt and return capital to shareholders.Despite the upward trend in crude oil and natural gas strip prices in the fourth quarter and generally favorable sentiment that the trend would likely continue into and through 2021, there was very little commentary on expectations of increasing rig activity.Perhaps more surprisingly, and with the exception of Murphy Oil’s earnings call, there was also not much discussion regarding the Biden-Harris administration and its actions and intentions, which generally provide for stronger headwinds coming from Washington D.C. than what the industry has been used to over the prior four years.We expect a clearer picture of E&P operators’ perspectives regarding future changes in the “boots on the ground” and regulatory environment in our next review of first-quarter 2021 earnings call themes.For more information or to discuss a valuation or transaction issues in confidence, please contact us.
Held by Production
Held by Production
Oftentimes differences are a matter of perspective. Put another way – one person’s loss can be another person’s gain.  One of the thematic differences between producers and mineral owners is their perspective on “Held By Production.”  It elicits very different reactions depending on what side of the term one is on, and has a leverageable impact on value.   With rig counts dropping to around half of last year’s count, how much acreage will be available for re-leasing this year?  In this post, we decided to spend some time exploring this concept and its impact on the energy industry.What Is Held By Production?Held By Production (“HBP”) is a mineral lease provision that extends the right to operate a lease as long as the property produces a minimum quantity of oil and gas.  The definition of HBP varies contractually by every lease it governs which is often misunderstood.  We have had discussions with several people, including peers (as well as knowledgeable industry participants) who did not have a clear grasp of HBP and its exact meaning.  Some people thought HBP was governed by state law, regulatory agencies, or even accounting rules.  However, the truth is that the facts and circumstances that shape a lease as it pertains to HBP, are all negotiable.  Therefore, by extension, the outcome of lease negotiations can have a spectrum of results: from being deemed balanced, to favoring the lessor (i.e., the mineral owner) or the lessee (i.e., the producer). A large percentage of public company leases are HBP.  In prior management calls, management teams have noted that the Permian Basin was about 95% HBP due to decades of prior drilling.  Why might someone be more attracted to an operator’s stock that has a large percentage of leases HBP? Investopedia puts it this way:The “held by production” provision enables energy companies to avoid renegotiating leases upon the expiry of the initial term. This results in considerable savings to them, particularly in geographical areas that have become “hot” due to prolific output from oil and gas wells.  With property prices in such areas generally on an upward trend, leaseholders would demand significantly higher prices to renegotiate leases.What Does the Term "Held By Production” Mean to Mineral Owners (Lessors)?Mineral owners should have an understanding of how their lease terms impact drilling activity (and by extension – royalty payments) on their properties.  Lessors are challenging operators’ decisions not to drill on their land, even if prospects appear to be good. As a result, mineral owners are more interested in how certain clauses and term structures function in their leases.Therefore, it is important for mineral owners to understand two lynchpin concepts as they pertain to defining HBP: the Pugh Clause and the Implied Covenant to Develop.Pugh ClauseThe Pugh Clause is named after Lawrence Pugh, a Crowley, Louisiana attorney who developed the clause in 1947, apparently in response to the Hunter v. Shell Oil Co., 211 La. 893 (1947). In this case, the Louisiana Supreme Court held that production from a unit, including a portion of a leased tract, will maintain the lease in force as to all lands covered by the lease even if they are not contiguous. This clause is most often cited today in pooling for horizontal wells.  There have been situations (depending on the clause’s language) whereby one well might maintain a large area (thousands of acres) defined as HBP.  This is to an operator’s advantage and a mineral holder’s chagrin. However, this can be negotiated in the mineral holder’s favor – particularly in active markets and basins. For example, a few years ago Mercer Capital had a client that had a large tract of land in the Eagle Ford Shale and was being courted by many eager operators.  Ultimately, they negotiated a lease with an operator who contractually obligated the company to drill three wells per year on the property for the duration of the lease.  Not too long after the lease was negotiated, the price of oil dropped in half and the operator was much less enthusiastic about having to drill three wells per year. There are several nuances and factors to Pugh clauses (and similar lease clauses) that we won’t explore here, but suffice to say, it is a critical factor to defining a property as HBP or not.Implied Covenant to DevelopAnother aspect of lease law is centered around the concept called “Implied Covenant to Develop.”  Sometimes a lessors’ alternative is to attempt to find remedy through the implied obligation that the lessee failed to develop and operate the property as a reasonably prudent operator.  Forcing an implied obligation generally occurs through a lawsuit and is difficult to prove.  However, implied covenants have been addressed by courts from all producing states as well as the Supreme Court of the United States.There are several potential examples.  One example is discussed in this Gas & Oil Law blog.Consider an oil and gas lease taken on 200 acres.  Let’s say that thirty years ago one well was drilled on the 200-acre lease and that this well unit only included 40 acres.   Under the implied covenant to reasonably develop, a judge may very well cancel the lease to the remaining, unused 160 acres (200 acres – 40 acres = 160 acres).  How could a judge do that?  The basic question that needs to be answered is whether or not the oil and gas producer has behaved as a reasonable oil and gas producer would in similar circumstances.  If any reasonable producer would have drilled more than one well on the 200-acre lease, then a reviewing judge might void the lease to the remaining 160 acres.  However, if the existing well was not a very good well, then it might be that the producer did behave reasonably when they decided not to drill additional wells.ConclusionDepending on which side of the negotiation one is on, HBP can be a favorable (or unfavorable) contributor to value. As such, it is crucial to have an analyst who possesses knowledge from all sides of industry negotiations.Mercer Capital has over 20 years of experience valuing assets and companies in the oil and gas industry. We have valued companies and minority interests in companies servicing the E&P industry and assisted clients with various valuation and cash flow issues regarding royalty interests.  Contact one of our oil and gas professionals today to discuss your needs in confidence.
What Is a Fairness Opinion And What Triggers the Need for One?
What Is a Fairness Opinion And What Triggers the Need for One?
Based on available public data from S&P Global’s Market Intelligence platform, there were 25 merger and acquisition announcements in 2020 related to oil and gas companies at the entity level (including natural gas midstream and utility companies).  These 25 announcements represented at least $16.2 billion in total deal value, notwithstanding three deals where the value was not publicly disclosed.  On a quarterly basis, there were eight announcements in Q1 2020, eight in Q2 and Q3 combined, and nine in Q4.While the trend in the quarterly announcements is not very surprising, one phrase, in particular, creeps up with increasing frequency when reviewing transaction details as 2020 progressed: “Fairness Opinion.”In Q1, only one of the eight transactions was reported to have had a Fairness Opinion conducted.  None of the two transactions announced in Q2 had Fairness Opinions, but two of the six announced deals in Q3 did.  As the Oil and Gas industry began to get somewhat comfortable again, Q4 finished out strong with nine announced deals. However, nearly half of them were accompanied by Fairness Opinions.  We examine this trend from a monthly perspective in the following chart: Irrespective of what industry or sector a company may operate in, a fundamental question arises as mergers and acquisitions persist and company boards and management teams survey their options when a proposed transaction is put on the table: is it fair to all direct stakeholders? What Is a Fairness Opinion?A Fairness Opinion involves a comprehensive review of a transaction from a financial point of view and is typically provided by an independent financial advisor to the board of directors of the buyer or seller.  The financial advisor must look at pricing, terms, and consideration received in the context of the market for similar companies.  The advisor then opines that the transaction is fair, from a financial point of view and from the perspective of the seller’s minority shareholders.  In cases where the transaction is considered to be material for the acquiring company, a second Fairness Opinion from a separate financial advisor on behalf of the buyer may be pursued.  On this point, we note that among the six deals announced in 2020 where a Fairness Opinion was conducted, only one of the six had Fairness Opinions conducted on behalf of both the buyer and the seller; the opinions performed for the other five deals were solely on behalf of the sellers in those transactions.Why Is a Fairness Opinion Important?Why is a Fairness Opinion important?  There are no specific guidelines as to when to obtain a Fairness Opinion, yet it is important to recognize that the board of directors is endeavoring to demonstrate that it is acting in the best interest of all the shareholders by seeking outside assurance that its actions are prudent.One answer to this question is that good intention(s) without proper diligence may still give rise to potential liability.  In its ruling in the landmark case Smith v. Van Gorkom, (Trans Union), (488 A. 2d Del. 1985), the Delaware Supreme Court effectively made the issuance of Fairness Opinions de rigueur in M&A and other significant corporate transactions.  The backstory to this case is the Trans Union board approved an LBO that was engineered by the CEO without hiring a financial advisor to vet a transaction that was presented to them without any supporting materials.  Regardless of any specific factors that may have led the Trans Union board to approve the transaction without extensive review, the Delaware Supreme Court found that the board was grossly negligent in approving the offer despite acting in good faith.  Good intentions, but lack of proper diligence.The facts and circumstances of any particular transaction can lead reasonable (or unreasonable) parties to conclude that a number of perhaps preferable alternatives are present.  A Fairness Opinion from a qualified financial advisor can minimize the risks of disagreement among shareholders and misunderstandings about a deal.  They can also serve to limit the possibilities of litigation which could kill the deal.  Perhaps just as important as being qualified, a Fairness Opinion may be further fortified if conducted by a financial advisor who is independent of the transaction.  In other words, a financial advisor hired solely to evaluate the transaction, as opposed to the banker who is paid a success fee in addition to receiving a fee for issuing a Fairness Opinion.When Should You Obtain a Fairness Opinion?While the following is not a complete list, consideration should be given to obtaining a Fairness Opinion if one or more of these situations are present:Competing bids have been received that are different in price or structure, leading to potential disagreements in the adequacy and/or interpretation of the terms being offered, and which offer may be “best”; Conversely, when there is only one bid for the company, and competing bids have not been solicited.The offer is hostile or unsolicited.Insiders or other affiliated parties are involved in the transaction, giving rise to potential or perceived conflicts of interest.There is concern that the shareholders fully understand that considerable efforts were expended to assure fairness to all parties.What Does a Fairness Opinion Cover?A Fairness Opinion involves a review of a transaction from a financial point of view that considers value (as a range concept) and the process the board followed in reaching a decision to consummate a transaction.  The financial advisor must look at pricing, terms, and consideration received in the context of the market.  The advisor then opines that the consideration to be received (sell-side) or paid (buy-side) is fair from a financial point of view of shareholders, especially minority shareholders in particular, provided the advisor’s analysis leads to such a conclusion.While the Fairness Opinion itself may be conveyed in a short document, most typically as a simple letter, the supporting work behind the Fairness Opinion letter is substantial.  This analysis may be provided and presented in a separate fairness memorandum or equivalent document.A well-developed Fairness Opinion will be based upon the following considerations that are expounded upon in the accompanying opinion memorandum:A review of the proposed transaction, including terms and price and the process the board followed to reach an agreement.The subject company’s capital table/structure.Financial performance and factors impacting earnings.Management’s current year budget and multi-year forecast.Valuation analysis that considers multiple methods that provide the basis to develop a range of value to compare with the proposed transaction price.The investment characteristics of the shares to be received (or issued), including the pro-forma impact on the buyer’s capital structure, regulatory capital ratios, earnings capacity, and the accretion/dilution to earnings per share, tangible book value per share, dividends per share, or other pertinent value metrics.Address the source of funds for the buyer.What Is Not Covered in a Fairness Opinion?It is important to note what a Fairness Opinion does not prescribe, including:The highest obtainable price.The advisability of the action the board is taking versus an alternative.Where a company’s shares may trade in the future.How shareholders should vote a prox.yThe reasonableness of compensation that may be paid to executives as a result of the transaction. Due diligence work is crucial to the development of the Fairness Opinion because there is no bright-line test that consideration to be received or paid is fair or not.  The financial advisor must take steps to develop an opinion of the value of the selling company and the investment prospects of the buyer (when selling stock).ConclusionThe Professionals at Mercer Capital may not be able to predict the future, but we have nearly four decades of experience in helping boards assess transactions as qualified and independent financial advisors.  Sometimes paths and fairness from a financial point of view seem clear; other times they do not.Please give us a call if we can assist your company in evaluating a transaction.
Mineral And Royalty Valuations Remain Low Amid Recent Oil Price Gains
Mineral And Royalty Valuations Remain Low Amid Recent Oil Price Gains
The recent rise of oil prices returning to over $50 per barrel is a welcome sign to mineral and royalty holders across the board. There are inklings of bullish expectations for oil and gas prices in the coming year. However, climbing back up the valuation cliff that these assets fell from in March 2020 is still daunting. There are a lot of factors keeping this asset class from rebounding such as rig counts, capex budgets and supply chain issues. It has slowed royalty acquisitions and divestitures to a crawl and pushed undeveloped acreage values in many areas to multi-year lows.On the other hand, these same factors have led to a rush of estate planning transaction activity. The combination of depressed E&P valuations, the potential for future tax changes and the ability for mineral and royalty holding entities to utilize minority interest and marketability discounts have kept many tax advisors busy in recent months. These low valuations may not last for much longer if some recent bullish sentiment comes to fruition though. In the meantime, let us expound a bit on these forces keeping mineral and royalty valuations in their existing state.Low Upstream ValuationsThere is no need to explain how 2020 was a tough year, though the pain was dire for many upstream companies. Recovery appears to be gaining ground, but the momentum is tentative and some changes in travel habits might become permanent. While E&P company values (as proxied by the SPDR S&P Oil & Gas Exploration & Production ETF $XOP) have recovered from their lows in March, the index remains down year-over-year, having declined 38% during 2020.[caption id="attachment_35814" align="alignnone" width="668"] SPDR S&P Oil & Gas Exploration & Production ETF (XOP) | Source: CAPITAL IQ[/caption] The recent flurry of E&P bankruptcies also is indicative of a challenging operating environment and reduced equity valuations. There are exceptions with assets and situations of highly economic Tier 1 production, and/or acreage that can maintain or have proportionally small value decreases during this downturn, but most E&P companies have suffered alongside commodity prices. One of the significant outcomes from this is that rig counts remain less than half what they were pre-pandemic. This lack of activity is contributing to current oil inventory issues and price gains but is also keeping raw and undeveloped acreage valuations particularly depressed due to the slowdown in prospective development timelines. Potential For Future Tax ChangesPresident Biden’s tax plan calls for some major changes to the current gift & estate tax regime. Most notably, the estate tax exemption could be reduced from today’s $11.7 million (unified) to $3.5 million (estate) and $1.0 million (gift), and the tax rate could increase from 40% to 45%. The prospects for tax reform likely increased after Georgia’s Senate run-off elections on January 5th which put the Democrats in control of both houses of Congress.While new tax legislation could potentially be made retroactive to January 1, many tax policy experts see that as unlikely.Acreage Values Remain DepressedThese dynamics are keeping values low. Cash flow values are coming back, but not much else. Few are paying for undrilled acreage unless it is extremely high quality. Freehold’s recent $58 million royalty package acquisition demonstrates this. The deal announced in early January included 400,000 gross acres of mineral title and overriding royalty interests across 12 basins and eight states. It traded for about 58x months of prospective cash flow, but the incremental acreage value was minimal (if anything).[caption id="attachment_35815" align="alignnone" width="700"] Royalty/Mineral Transaction Activity | Sources: Energy Net, EIA, and Hart Energy[/caption] This characteristic is also apparent in mineral aggregators’ stock prices, which remain significantly lower even though oil and gas prices are in a similar spot as a year ago. [caption id="attachment_35816" align="alignnone" width="700"] Mineral Aggregator Stock Performance: 2020-2021 | Source: Capital IQ[/caption] Until The Drill Bit Turns…Many things remain uncertain, but for investors in mineral and royalty assets, prices above $50 per barrel again is a start. The more restrictive regulatory environment will likely also buoy prices. However, until production ramps up and future drilling inventory comes into focus, expect that mineral and royalty values will still have a steep cliff to climb.Originally appeared on Forbes.com on January 29, 2021.
Optional Insights on Valuing PUDs and Unproven Reserves
Optional Insights on Valuing PUDs and Unproven Reserves
One of the primary challenges for industry participants when valuing and pricing oil and gas reserves is addressing proven undeveloped reserves (PUDs) and unproven reserves, particularly in today’s volatile price environment.  The onslaught of COVID-19 and the Russian-Saudi price war caused significant operational implications with arguably all E&P companies.  Companies’ forecasts were no longer reasonable.  Drilling stopped and the market took a dive.  The implication of these events had impacts on the valuations of PUDs and unproven reserves valuations.  While the market approach can sometimes be used to understand the value of PUDs and unproven reserves, every transaction is unique.  Why then, and under what circumstances, might the PUDs and unproven reserves have significant value?Public transactions do not disclose the value associated with PUDs and unproven reserves, but instead, they indicate an aggregate value for a bundle of assets.  The allocation of that value across the various assets acquired is up for debate.  Recent transaction sheds some light on asset pricing in the current environment.Optionality ValueThe answer lies within the optionality of a property’s future DCF values.  In particular, if the acquirer has a long time to drill, one of two forces come into play: either the PUDs potential for development can be altered by fluctuations in the current price outlook for a resource, or as seen with the rise of hydraulic fracturing, drilling technology can drive significant increases in the DCF value of the unproven reserves.This optionality premium or valuation increment is often most pronounced in unconventional resource play reserves, such as coal bed methane gas, heavy oil, or foreign reserves.  This is especially apparent when the PUDs and unproven reserves are reliant on future production.  These types of reserves do not require investment within a fixed short timeframe.PUDs are typically valued using the same discounted cash flow (DCF) model as proven producing reserves after adding in an estimate for the capital costs (capital expenditures) to drill.  Then the pricing level is adjusted for the incremental risk and the uncertainty of drilling “success,” i.e., commercial volumes, life, risk of excessive water volumes, etc.  This incremental risk could be accounted for with either a higher discount rate in the DCF or a reserve adjustment factor (RAF).  Historically, in lower oil price environments like we face today, a raw DCF would suggest little to no value for PUDs or unproven reserves in several plays and basins.In practice, undeveloped acreage ownership functions as an option for reserve owners; they can hold the asset and wait until the market improves to start production.  Therefore, an option pricing model can be a realistic way to guide a prospective acquirer or valuation expert to the appropriate segment of market pricing for undeveloped acreage.Adaptation of Black Scholes Option ModelThe PUD and unproved valuation model is typically seen as an adaptation of the Black Scholes option model.  The Black Scholes option model is widely used to develop the value of European-style options. The adaptation is most accurate and useful when the owners of the PUDs have the opportunity, but not the requirement, to drill the PUD and unproven wells and the time periods are long, (i.e., five to ten years).  The value of the PUDs thus includes both a DCF value, if applicable, plus the optionality of the upside, driven by potentially higher future commodity prices and other factors.  The comparative inputs, viewed as a real option, are shown in the table below. When these inputs are used in an option pricing model, the resulting value of the PUDs reflects the unpredictable nature of the oil and gas market.  This application of option modeling becomes most relevant near the lower end of historic cycles for a commodity.  In a high oil price environment, adding this consideration to a DCF will have little impact as development is scheduled for the near future and the chances for future fluctuations have little impact on the timing of cash flows.  At low points, on the other hand, PUDs and unproved reserves may not generate positive returns and thus will not be exploited immediately. If the right to drill is postponed for an extended period, (i.e., five to ten years), those reserves still have value based on the likelihood they will become positive investments when the market shifts at some point.  In the language of options, the time value of the out-of-the-money drilling opportunities can have significant worth.  This worth is not strictly theoretical, either, or only applicable to reorganization negotiations.  Market transactions with little or no proven producing reserves have demonstrated significant value attributable to non-producing reserves, demonstrating the recognition by the pool of buyers of this optionality upside. ConclusionWe caution, however, that there can be limitations in the model’s effectiveness, as we describe in Bridging Valuation Gaps Part 3. Specific and careful applications of assumptions are needed, and even then, Black Sholes’ inputs do not always capture some of the inherent risks that must be considered in proper valuation efforts.  Nevertheless, option pricing can be a valuable tool if wielded with knowledge, skill, and good information, providing an additional lens to peer into a sometimes-murky marketplace. Today’s marketplace is particularly uncertain, and a quality appraisal is extremely valuable since establishing reasonable and supportable evidence for PUD, probable, and possible reserve values may assist in a reorganization process that determines the survival of a company, the return profile for a potential investment, or simply standing up to third-party scrutiny. Given these conditions, we feel that the benefits of using option pricing far outweigh its challenges.
2021 Is Still an Optimal Time for Gifting Interests in E&P Companies
2021 Is Still an Optimal Time for Gifting Interests in E&P Companies

Factors That Led to a Rush of Estate Planning Activity in 2020 Largely Remain

December was a busy month at Mercer Capital, and at business valuation firms across the country.  Clients sought to make gifts and perform other estate planning transactions ahead of year-end.  But the changing of the calendar does not mean that the window for gifting is over.  The factors that led to a rush of estate planning transaction activity during 2020 largely remain.  The combination of depressed E&P valuations, the potential for future tax changes, and the ability to utilize minority interest and marketability discounts are still present in 2021.Depressed E&P Valuations2020 was a difficult year for many companies, though the pain was acute for E&P companies that were faced with unprecedented demand destruction that led to negative oil prices.  Recovery appears to be taking hold, but the pace is uncertain and some changes in commuting and business travel habits might be permanent.While E&P company values (as proxied by the SPDR S&P Oil & Gas Exploration & Production ETF) have recovered from their lows in March, the index remains down year-over-year, having declined 38% during 2020.[caption id="attachment_35371" align="aligncenter" width="645"]Source: Capital IQ[/caption] The recent spate of E&P bankruptcies also is indicative of a challenging operating environment and reduced equity valuations.  There are exceptions with assets and situations of highly economic Tier 1 production, and/or acreage that can maintain or have proportionally small value decreases during this downturn, but most E&P companies have suffered alongside commodity prices. While unpleasant from a net worth perspective, this (hopefully temporary) reduction in value can be a boon for estate planning purposes, allowing taxpayers to gift larger interests, while utilizing less of their gift & estate tax exemption (or paying less in taxes on the gifted interest). Potential for Future Tax ChangesPresident-elect Biden’s tax plan calls for some major changes to the current gift & estate tax regime.  Most notably, the estate tax exemption could be reduced from today’s $11.7 million (unified) to $3.5 million (estate) and $1.0 million (gift), and the tax rate could increase from 40% to 45%.  The prospects for tax reform likely increased after Georgia’s Senate run-off elections on January 5th put the Democrats in control of both houses of Congress.While new tax legislation could potentially be made retroactive to January 1, many tax policy experts see that as unlikely.  Mercer Capital’s Atticus Frank has a great blog post with additional reading for anyone interested in estate planning for 2021.Consider taking advantage of the current gift & estate tax exemptions in 2021 before they potentially go away.Minority Interest and Marketability DiscountsBy gifting minority interests to heirs, taxpayers can potentially utilize minority interest and marketability discounts to reduce the value of the gifted interest and ease gift & estate tax burdens.  These discounts are highly dependent on facts and circumstances surrounding the subject interest.  Mercer Capital has successfully defended its minority interest and marketability discounts to the IRS and in other litigated contexts.By gifting minority interests, one does not only benefit from the application of minority interest and marketability discounts during the gifting process.  If done as a part of a thoughtfully executed estate planning strategy, gifting can result in a non-controlling ownership interest in an estate, allowing for the potential application of discounts for estate tax purposes as well.Mercer Capital’s Travis Harms has an insightful blog post about this issue.  In the post, he runs hypothetical math showing the difference in potential tax liabilities under various gifting scenarios.  A thoughtful gifting strategy as part of a broader estate plan can have a significant impact on the proceeds heirs receive from an estate.ConclusionDespite what one might think, the window for gifting transactions has not closed.  Mercer Capital provides valuation and other financial advisory services to families seeking to optimize their estate plans.  Give one of our professionals a call to discuss how we can help you in the current environment.
The “Best” of 2020
The “Best” of 2020

<em>Energy Valuation Insights’</em> Top Blog Posts

As we hope for a better 2021, we look back at 2020 to see what was popular with you ­– our readers.  Below is a list of some of our top posts of 2020.Energy Valuations: Freefall Into Bankruptcy Or Is This Time Different?2020’s challenges were apparent early in the year.  In this post, Bryce Erickson discusses whether the headwinds are a temporary blip, or whether these issues portend a wave of bankruptcies for the industry.Saudi Arabia, Russia, or the United States – Did One of the Players Blink?This post from April discusses some of the initial fallout from the Saudi / Russian price war, and came just days before the historic decline of WTI into negative territory.Royalties and Minerals: A New Market Is Emerging2020 delivered some jarring blows to players in the mineral and royalty space. Although this asset class enjoys certain benefits relative to oil and gas producers, its value is still connected to commodity prices. The recent swing downward has staggered market participants and quickly changed several assumptions regarding a sense of normalcy. In this post, Bryce Erickson discusses the sector with Chris Atherton, the CEO of EnergyNet, which is one of the largest private mineral transaction platforms in the market.Impairment Testing of Oil & Gas ReservesThe oil & gas market and the energy sector as a whole took a beating during 2020 and experienced unprecedented events due to the global impacts from the pandemic and international price wars. Companies are having to question and consider the need for interim impairment testing on reserves. This post will help oil & gas companies discern whether they may need to make interim impairment assessments and to understand the impairment testing process.Oil Frackers Are Breaking Records Again – In Bankruptcy CourtIn an unfortunate answer to the first post featured above, it was not different.  In this post, Bryce Erickson discusses the volume of E&P bankruptcies observed during 2020.Conclusion2020 was a challenging year in the energy space that most are eager to leave behind.  We look forward to 2021 and appreciate your interest in this blog. May you and your family enjoy a happy and prosperous year!
EP First Quarter 2021 Eagle Ford
E&P First Quarter 2021

Eagle Ford

Eagle Ford // The first quarter of 2021 saw generally increasing commodity prices, a welcome change from the volatile price environment seen during 2020.
What Is a Reserve Report?
What Is a Reserve Report?
A reserve report is a fascinating disclosure of information. This is, in part, because the disclosures reveal the strategies and financial confidence an E&P company believes about itself in the near future. Strategies include capital budgeting decisions, future investment decisions, and cash flow expectations.For investors, these disclosures assist in comparing projects across different reserve plays and perhaps where the economics are better for returns on investment than others.However, not all the information in a reserve report is forward-looking, nor is it representative of Fair Value or Fair Market Value. For a public company, disclosures are made under a certain set of reporting parameters to promote comparability across different reserve reports. Disclosures do not take into account certain important future expectations that many investors would consider to estimate Fair Value or Fair Market Value.What Is a Reserve Report?Simply put, a reserve report is a report of remaining quantities of minerals which can be recoverable over a period of time. The current rules define these remaining quantities of mineral as reserves. The calculation of reserves can be very subjective, therefore the SEC has provided, among these rules, the following definitions, rules, and guidance for estimating oil and gas reserves:Reserves are “the estimated remaining quantities of oil and gas and related substances anticipated to be economically producible;The estimate is “as of a given date”; andThe reserve “is formed by application of development projects to known accumulations”. In other words, production must exist in or around the current project.“In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production of oil and gas”There also must be “installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.”Therefore, a reserve report details the information and assumptions used to calculate a company’s cash flow from specific projects which extract minerals from the ground and deliver to the market in a legal manner. In short, for an E&P company, a reserve report is a project-specific forecast. If the project is large enough, it can, for all intents and purposes, become a company forecast.What Is the Purpose of a Reserve Report?Many companies create forecasts. Forecasts create an internal vision, a plan for the near future and a goal for employees to strive to obtain. Internal reserve reports are no different from forecasts in most respects, except they are focused on specific projects.Externally, reserve reports are primarily done to satisfy disclosure requirements related to financial transactions. These would include capital financing, due diligence requirements, public disclosure requirements, etc.Publicly traded companies generally hire an independent petroleum engineering firm to update their reserve reports each year and are generally included as part of an annual report. Like an audit report for GAAP financial statements, independent petroleum engineers provide certification reserve reports.Investors can learn much about the outlook for the future production and development plans based upon the details contained in reserve reports. Remember, these reserve reports are project-specific forecasts. Forecasts are used to plan and encourage a company goal.How Are Reserve Reports Prepared?Reserve reports can be prepared many different ways. However, for the reports to be deemed certified, they must be prepared in a certain manner. Similar to generally accepted accounting principles (GAAP) for financial statements, the SEC has prepared reporting guidance for reserve reports with the intended purpose of providing “investors with a more meaningful and comprehensive understanding of oil and gas reserves, which should help investors evaluate the relative value of oil and gas companies." Therefore, the purpose of SEC reporting guidelines is to assist with project comparability between oil and gas companies.What Is in a Reserve Report?Reserve reports contain the predictable and reasonably estimable revenue, expense, and capital investment factors that impact cash flow for a given project. This includes the following:Current well production: Wells currently producing reserves.Future well production: Wells that will be drilled and have a high degree of certainty that they will be producing within five years.Working interest assumption: The ownership percentage the Company has within each well and project.Royalty interest assumptions: The royalty interest paid to the land owner to produce on their property.Five-year production plan: All the wells the Company plans to drill and have the financial capacity to drill in the next five years.Production decline rates: The rate of decline in producing minerals as time passes. Minerals are a depleting asset when producing them and over time the production rate declines without reinvestment to stimulate more production. This is also known as a decline curve.Mineral price deck: The price at which the minerals are assumed to be sold in the market place. SEC rules state companies should use the average of the first day of the month price for the previous 12 months. Essentially, reserve reports use historical prices to project future revenue.Production taxes: Some states charge taxes for the production of minerals. The rates vary based on the state and county, as well as the type of mineral produced.Operating expenses for the wells: This includes all expenses anticipated to operate the project. This does not include corporate overhead expenses. Generally, these are asset-specific operating expenses.Capital expenditures: Cash that will be needed to fund new wells, stimulate or repair existing wells, infrastructure builds to move minerals to market and cost of plugging and abandoning wells that are not economical.Pre-tax cash flow: After calculating the projected revenues and subtracting the projected expenses and capital expenditures, the result is a pre-tax cash flow, by year, for the project.Present value factor: The annual pre-tax cash flows are then adjusted to present dollars through a present value calculation. The discount rate used in the calculation is 10%. This discount rate is an SEC rule, commonly known as PV 10. The overall assumption in preparing a reserve report is that the company has the financial ability to execute the plan presented in the reserve report. They have the approval of company executives, they have secured the talent and capabilities to operate the project, and have the financial capacity to complete it. Without the existence of these expectations, a reserve report could not be certified by an independent reserve engineer.A Plug for Mercer CapitalMercer Capital has significant experience valuing assets and companies in the energy industry. Because drilling economics vary by region it is imperative that your valuation specialist understands the local economics faced by your E&P company.  Our oil and gas valuations have been reviewed and relied on by buyers and sellers and Big 4 Auditors. These oil and gas related valuations have been utilized to support valuations for IRS Estate and Gift Tax, GAAP accounting, and litigation purposes. We have performed oil and gas valuations and associated oil and gas reserves domestically throughout the United States and in foreign countries. Contact a Mercer Capital professional today to discuss your valuation needs in confidence.
How to Use an EV/Production Multiple
How to Use an EV/Production Multiple
Oil and gas analysts use many different metrics to explain and compare the value of an oil and gas company, specifically an exploration and production (E&P) company. The most popular metrics (at least according to our eyeballs) include (1) EV/Production; (2) EV/Reserves; (3) EV/Acreage; and (4) EV/EBITDA(X). Enterprise Value (EV) may also be termed Market Value of Invested Capital (MVIC) and is calculated by the market capitalization of a public company plus debt on the balance sheet less cash on the balance sheet. In this post, we will dive into one of these four metrics, the EV/Production metric, and explore the most popular uses of it.DefinitionEV/Production is a commonly used valuation multiple in the oil and gas industry which measures the value of a company as a function of the total number of barrels of oil equivalent, or mcf equivalent, produced per day. When using this multiple, it is important to remember that it does not explicitly account for future production or undeveloped fields.Common UsesWhile the above definition was provided by Investopedia, the source goes on to explain the meaning of the multiple in the following way:All oil and gas companies report production in BOE. If the multiple is high compared to the firm's peers, it is trading at a premium, and if the multiple is low amongst its peers it is trading at a discount. However, as good as this metric is, it does not take into account the potential production from undeveloped fields. Investors should also determine the cost of developing new fields to get a better idea of an oil company's financial health.While some of the above explanation may appear true; the detail, analysis, and reason is lacking. Let’s more fully investigate the above notes:BOE or MCFE. Not all oil and gas companies report in barrel of oil equivalent per day (BOEPD). Those that are primarily dry gas producers will choose to report in MCF equivalent per day (MCFEPD). On the other hand, majority oil producers will report in BOEPD. One take away analysis to consider is that many times the metric a company uses to report production communicates the core production activity of the company (i.e. a company that reports in BOE wants to communicate they primarily target oil, while a company that reports in MCFE wants to communicate they primarily target gas).Premium or Discount. If the multiple is higher compared to its peers, it only appears to trade at a premium, but it does not mean the market value of the company is at a premium or more expensive than its peers. If it trades at a discount to its peers, the same is also true; it does not automatically mean the MVIC of a company is cheaper than its peers. To draw that conclusion, one assumes each of its peers has the exact same future production outlook, the exact same well locations and the exact same management team, just to name a few. Making this assumption in isolation is in error. Instead, analysis should be performed to understand the why behind a perceived “premium” or “discount.”Current or Future Production. The metric uses current production as an indication of value for the company. When using this metric, it could be assumed that (1) the current oil/gas/natural gas liquids mix will stay the same; (2) the current production level will continue on its previously experienced decline rate; and (3) the equivalency formula to translate gas production into oil production (typically 6.1 mcf = 1 barrel of oil equivalent) will not change. This metric fails to account for visibility into future production. When analyzing an E&P company, future production should always be considered.ExperienceWhile this multiple is useful, it also has its shortfalls. As with all multiples, it should never be used as the sole indicator of value. As an example, using this multiple in isolation would give zero value for an E&P flush with acreage and no production.We had a client with investments in an oil and gas company that was facing a transfer of ownership decision. During negotiations certain parties involved were convinced the only way to value, and therefore the only way they would pay for, an E&P was to utilize an EV/Production multiple and nothing else. They backed their position with their transaction experience of buying oil and gas assets as well as their knowledge of industry participants. We believed utilizing that particular method significantly undervalued our client. While the company had very little production, the acreage rights were significant as well as the PV 10 reserve report. We assisted our client through the transaction process by utilizing multiple valuation approaches, not solely the one a potential suitor strongly suggested.Multiples such as EV/Production can provide context for market pricing in the form of a range. We would never recommend using one market multiple as the only value indication for a subject company, particularly a non-publicly traded company. Ideally, market multiples should be used as one of many value indicators during analysis. While there may be facts and circumstances that prohibit the use of multiple value indicators, it is always advisable to (1) understand the implications of using a specific multiple; (2) understand its weaknesses; and (3) use other value indications together. When observing the EV/Production multiple, reconcile the observations with other valuation multiples and valuation indications for a reasonable analysis. For assistance in the process or other valuation analysis for an energy company, contact a member of our oil and gas team to discuss your needs in confidence.
Themes from Q3 2020 Earnings Calls (1)
Themes from Q3 2020 Earnings Calls

Part 2: Mineral Aggregators

Last week, we reviewed the third quarter earnings calls from a select group of E&P companies and briefly discussed the macroeconomic factors affecting the oil and gas industry. In this post, we focus on the key takeaways from the mineral aggregator third quarter 2020 earnings calls.Theme 1: M&A Activity Is Heating UpThe mineral aggregator space seems to be following the same M&A pattern as E&P operators as of late. Relative to the first half of 2020, consolidation efforts are increasing as aggregators are focusing on potential acquisition opportunities. Industry participants, however, continue to notice a wide bid-ask spread as sellers are often unwilling to sell at current prices.“I would say that, in terms of overall deal flow, we're seeing a tremendous amount of deal flow. If anything, our deal teams are busier now than they ever have. What I would say is that the competition today isn't necessarily with other mineral companies, but in often instances, we refer to kind of reservation price and that's the seller's willingness to part with those minerals.” – Robert Roosa, Founder & CEO, Brigham Minerals“We've been active on the M&A front. We'll still look at acquisitions. We're still working around the clock on acquisitions or submitting bids. It's just more challenging. I mean I think that sellers in this environment need to adjust expectations when the public companies, they're supposed to be the lowest cost of capital trade down so dramatically, us and our peers, that should trickle down to the sellers.” – Davis Ravnaas, President, CFO & VP of Business Development, Kimbell Royalty Partners“There's billions of dollars of minerals held within private equity firms as well as family offices. But in places where they're not meant to be held over the long term. And I think you will see consolidation in the space. And I think there's an opportunity for value creation as a result of that.” – Daniel Herz, President & CEO, Falcon MineralsTheme 2: Curtailment Situation Affects Aggregators Differently Production curtailments continued in some basins, like the Bakken, in the third quarter, while other well curtailments were reversed and put back online in the Permian and Eagle Ford. Some aggregators had the benefit of being active in certain basins where the curtailments were lifted, and others were not so fortunate but remained optimistic that their wells would be back online by the end of the year.“We believe, as of the end of September, all of the curtailed wells are back online and are producing to our benefit, with the barrels of oil selling at substantially higher prices that existed during the curtailment period. Very good news for us all. While the third quarter had limited wells turned online, which is consistent with what we had expected and previously discussed, activity has begun to pick up.” – Daniel Herz, President & CEO, Falcon Minerals“Production curtailments, which were put in place by many operators during the height of the pandemic earlier this year, were largely reversed in the Permian and Eagle Ford during the quarter. However, curtailments were still largely in place on our Bakken assets during the third quarter. We are hopeful that these will reverse in Q4 of 2020 due to improved differentials in commodity prices.” – Bob Ravnaas, President, CFO & Chairman, Kimbell Royalty PartnersTheme 3: Natural Gas Continues to Spark InterestNatural gas has shown its ability to remain somewhat stable during a difficult price environment. The commodity’s price stability along with the favorable outlook has aggregators interested. The participants recognize natural gas as an important asset in their portfolio and express their optimism in gas prices moving into 2021.“There's already some optimism in natural gas with '21 forward prices over $3 in MMbtu. And the recent underinvestment in oil projects, both domestically and abroad, combined with the lessening influence of OPEC is setting the stage for an oil rally once demand recovers.” – Tom Carter, CEO & Chairman of the Board, Black Stone Minerals“In addition to our gas weighted daily production, we also have a significant amount of future drilling inventory located across the major natural gas basins in the U.S. with a concentration in the core areas of the Haynesville and Marcellus.” – Bob Ravnaas, President, CFO & Chairman, Kimbell Royalty Partners“As Bob laid out a few moments ago, natural gas price futures are projected to be up approximately 50% in the next 12 months as compared to the average prices over the last 12 months, which could generate a significant improvement in cash flow for the company.” – Davis Ravnaas, President, CFO & VP of Business Development, Kimbell Royalty Partners“And just when we thought gas was dead, of course, natural gas prices are above $3 and that's a great call option for us. And we have two rigs running across our acreage position. And we have a nice amount of gas.” – Daniel Herz, President & CEO, Falcon MineralsTheme 4: Banks and Balance SheetsBanks seem to be uneasy with E&P companies’ lending situations, which trickles down to the aggregator space. A continuing trend among E&P operators and mineral aggregators is the effort to shore up the balance sheet to create a healthier company and maintain positive bank relationships during the current uncertainty.“In addition, the balance sheets of many operators are strained and as we go through the fall borrowing base redetermination season. Bank and equity markets remain closed for most E&P companies. This plus a renewed focus on cash returns instead of simply production growth, has limited new drilling capital across Lower-48, which obviously impacts our production levels.” – Tom Carter, CEO & Chairman of the Board, Black Stone Minerals“I mean, you've seen obviously, the banks have had a tough time with energy companies through this down cycle. We want to be as low touch as possible with those banks.” – Kaes Van’t Hof, President, Viper Energy Partners“We're not interested in using cash in this environment just given the fact that we're really focused on cleaning up the balance sheet as much as we can and we don't want to do an equity raise at an unpalatable discount right now to raise the cash.” – Davis Ravnaas, President, CFO & VP of Business Development, Kimbell Royalty Partners
Themes from Q3 2020 Earnings Calls
Themes from Q3 2020 Earnings Calls

Part 1: E&P Operators

As discussed in our quarterly overview, the oil & gas sector experienced a relatively stable price environment as compared to the volatile energy prices seen in the first half of the year.  The third quarter saw the WTI range narrow and hover around $40 per barrel, in line with industry participant expectations of nominally higher prices than in the second quarter.However, the concurrent overlapping impact of (i) discord created by the OPEC/Russian rift and resulting supply surge; and (ii) the drop in demand due to COVID-19 related issues was historic and continued to play a role in the third quarter.  As if COVID-19 and the Russian-Saudi price rift wasn’t eventful enough, the regulatory shakeup expected to come from the Biden administration following the November election will add to the mix for what seems to be an already pressing and critical time for the industry.  The unfortunate, overlapping timing of these events has made the bankruptcy courts busy with no indication of that trend coming to a halt.In this post, we capture the key takeaways from E&P operator third quarter 2020 earnings calls.Theme 1: Continued Cost Reductions Lower Break-Even PricesOne recurring theme among E&P operators in our prior E&P operator earnings calls was the continued focus on reducing operating costs and capital expenditures in the pursuit of increased efficiencies. All six E&P operators we tracked in our current quarterly overview saw gains along these lines, evident by positive free cash flow in Q3 due to a decline in break-even prices.“Yes, we do see the break-even is roughly $32 next year. I don’t think that’s too dissimilar from where we were before we were indicating kind of in the mid-30s. But it depends on the capital program at any given time and where you’re putting those assets and the productivity.” – William Berry, CEO, Continental Resources, Inc.“Our pro forma maintenance capital corporate breakeven is at a very, very attractive low -- in the low 30s WTI, including the base dividend.” – Scott Sheffield, CEO, Pioneer Natural Resources Company“Impressive downside resilience as evidenced by our low-cost structure and enterprise free cash flow breakeven, approximately $35 per barrel WTI breakeven in 2021, including our dividend…” – Lee Tillman, President & CEO, Marathon Oil Company“Due to sustainable cost reductions achieved this year, maintenance capital and the current dividend can now be funded with oil in the mid-30s.” – Lloyd Helms, COO, EOG Resources, Inc.Theme 2: Continued Emphasis on Debt Reduction and Shareholder DividendsAnother recurring theme in our prior quarterly analysis was the focus by E&P operators on reducing debt and reinforcing dividends.  The panel of operators we tracked in this quarterly earnings call review was split almost evenly among those who were still focused on debt reduction and those who put the return of capital to shareholders as their top priority.“The cornerstone of our 2021 plan is maximizing free cash flow to pay down debt… While our dividend has been suspended, but not terminated, both our shareholders and our board are very supportive of bringing the dividend back at the appropriate time after our debt is reduced.” – William Berry, CEO, Continental Resources, Inc.“We are well aware that some of our larger peers are planning to return cash to shareholders. But as we have repeatedly stated, our plan is to apply our free cash flow, alongside our monetization proceeds, towards meaningful debt reduction, until we have significantly lowered our total debt balance.” – Jim Ulm, Chief Financial Officer, Callon Petroleum Company“[With respect to the prioritization of allocating free cash flow] the base dividend will be first. And then second, will be a combination of balance sheet and variable dividend.” – Scott Sheffield, CEO, Pioneer Natural Resources Company“Put very simply, our forward capital allocation philosophy has not changed. We will protect our dividend, spend maintenance capital at most and use excess free cash flow to pay down debt. If our expected free cash flow will not cover our dividend, then we will cut capital to ensure our dividend is protected.” – Travis Stice, CEO, Diamondback Energy, Inc.“[W]e are putting this free cash flow to good use. Advancing our dual objectives of returning capital to our shareholders through our base dividend reinstatement and improving our balance sheet through … gross debt reduction while cutting our 2022 maturity tower in half. Importantly, both the fourth quarter dividend reinstatement and gross debt reduction were fully funded by actual third quarter free cash flow.” – Lee Tillman, President & CEO, Marathon Oil Company“We remain committed to pursuing our objective to strengthen our balance sheet further during upturns. Beyond the regular dividend and debt reduction we regularly review performance scenarios that may present options for additional cash return to shareholders. We haven't ruled out buybacks or a variable or special dividend and we'll consider all options for additional return of cash to shareholders when the opportunity presents itself.” – Tim Driggers, CFO, EOG Resources, Inc.Theme 3: Uncertainty Lies AheadDespite the relative stability of oil and gas prices in the third quarter, E&P operators continue to project significant uncertainty for their industry.  The critical near-term factors affecting their forward outlook include regulatory changes for the oil and gas industry as put forth by the Biden administration, an upcoming meeting of OPEC+ producers in December, and the potential timeline of effective and available vaccines to curb the energy demand shock brought on by the  COVID-19 pandemic.“There's certainly some significant headwinds on the commodity space right now. I mean we've got the election uncertainty and looming policy changes… We've got COVID that we're still struggling how to contain that. And is there going to be a vaccine anytime soon, and what does that mean to the supply demand recovery? We've got OPEC+ meeting in December to talk about whether they maintain cuts or start easing those cuts, and then we've got a global inventory overhang that's still there.  All of those are macro issues that I can't control, and we can't influence.” – Travis Stice, CEO, Diamondback Energy, Inc.“There are still several unknowns that we will continue to evaluate during our budgeting process. The impact of the election, the timing of COVID-19 vaccine and in turn, the return and stabilization of oil demand, especially what OPEC decides to do in during the mid-November to December 1 OPEC meetings.” – Scott Sheffield, CEO, Pioneer Natural Resources CompanyOn the HorizonBroadly speaking, the E&P operator earnings calls suggest an uneasy calm. The question is, has the oil and gas industry emerged from the first major quake and should it expect relatively minor aftershocks, or is it in the eye of the storm, experiencing a brief respite before the tempest picks up again?  Overall, it is clear that oil and gas operators can not only weather the storm, but still produce free cash flow that is significant enough to shore up the balance sheet and return capital to shareholders while concurrently maintaining lean operational and capital programs.  This modus operandi, however, comes at the cost of highly subdued expectations for growth (with one noted exception among the six E&P operators we monitor).Throughout the earnings calls, we noted that management outlooks that included flat or even slight production declines over the near-term horizon were not considered to be “downside” scenarios, but evidence of, if nothing else, at least sustainable ongoing operations.  Additionally, we noted that at least half the E&P operators discussed continued efforts to support and advance various ESG initiatives, including proactively reducing emissions, and imparting stronger positive impacts on the local communities in which the companies operate.Regarding M&A activity, there was not much commentary regarding overall industry trends, but the overriding thesis was brought up in a number of calls that the focus of any such activity should be on “not necessarily bigger, but better.”
Mineral Aggregator Valuation Multiples Analysis (1)
Mineral Aggregator Valuation Multiples Analysis

Market Data as of November 10, 2020

Mercer Capital has its finger on the pulse of the minerals market.  An important trend has been the rise of mineral aggregators, which have largely supplanted the trusts as the primary method of publicly-traded minerals ownership.Due to a variety of corporate structures (including master limited partnerships and Up-Cs) and complex capital structures (including preferred equity and non-traded common units), mineral aggregator enterprise values pulled from databases are often missing meaningful components of value, leading to skewed valuation multiples.Mercer Capital has thoughtfully analyzed the corporate and capital structures of the publicly traded mineral aggregators to derive meaningful indications of enterprise value.  We have also calculated valuation multiples based on a variety of metrics, including distributions and reserves, as well as earnings and production on both a historical and forward-looking basis. Download our report below. Mineral Aggregator Valuation MultiplesDownload Analysis
Solvency Opinions Explained
Solvency Opinions Explained

What a Solvency Opinion Is and What It Addresses

What Is a Solvency Opinion?With the rise of corporate bankruptcies, a lot of leveraged transactions that occurred pre-COVID are going to be scrutinized. The musings here consider solvency opinions conceptually, but many bankruptcy courts, such as the one that oversaw the restructuring of Neiman Marcus, will consider the issue retroactively and may ask stockholders to return distributions that were deemed to have been obtained via fraudulent conveyance.The Business Judgement RuleThe Business Judgement Rule, an English case law doctrine followed in the U.S. and Canada, provides directors with great latitude in running the affairs of a corporation provided directors do not breach their fiduciary duties to act in good faith, loyalty, and due care. However, there are instances when state law prohibits certain actions including the fraudulent transfer of assets to stockholders that would leave a company insolvent.This straightforward statutory prescription has taken on more meaning over the past decade because corporate America has significantly increased its use of debt given very low interest rates. Investors have been willing to fund the increase because negligible rates on “safe” assets have pushed individuals and institutions out of the risk curve to produce income.Transactions that may meaningfully alter the capitalization of a company include leveraged dividend recapitalizations, leveraged buyouts, significant share repurchases, and special dividends funded with existing assets. Often a board contemplating such actions will be required to obtain a solvency opinion at the direction of its lenders or corporate counsel to provide evidence that the board exercised its duty of care to make an informed decision should the decision later be challenged.Four QuestionsA solvency opinion addresses four questions:Does the fair value of the company’s assets exceed its liabilities after giving effect to the proposed action?Will the company be able to pay its debts (or refinance them) as they mature?Will the company be left with inadequate capital?Does the fair value of the company’s assets exceed its liabilities and surplus to fund the transaction? A solvency opinion is typically performed by a financial advisor who is independent, meaning the advisor has not arranged financing or provided other services related to the contemplated transaction. The opinion is based upon financial analysis to address the valuation of the corporation and its cash flow potential to assess its debt service capacity. Also, the opinion is just that—it is an informed opinion. It is not a pseudo-statement of fact predicated upon the “known” future performance of the company.  It provides a reasonable perspective concerning the future performance of the company while neither promising to stakeholders that those projections will be met, nor obligating the company to meet those projections.Test 1: The Balance Sheet TestThe balance sheet test asks: Does the fair value and present fair saleable value of the company’s total assets exceed the company’s total liabilities, including all identified contingent liabilities? The balance sheet test is a valuation test in which the value of the company’s liabilities are subtracted not from the assets recorded on the balance sheet, but rather the fair market value of the company on a total invested capital basis. The value of the company on a debt-free basis is estimated via traditional valuation methodologies, including Discounted Cash Flow (“DCF”), Guideline Public Company, and Guideline Transactions (M&A) Methods. In some instances, the Net Asset Value (“NAV”) Method may be appropriate for certain types of holding companies in which assets can be marked-to-market.Test 2: The Cash Flow TestWill the company be able to pay its liabilities, including any identified contingent liabilities, as they become due or mature? This question addresses whether projected cash flows are sufficient for debt service. A more nuanced view evaluates the question along three general dimensions:Revolver Capacity: If financial results approximate the forecast, does the company have sufficient capacity, relying upon its revolving credit facility if necessary, to manage cash flow needs through each year?Covenant Violations: Does the projected financial performance imply that the company will violate covenants of the credit or loan agreement, or the terms of any other credit facility currently in place or under consideration as part of the subject transaction?Ability to Refinance: Is it likely that the company will be able to refinance any remaining balance at maturity?Test 3: The Capital Adequacy TestDoes the company have unreasonably small capital with which to operate the business in which it is engaged, as management has indicated such businesses are now conducted and as management has indicated such businesses are proposed to be conducted following the transaction? The capital adequacy test is related to the cash flow test. A company may be projected to service its debt as it comes due, but a proposed transaction may leave the margin to do so too thin – something many companies discovered this year in which they were able to operate with high leverage as long as business conditions were good. There is no bright line test for what “unreasonably small capital” means. We typically evaluate this concept based upon pro forma and projected leverage multiples (Debt/EBITDA and EBITDA/Interest Expense) relative to public market comps and rating agency benchmarks. While management’s projections represent a baseline scenario, alternative downside scenarios are constructed to asses the “unreasonably small capital” question in the same way downside scenario analyses are constructed to address the question of whether debts can be paid or refinanced when they come due.Test 4: The Capital Surplus TestThe capital surplus test asks: Does the fair value of the company’s assets exceed the sum of (a) its total liabilities (including identified contingent liabilities) and (b) its capital (as such capital is calculated pursuant to Section 154 of the Delaware General Corporation Law)? The capital surplus test replicates the valuation analysis prescribed under the balance sheet test, but also includes the company’s capital in the subtrahend (Hey! There is a word we haven’t seen since early primary school. The subtrahend is the value being subtracted.) Section 154 of the Delaware General Corporation Law defines statutory capital as (a) the par value of the stock; or in instances when there is no par value as (b) the entire consideration received for the issuance of the stock. "Capital" as defined here is nuanced. Often it may be a small amount if par is some nominal amount such as a penny a share, but that may not always be the case. What is excluded is retained earnings (or deficit) from the equity account.The Mosaic of SolvencyThe tests described above are straightforward. Sometimes proposed transactions are straightforward regarding solvency, but often it is less clear—especially when the subject company operates in a cyclical industry. Every solvency analysis is unique to the subject transaction and company under review and requires an objective perspective to address the solvency issue.Mercer Capital renders solvency opinions on behalf of private equity, independent committees, lenders and other stakeholders that are contemplating a transaction in which a significant amount of debt is assumed to fund shareholder dividends, an LBO, acquisition or other such transaction that materially levers the company’s capital structure. For more information or if we can assist you, please contact us.
What a Biden or Trump Presidency Might Mean for the Oil & Gas Industry
What a Biden or Trump Presidency Might Mean for the Oil & Gas Industry
With the presidential election less than a week away, we believe it is timely to identify the potential domestic and international implications of each candidates’ agendas as they relate to the oil and gas industry.  The election comes at a pressing time in the industry, with the next four years of U.S. oil and gas policy at stake.  Uncertainty continues to build as the election awaits and as two contrasting platforms face off.  As if COVID-19 and the Saudi-Russian price rift weren’t impactful enough to the industry, an election year adds to the eventful list.  In this post, we discuss each candidate’s political platform for the oil and gas industry.  The major topics and issues at stake include domestic production, infrastructure plans, OPEC+ engagements, and international sanctions.U.S. UpstreamPrior to the COVID-19 demand destruction, U.S. oil production increased 3.9 million b/d from Trump’s inauguration in January 2017.  President Trump’s production initiative aims to increase domestic output to pre-COVID levels, aligning with his historical policies to maximize U.S. energy production while constraining the supply of international players.  The industry has a general consensus on what the next four years may look like under a Trump administration.  The last four years have been filled with unrestricted oil production and relaxed crude export barriers.  The greatest domestic impact could come from Joe Biden’s initiative to oppose fracking on federal lands and waters.  Biden denied claims that he would ban fracking outright, instead stating that his platform would favor a ban on new fracking on federal lands and waters.  According to S&P Global Platts Analytics, eliminating the issuance of drilling permits for federal lands has the potential to shrink U.S. oil production by up to 2 million b/d by 2025, primarily from the Delaware Basin and the Gulf of Mexico.  During the final presidential debate, Joe Biden called for the U.S. to transition away from oil to address the environmental harm of climate change.  A Biden administration would look to re-enter the Paris Climate Agreement, which Trump pulled out of during his term, in order to prioritize the movement away from fossil fuel energy sources.  The push towards alternative energy sources could hinder domestic oil production compared to Trump’s vision for the industry, which supports fracking initiatives.Source: S&P GlobalInfrastructure During his term, President Trump signed executive orders, making efforts to ease permitting for pipelines, ports, and other energy infrastructure projects.  His actions were challenged by many state governments and projects continue to face legal obstacles.  If Joe Biden is elected, he would likely raise the bar for infrastructure project permits by considering climate impacts.  For example, it is possible that Biden may deny the 570,000 b/d Dakota Access Pipeline a new permit, a move initiated by the Obama administration, leaving Bakken producers without capacity to transport roughly 300,000 b/d to market.  U.S. crude exports that rely on certain pipelines will be affected by these future build-out decisions.  Infrastructure orders that are initiated by either candidate will face pushback as it is common for state and local authorities to get involved.OPEC+According to the Dallas Federal Energy Survey, 74% of industry executives believe that OPEC will play a bigger role in the determination of the price of oil going forward.  This year has further illustrated the impact OPEC+ participants can have on the global oil and gas market, shown by the Saudi-Russian price rift.  During his term, President Trump urged OPEC+ to increase or cut supply on a number of occasions.  Most would agree that President Trump has been more engaged with OPEC+ than most of his predecessors.  Trump’s international sanctions, which we will touch on below, have weakened the influence of OPEC’s Venezuela and Iran, which in turn concentrated power with Saudi Arabia and Russia.  A Biden administration may not be as aggressive with OPEC+ compared to President Trump.  Although Biden has not detailed his approach to the OPEC+ players, some assume he will attempt to rely on quiet diplomatic channels behind the scenes.International SanctionsIn November 2018, President Trump imposed economic sanctions on Iran and withdrew the United States from the Iran Nuclear Deal.  President Trump’s approach to international sanctions on OPEC members Iran and Venezuela have decreased international oil production by approximately 3 million b/d, slightly more than 3% of world supply.  If President Trump is re-elected, he is expected to continue the sanctions pressure on the two countries, restricting Iran and Venezuela’s oil exports.  If Biden is elected, Iranian oil exports could rise 1.8 million b/d by the end of 2021.  There is a possibility that Biden would amend the sanctions imposed on Iran, creating a partnered approach, assuming conditions are met, that would be similar to the deal struck under the Obama administration.  Global oil supply has the ability to dramatically shift, depending on each candidate’s international sanctions approach.ConclusionWe have examined only a number of categories of each candidate’s proposed agendas and the impact each will have on the oil and gas industry.  As with all industries, the oil and gas sector is affected by many macro and micro factors that transpire over a long period of time.  The true impact of each candidate’s policies, along with the policies that are already enacted, may not be measurable for years to come.  A summary of the key differences discussed above in each candidate’s proposed agendas are as follows:
Down and Out: Bankruptcy Valuations Portend Production Declines
Down and Out: Bankruptcy Valuations Portend Production Declines
Projections and reorganization valuations of some recent oil and gas debtors demonstrate that creditors are aiming to ride existing production out of bankruptcy as opposed to drilling their way out of it.Oil patch producers have been plunging towards bankruptcy for several months now as I have written before. This trend is on pace to continue with WTI still hovering around $40 per barrel. Hopes for even $50 per barrel prices could be cathartic for many, but alas prices have been flat for months now. There are dozens of areas and fields that have become economic at $50 compared to $40. Somewhat ironically, one of the pathways back to higher prices will be the decline of production in the U.S. (if not replaced elsewhere). That appears to be the case for most producers already in Chapter 11 bankruptcy.Whiting is a good example. According to its bankruptcy filings, projections show that Whiting is only expected to spend a paltry $6 million on capital expenditures in 2021 against $300 million in EBITDA. Cash flows are scheduled to be maximized towards claim recovery; particularly its reserve-based lending (RBL) claims of $581 million. As such, production is slated to decline steadily over the next five years as its creditors attempt to recover claims. Creditors’ priorities make sense from their standpoint. Even banks with financially stable clients are not advancing higher borrowing bases right now.Whiting’s midpoint reorganization value as estimated in its bankruptcy documents is also primarily reflective of its cash flows from existing wells and not from prospective future wells and acreage. As such, its valuation, while steady from an EBITDAX multiple perspective, is towards the bottom of Mercer Capital’s range of publicly traded implied production multiples.Whiting is not alone at these valuation metrics. Bruin, another bankrupt operator in the Williston basin, has a reorganization value of 5.4x projected EBITDAX and a production multiple of $18,558. Bruin also is expected to spend relatively little ($15 million) on exploration expenses, however, it also has 1/5th of Whiting’s production. While also at the low end of implied public multiples, Whiting and Bruin are at a higher premium than some in the market right now.Another bankrupt company, California Resources Corp. has a higher production multiple than either Whiting or Bruin. This appears to be driven by substantially higher realized oil prices in California, and also potentially by shallower decline curves that lead to longer lived wells in the San Joaquin and Los Angeles Basins. It’s also remarkable that California Resources plans to spend more than Whiting and Bruin combined in 2021.[caption id="attachment_34208" align="alignnone" width="638"]Source: Mercer Capital Analysis[/caption] How do these values stack up in the transaction marketplace? Not a simple answer. First, there aren’t many deals happening in this environment and the ones that are happening are not in the Williston or California. One recent deal is Devon Energy’s purchase of WPX Energy. All three reorganization values lag the implied transaction multiple for WPX Energy. A Permian-based operator with an oil tilted production mix, WPX, transacted for $27,198 per flowing barrel according to Shale Experts. However, it is not surprising that it went at a premium to these debtors; with plans to limit future drilling, the debtors’ reorganization values are thus more heavily weighted towards PDP production than any other reserve category. Additionally, the Permian has been a favored basin compared to the Williston and California in recent years. Amid this year’s turmoil, the Permian is still expected to lead U.S. oil growth for years to come. Depending on who one consults, the basin with the most amount of potential to return to profitability as oil crawls back towards $50 per barrel is the Permian. There are already a few top tier locations that are profitable at $35 per barrel, but those are limited locations and are mostly in the Delaware. Certain areas in the Permian contain several potentially economic locations between $40 and $50. In contrast, most of the Williston’s inventory becomes profitable at above $50 per barrel. Still, as it stands at around $40 per barrel, only a handful of areas (mostly in the Eagle Ford and Permian) are profitable to drill right now. According to the most recent Dallas Fed Energy Survey, oil prices are expected to rise less than 10% by next year. Accordingly, drilling activity has turned anemic. Rigs, which as recently as a year ago were plentiful across the fruited plains, are as sparse as some endangered species. That will not change until oil gets back over $50 and where differentials between benchmarks and actual realizations are smaller. In the meantime, production could continue to fall off. Since March, production in the U.S. fell as far as 20% in September. This is a precipitous decline in a short amount of time. The chart above reflects not only the lack of new drilling, but the steep decline that shale oil wells intrinsically have. This will be a critical consideration in bankruptcy hearings. How steep will decline curves be and how much will revenues (and thus debt recovery) be delayed or impaired by these declines? Additionally, if OPEC fills the supply gap once demand returns, which it is projected to do, U.S. producers could miss some of the comeback especially with current China tensions. That said, investment prospects remain cloudy as more look to get out than to get in. JPMorgan Chase just announced that it is shifting its financing portfolio away from fossil fuels. Although disputed by many experts, one of BP’s world oil scenarios contemplates peak oil as governments and markets shift away from fossil fuels more quickly than anticipated. ESG investing and stronger investor sentiments towards other fuel sources imply that its possible oil did in fact peak in 2019. If that is the case, then Whiting, Bruin and California Resource Corp’s creditors will be hoping that their debtor’s recovery will pick up alongside improving oil prices. If prices do not recover quickly then they will be joined by many more peers before 2020 ends, which will likely exacerbate more production decline in the U.S. Originally appeared on Forbes.com on October 13, 2020.
Oilfield Services in 2020
Oilfield Services in 2020

Fork in the Road: Survival or Bankruptcy?

To say that 2020 has been “rough” for U.S. oil and gas (O&G) industry participants would be the height of an understatement.  The one-two punch of the Saudi-Russia dust-up over oil market share, and the COVID-19 pandemic, which together spiked oil supplies and made demand plunge, combined to set-up for a record bad year for the O&G industry.  Oil prices, that ended 2019 near $60/barrel (WTI), tumbled below $22/barrel in late March, and hit a 2020 low of $17/barrel in April.  A much welcome partial recovery during the month of May led to a somewhat stabilized price range of $36-$43/barrel through the third quarter.  While $40/barrel oil prices provided at least some relief to O&G industry participants, prices at that level aren’t expected to lead to anything close to a recovery to pre-2020 activity levels.  The industry continues to “flow red” with continued bankruptcies piling-up. Bankruptcy courts have been busy as a result of the O&G industry downturn.  Already this year 36 bankruptcies were filed among the production segment operators alone.  Industry insider conversations have included concerns that there could be 60-70 additional producer filings by the end of the year. If those predictions come true, 2020 would represent a record year for O&G-related filings in the annals of the bankruptcy courts.   While that may seem like an unusually bad turn for a six-month period of depressed prices, it’s worth noting that the industry was significantly stressed beforehand.  Natural Gas Intelligence’s Andrew Baker noted that the anticipated cutbacks in future capital expenditures among the producers for drilling, completions, and other activities in the field will most certainly spread the bankruptcy trend to the oilfield services (OFS) segment that never completely recovered from the 2014 industry downturn.  Baker indicated that “many smaller or highly leveraged OFS companies may not be able to hold on” and will be forced to seek the protection of bankruptcy courts. As Baker referenced, size and financial leverage can generally contribute to an OFS participant business being forced into a bankruptcy filing.  In this edition of Mercer Capital’s Energy Valuation Insights blog, we explore some of the many factors that play into making it more (or less) likely that an OFS participant will survive an industry downturn intact, or succumb to market pressures and enter into bankruptcy. OFS Bankruptcy DifferentiatorsThere are most certainly many factors that may contribute to, or deter, an OFS company’s need to file for bankruptcy protection during an industry downturn.  Some are more general and more obvious, while others are more specific and not as readily discerned.  Here we address some of the more general factors (margins, financial leverage, and breadth of product/service offerings), some industry specific factors (customer sectors and basins served), and the benefit of industry experience.General FactorsAs in any industry, the ability to survive a downturn in the OFS industry is all about maintaining cash flow, and therefore liquidity.  No surprise here, a company generating higher margins in “normal” industry conditions is more readily able to navigate a downturn when the company’s margins are likely to get pinched.  As such, bankruptcies during a downturn in the industry are materially more likely among highly competitive sectors of the OFS industry where margins tend to be lower, as opposed to less competitive sectors, where margins tend to be more robust.  Beyond general competition levels, a particular OFS company’s margins may be influenced by a number of factors.  These include proprietary products or processes, its having embraced efficiency inducing technology and automation, and other factors that contribute to lower cost of sales, or operating expenses.  With higher margins, an OFS company is able to endure the margin reductions that come with industry downturns with a significantly lower probability of reaching a financial breaking point....the ability to survive a downturn in the OFS industry is all about maintaining cash flow, and therefore liquidity.Similarly, the degree to which an OFS company makes use of financial leverage to enhance returns can play into its ability to weather an industry storm.  Take Company A and Company B that both generate the same operating cash flow margins – margins before consideration of financing costs in the form of interest expenses on outstanding debt.  If Company A carries a lower level of debt financing (relative to Company B), its operating cash flow will be greater than Company B’s.  The cash flow differential may not be a make-or-break matter during normal industry conditions when both companies are generating significant cash flows relative to their interest expense.  However, during periods of reduced cash flow, the more leveraged company may reach a point where operating cash flows are inadequate to meet its interest payments.  So, the financial leverage that enhances return during the times of industry strength can be the same financial leverage that leads to distressed liquidity during industry downcycles.An OFS company’s breadth of product or service offerings can also impact the ability to maintain operations during a downturn.  Larger OFS participants, with multiple product or services offerings, have the benefit of being able to consider shifting its efforts among various offerings.  In that way, the company can emphasize operations where it can continue providing more productive (profitable) lines and deemphasize less productive lines.  It may even be in a position to sell-off assets related to less productive lines in order to maintain liquidity to continue operations of productive lines.  WorldOil Magazine’s David Wethe cites examples of this type of shifting of products/services in Schlumberger’s sale of its land-rig unit in the Middle East and Precision Drilling’s sale of its Mexican operations as the companies struggled in recent years.  Unlike these larger industry participants, smaller companies with very limited product or service offerings, don’t have nearly the same level of flexibility.  Among these smaller OFS companies, diversity of offerings may simply not exist.  That leaves the businesses without the ability to shift away from less profitable products or services, and therefore make them more prone to the necessity of a bankruptcy filing.Industry-Specific FactorsThe diversity and breadth of the OFS industry brings additional factors that may influence an industry participant being forced into a bankruptcy filing.  Despite the misnomer, the OFS industry includes providers of products and services to both oil-focused and gas-focused E&P companies.  The graphic below provides some insight as to just how wide an array of products and services are represented within the OFS industry.Sub-Sectors FocusDue to the significant differences between the operations of the OFS industry participants, an industry downturn doesn’t impact all OFS participants to the same degree.  For instance, OFS businesses that disproportionately serve the natural gas side of the industry were not as significantly impacted by the precipitous drop in oil prices during the 2020 second quarter.  In the same way, OFS participants may be impacted quite differently based on the E&P subsector that they serve.  For example, during the 2020 oil price disruption, new drilling operations were much more adversely affected than were continuing production operations.  Following a sharp decline in oil prices, exploration operations may be curtailed much more so than production operations.  For example, when oil prices are in the $35 to $40 per barrel range, it can be economically beneficial to continue production from existing wells, but quite uneconomically viable to incur the cost of drilling new wells.  Even much less economical to incur exploration related expenses.  As such, OFS companies whose products or services support production activities – fracking, well maintenance services, and production chemical providers – face less dire circumstance at $35 to $40/barrel prices than OFS companies that support exploration activities – geological, seismic, drilling, and site preparation services.Basin FocusBeyond the differences between serving the oil versus gas subsectors, and the differences between serving exploration versus production subsectors, there are differences in the basins that a particular OFS business focuses on.  These differences can generally be categorized into three areas – type of oil, midstream transportation availability, and production cost.   Different basins may produce different types (grades) of crude oil (light versus heavy, sweet versus sour, etc.), which require varying levels of refining in order to generate end products.  As such, the “price” of oil isn’t uniform across basins, and as a result, a drop in oil demand can impact different basins to varying degrees.[caption id="attachment_34074" align="alignnone" width="726"] http://www.eia.gov/maps/maps.htm[/caption] Similarly, the midstream transportation assets of a particular basin can influence the price of oil based on the location of the production facilities.  Basins, where pipeline capacity is lacking, may have a higher cost of getting the oil to refining facilities and, therefore, require higher prices to justify continued production.  In much the same way, different basins can have materially different production costs per barrel depending on the age of the fields and the specific geology of the field. As with basins that suffer from higher costs in getting produced oil to refineries, basins that have higher production costs (the total cost of bringing oil/gas to the surface) may not have the needed economics to justify continued production at oil prices that allow for continued production from basins with lower production costs.  For example, Reuter’s Energy Correspondent, Liz Hampton, notes that oil firms operating outside the Permian basin (in Oklahoma, Colorado, Wyoming, Kansas, and parts of New Mexico) where production costs are higher may be particularly hit hard by oil prices in the $25 to $30/barrel range. On average, producers in those states need oil prices at $47 a barrel to make money. Liquidity Management and Cost StructureTo this point, we’ve addressed factors that primarily impact the demand for an OFS participant’s products and services.  Now we move to factors beyond demand – liquidity and cost structure/control.  In a pronounced industry downturn, where cash flows are known to be turning negative for an indeterminate amount of time, liquidity becomes a major focus point.  If cash runs out, a previously slow decline in business can rapidly turn into a downward spiral.  Managing the company’s liquidity can involve several related actions including reducing costs, drawing down existing lines of credit (before they become difficult to access), and engaging as soon as possible with debt providers.  While it may seem that these actions would have the same benefit to all OFS participants, the results of such efforts can vary markedly.In a pronounced industry downturn, liquidity becomes a major focus point.OFS businesses that have closely managed their line of credit, such that they have abundant LOC capacity remaining when a downturn occurs, have flexibility that other OFS businesses lack.  Likewise, OFS participants that maintain close debtor relationships are likely to get a better reception when negotiating with their debtors for adjustments to their debt structure, or for forbearance terms.In terms of cost reduction, a company’s particular cost structure plays a significant role in its ability to cut expenses.  Businesses with higher fixed costs lack the level of flexibility in cost containment that lower fixed cost businesses have.  For example, businesses in which human resources are a larger percentage of total expenses have greater flexibility when considering staff reductions, pay-cuts, furloughs, and reducing hours.  Furthermore, the ability to take those type cost containment actions can be easier for OFS businesses where the time to identify and hire qualified employees is shorter, and the cost of training such employees is lower.  These factors make it easier to take critical human resource related / cost containment actions, in that any resulting staff losses can easily be replaced, and at a lower replacement cost.Management ExperienceOur discussion of differences among OFS industry participants during a downturn, would be incomplete without addressing the benefit of a management team with deep industry experience.  Industry downcycles in highly cyclical industries,  can be even more challenging with a management team that has limited experience.  Most industries experience some degree of cyclicality, but the O&G industry tends to bring a heightened level of ups and downs, and unexpected supply and demand shifts.  Afterall, how many industries can even fathom the idea of the futures market, for their only product, pushing into the realm of negative pricing?  How many industries can be so significantly impacted, in such a short period of time, by a market share spat between market participants on the other side of the globe – not to mention those market participants being countries (Saudi Arabia and Russia) rather than individual businesses.  Not exactly an industry conducive to downturn survival if the management team has limited industry experience.In a recent management interview with one of our recurring OFS clients, the head of the company expressed how industry experience allows a seasoned management team to act quickly and decisively, and that such actions can make or break an OFS business in an industry wide downturn.  He commented that less experienced management teams sometimes suffer from a “drug” known as “hopium” – a tendency to hope that the downturn will be short lived and therefore hesitate to take the necessary decisive action needed to stave off a cash crunch that can rapidly turn into a bankruptcy filing.  He further noted that due to his teams’ deep industry experience across multiple O&G cycles, when the combined COVID-19 and Saudi-Russian dust-up hit, his team immediately, as he put it, flipped open to page 5 of their “Oh <bleep>” playbook and began a pre-planned series of actions to enhance liquidity and reduce costs, without allowing unwarranted “hope” to get in the way.  As such, their business, while certainly feeling the impact of the downturn, is feeling it much less negatively than other OFS businesses.ConclusionWhile the O&G industry has many systematic forces that impact industry participants across the board, there are many unsystematic forces that lead to marked differences in the magnitude of the downturn’s impact on individual businesses.  The OFS portion of the O&G industry is particularly diverse with subsector and basic focus potentially imposing greater, or lesser, downturn risk on a particular OFS market participant.  Beyond those demand impacting factors, cost structure and level of industry cycle, experience among management teams have a significant impact on an OFS business’s ability to hold-on during an industry wide downturn and avoid the need for a bankruptcy filing.
Oil & Gas Industry Optimism Contained with Political Uncertainty Lying Ahead
Oil & Gas Industry Optimism Contained with Political Uncertainty Lying Ahead

Q3 2020 Macro Review

The third quarter of 2020 experienced a relatively stable price environment compared to the volatile prices seen in the first half of the year.  The WTI range narrowed, hovering around $40 per barrel, and natural gas increased from $1.70 per MMbtu to $2.50 per MMbtu.  According to the Dallas Federal Survey released on September 23, industry participants expect oil price to be nominally higher than last quarter’s expectations, but respondents continue to state that most new drilling remains uneconomic.  The concurrent overlapping impact of (i) discord created by the OPEC/Russian rift and resulting supply surge; and (ii) the drop in demand due to COVID-19 related issues was historic and continued to play a role in the third quarter.  As optimism surrounding a gradual demand recovery has increased, companies are preparing for an eventful end to 2020.  As if COVID-19 and the Russian-Saudi price rift wasn’t eventful enough, an election in November will add to the mix for what seems to be an already pressing and critical time for the industry.  The unfortunate, overlapping timing of these events has made the bankruptcy courts busy, with no indication of that trend coming to a halt.  In this post, we will examine the macroeconomic factors that have affected the industry in the third quarter and peek behind the curtain on what the remainder of the year might hold.Global EconomicsOPEC+On June 6, OPEC+ members reached an agreement to continue cutting 9.7 million barrels a day, or about 10% of global output under normal circumstances, through July.  The extended supply cuts helped oil prices continue their recovery from their drastic drop in April due to the demand issues caused by COVID-19.  The original agreement that OPEC+ reached on April 12 stated that production was set to increase gradually after June, but members refined that plan and continued their supply cuts for another month.On July 15, OPEC + members agreed to loosen existing production caps by roughly 1.6 million barrels a day.  The agreement was slated to begin in August as demand was showing signs of recovery amid the COVID-19 related lockdowns.  The decision created a 10% increase in Brent prices to $43.30/bbl.  OPEC expects the world’s demand for oil to increase by 7 million barrels a day next year, after a forecast 8.9 million barrel a day decline in 2020.  A primary source of overall industry decline is the lack of jet fuel demand as travel has decreased significantly throughout the year.  According to the Dallas Federal Energy Survey, 74% of industry executives believe that OPEC will play a bigger role in the determination of the price of oil going forward.Potential Market Consequences: Trump vs. Biden AdministrationThe upcoming election in November 2020 is on the industry’s mind as both administrations have expressed their energy initiatives that will be implemented during the next four years.  The election comes at a pressing time in the industry, with the next four years of U.S. oil and gas policy at stake.  The major topics at hand include domestic production, infrastructure plans, OPEC+ engagements, and international sanctions.  The following chart shows the contrasting platforms of the two potential administrations:U.S. ProductionThe decline in production, 9.7 million b/d year-over-year in August, reflects voluntary production cuts by OPEC+ along with reductions in drilling activity and curtailments as of late.  The EIA estimates that U.S. crude oil production increased to 10.8 million b/d in August as operators have brought wells back online in response to rising prices after curtailing production in the second quarter.  Frac fleets have slowly grown since May, but still are down roughly 68% from the peak in 2020.  After September, however, the EIA projects U.S. crude oil production to decline slightly as new drilling activity will not generate enough production to offset declines from existing wells.  According to the Dallas Federal Energy Survey, 66% of industry executives believe that U.S. oil production has peaked.   The upcoming election poses significant uncertainties as the two administrations’ contrasting agendas will play a major role in U.S. production moving forward.BankruptcyCompanies are on their heels heading into the end of 2020.  Bankruptcy activity has heightened, and debt levels have increased as companies are hoping the worst is behind them.  The question is whether the worst is yet to come.  Balance sheets have become increasingly important and cash will remain king until the price environment becomes more economic.  Deal activity has been quiet as of late, though ended with a bang given Devon’s announced merger with WPX. More deals could come as buyers and sellers turn to consolidation to reduce costs in these challenging times.  That does, however, assume companies will not have to file for bankruptcy.Interest RatesThe U.S. Federal Reserve cut interest rates twice in the month of March. On March 3, the Fed made an emergency decision to cut interest rates by 0.5% in response to the foreseeable economic slowdown due to the spread of the coronavirus. This cut was anticipated and largely shrugged off by the markets as interest rates continued their precipitous decline.  Benchmark rates were again cut on March 15 by a full percent to near zero.  The Federal Reserve’s latest forecast suggests that rates will remain close to zero for the foreseeable future until inflation increases.ConclusionAs the industry attempts to recover from a dramatic timeline of events in the first half of 2020, many uncertainties remain ahead.  Companies are trying to survive during the challenging environment while attempting to shore up the balance sheet and hang on tight with the election on the horizon.  Potential policy changes might be the least of companies’ worries as other pressing issues are affecting them in the very short-term.  All of the pieces are stacking up against the industry, and it will be interesting to analyze the next six months, which could very well look different.At Mercer Capital, we stay current with our analysis of the energy industry both on a region-by-region basis within the U.S. as well as around the globe. This is crucial in a global commodity environment where supply, demand, and geopolitical factors have varying impacts on prices. We have assisted clients with diverse valuation needs in the upstream oil and gas industry in North America and internationally. Contact a Mercer Capital professional to discuss your needs in confidence.
EP Fourth Quarter 2020 Appalachian Basin
E&P Fourth Quarter 2020

Appalachian Basin

Appalachian Basin // The fourth quarter of 2020 experienced an increasing price environment compared to the volatile prices seen in the majority of 2020.
Bakken Production Has Rebounded, But Operating Challenges Remain Acute
Bakken Production Has Rebounded, But Operating Challenges Remain Acute
The economics of oil and gas production vary by region. Mercer Capital focuses on trends in the Eagle Ford, Permian, Bakken, and Marcellus and Utica plays. The cost of producing oil and gas depends on the geological makeup of the reserve, depth of reserve, and cost to transport the raw crude to market. We can observe different costs in different regions depending on these factors. In this post, we take a closer look at the Bakken.Production and Activity LevelsEstimated Bakken production declined approximately 16% year-over-year through September, in line with the Eagle Ford, though worse than production declines seen in the Permian (down approximately 5%) and Appalachia (essentially flat).  However, the Bakken has rebounded strongly from production lows observed in May following April’s historic rout in crude oil prices.  The Bakken was particularly impacted by production curtailments, driven in part by higher pricing differentials given the basin’s location, higher breakeven prices, and the fact that most operators in the basin have diverse operations, giving them optionality as to where to curtail production while being able to maintain cash flow necessary for near-term obligations (unlike pure-play counterparts). The rig count in the Bakken stood at 10 as of September 18, down over 80% from the prior year.  Only the Eagle Ford has seen a more severe drop in rigs, with the rig count declining by more than 86% during the same period.  While swift, the decline has stabilized.  The Bakken’s rig count has ranged between 9 and 11 rigs during the third quarter.  However, a meaningful increase in rigs is unlikely given reduced capex budgets. Commodity Prices Stabilize, Though Uncertain Demand Dynamics RemainThe third quarter of 2020 was relatively quiet for commodity prices, with near-term WTI futures prices oscillating around $40/bbl. Natural gas prices, which avoided crude oil’s steep declines in April, have generally been trending higher.  Part of that relates to a reduction of associated gas production driven by lower oil production activity, as well as some regular seasonality as winter approaches. We note that CapitalIQ has revised the default futures contracts utilized for historical commodity pricing in order to make the output more reasonable.  (Hence the lack of negative prices shown in the preceding chart.)  As such, the information shown may not tie to previous analyses. However, there is still considerable uncertainty around future demand, both near-term and long-run.  While resuming economic activity has spurred an increase in consumption, changing travel habits and concerns around a potential surge of COVID-19 cases during the upcoming traditional flu season have clouded experts’ ability to make projections.  In the longer-run, BP’s 2020 Energy Outlook expects global liquid fuels consumption to peak by 2030 under a “business as usual” scenario.  Under scenarios assuming more aggressive policy measures to reduce carbon emission, BP’s analysis suggests that liquid fuels consumption peaked in 2019 and will continue to trend downward. Financial PerformanceWith Whiting’s restructuring (discussed in a subsequent section), the Bakken-focused peer group with meaningful historical trading activity has become quite small.  Continental Resources is down approximately 57% year-over-year, though that isn’t much worse than the overall exploration & production sector (as proxied by XOP, which is down 51% over the same period).  Oasis Petroleum’s stock price has declined by approximately 88% over the past year and the company has warned of a potential bankruptcy filing. We note that neither company is pure-play Bakken, as Continental has a sizeable acreage position in Oklahoma’s SCOOP/STACK, and Oasis has operations in the Permian as well.  Other publicly traded Bakken operators, including ExxonMobil, Marathon Oil, Hess, EOG, Ovintiv, ConocoPhillips, and QEP, also have diverse operations outside the basin.  Northern Oil & Gas, which has traditionally focused on owning non-operating working interests in the Bakken, has expanded outside the basin with acquisitions in the Permian. Equinor, which entered the Bakken with its $4.7 billion acquisition of Brigham Exploration, announced that it is halting all U.S. shale drilling and well completion activity. The lack of a pure-play Bakken peer set makes it difficult to draw conclusions specific to the basin, but is also a telling fact about the difficult operating conditions in the area. Whiting Emerges, Oasis Potentially to Enter BankruptcyWhiting Petroleum, which announced its Chapter 11 reorganization process in April, emerged from bankruptcy in September.  The reorganization process allowed Whiting to reduce its debt load by more than $3 billion, from over $3.4 billion to just $425 million.  While shareholders were able to avoid being completely wiped out, the restructuring was extremely dilutive.  Legacy shareholders now own approximately 3% of the equity of the new entity.Oasis Petroleum announced it skipped an interest payment due September 15.  That puts the company in a 30-day grace period in which it can continue to negotiate with lenders regarding a restructuring.  Oasis has been reviewing strategic alternatives with advisors, including “a recapitalization transaction with a third-party capital provider; restructuring of the Company’s existing debt either through an out-of-court process or under Chapter 11 of the Bankruptcy Code; or other strategic transaction.”Dakota Access Pipeline Under Siege AgainEnergy Transfer’s Dakota Access Pipeline (“DAPL”), which was the subject of protests in 2016 and 2017, is under renewed legal action.  The pipeline, which was instrumental in helping minimize pricing differentials in the land-locked Bakken relative to other basins, has the capacity to transport 570 mbbl/d of crude oil from the Bakken to a hub in Illinois, with connections to pipelines serving refining markets in the Midwest and Gulf Coast.In July, a judge ruled that DAPL must be shut down and emptied by August 5, pending an environmental review by the Army Corps of Engineers.  A U.S. appeals court reversed the shutdown order in August, though the requirement for the environmental review is still under appeal.  Based on the current trial schedule, DAPL’s should be able to continue operating through at least late December before a federal court could mandate another shutdown.Despite the renewed legal scrutiny, Energy Transfer is pushing forward with an expansion plan which would roughly double DAPL’s capacity.  The additional capacity is expected to come online in the third quarter of 2021.ConclusionThe Bakken was hit the hardest by curtailments driven by low commodity prices, but has also seen the sharpest rebound in production.  Whiting’s successful restructuring should add stability to the basin, but Oasis may take its place shortly in the bankruptcy courts.  While operating conditions are difficult across the U.S., the stress appears quite acute in the Bakken.We have assisted many clients with various valuation needs in the upstream oil and gas space in both conventional and unconventional plays in North America, and around the world.  Contact a Mercer Capital professional to discuss your needs in confidence and learn more about how we can help you succeed.
M&A in the Bakken
M&A in the Bakken

Immense Drop in Deal Activity Due to COVID Concerns

Over the past several years, the Bakken has generally had much lighter acquisition and divestiture activity than other major basins in the United States. Given that deal activity across the energy sector has dropped an immense 42.7% over the past year, acquisition and divestiture activity has dropped even further in this basin over the past year.Observed deal activity has largely been the result of Northern Oil and Gas growing its production base in the area during the past several years.Recent Transactions in the BakkenDetails of recent transactions in the Bakken, including some comparative valuation metrics, are shown below.Northern Oil and Gas Continues Core Acreage BuildoutNorthern Oil has constituted approximately two-thirds of the observed deal activity (based on disclosed deal value) in the basin, including its bolt on acquisitions in June and August 2020 for several hundred acres. This activity furthers Northern Oil’s mission of building out its core position in non-operating interests through consistent, strategic acquisitions.Although production is down across the country, wells are slowly beginning to come back online, and Northern Oil believes increasing inventory while pricing is advantageous should drive returns in the future.According to Northern COO Adam Dirlam, “We continue to add to our core inventory. Record levels of wells-in-process should drive strong volumes, and improve upon our return on capital employed metrics in 2021 and beyond.”Since the start of 2018, the company has made six large publicly announced transactions totaling more than $820 million, including its large acquisition of private equity-backed Flywheel Energy LLC in April 2019.Below is a map of Northern Oil’s acreage to show its overall footprint in the basin.[caption id="attachment_33656" align="aligncenter" width="489"]Source: Northern Oil & Gas September 2020 Investor Presentation[/caption] ConclusionThe energy industry in Q1 and Q2 2020 has seen extreme volatility that has had investors and operators alike remaining cautious and waiting to see what happens next. As a result, acquisition and divestiture activity has been put on the back burner as companies struggle to plan ahead while remaining solvent.As we have moved from the second quarter to the third quarter, fundamentals in the Bakken have steadily improved as crude oil pipeline and storage limitations were alleviated. Stabilization of WTI pricing and well differentials in the region over the past couple of months have also aided as well. Companies like Northern Oil look towards the future as demand begins to creep upward from its mid-year lows, and the company has taken advantage of lower pricing to accrete acreage to its core position.We have assisted many clients with various valuation needs in the upstream oil and gas industry in North America and around the world.  In addition to our corporate valuation services, Mercer Capital provides investment banking and transaction advisory services to a broad range of public and private companies and financial institutions.  We have relevant experience working with companies in the oil and gas space and can leverage our historical valuation and investment banking experience to help you navigate a critical transaction, providing timely, accurate and reliable results.  Contact a Mercer Capital professional to discuss your needs in confidence.
Themes from Q2 2020 Earnings Calls (1)
Themes from Q2 2020 Earnings Calls

Part 2: E&P Operators

As discussed in our quarterly E&P newsletter, the oil & gas industry experienced a volatile path to price stability as COVID-19 and the Saudi-Russia price war took a toll on supply and demand.  The road to recovery was apparent late in the quarter and was driven by supply cuts from OPEC+, curtailments by U.S. producers, and an increase in demand.  In this post, we capture the key takeaways from E&P operator second quarter 2020 earnings calls.Theme 1: Cost Reductions Expected to PersistOne recurring theme among E&P operators in our prior E&P operator earnings calls quarterly overview included a continued focus on capital discipline.  The six E&P operators we track typically characterize this concept as the reduction of operational costs and capital expenditures in the pursuit of increased operational and capital efficiencies.  To that effect, all six operators pursued this goal in the second quarter, with most indicating the expectation that a substantial portion of these cost reductions will persist beyond the current environment of suppressed crude oil prices and uncertain projected economic activity.We expect capital efficiencies to increase across both the Bakken and the South in 2020.  In the Bakken, we have achieved a 12% reduction to completed well costs.  In the South, we've achieved a 10% reduction to our overall South completed well cost.  70% of these reductions are structural in the Bakken, and 80% of these reductions are structural in the South, driven by all aspects of our operations. – William Berry, CEO, Continental Resources, Inc.This flexibility, combined with mature production base and the structural well cost savings we have delivered, underpins our outlook for durable cash flow generation, as we were able to reduce our reinvestment rate, while maintaining production levels in a low-price environment. – Joseph Gatto, President & CEO, Callon Petroleum CompanyDiamondback has further adjusted downward our already low-cost structure and is prepared to operate successfully in a lower-for-longer oil price environment.  A lot of the efficiency and cost gains made during this downturn will become permanent and will benefit Diamondback shareholders in a recovery. – Travis Stice, CEO, Diamondback Energy, Inc.When you look at these efficiency gains combined with service cost deflation and a consistent development strategy, we continue to drive down our well costs and drastically improve capital efficiency.  As you can see […] we have reduced our well cost by approximately $1.8 million or 20% in the first two quarters of 2020.  We believe that approximately 60% of these cost reductions are sustainable. – Joey Hall, Executive Vice President – Permian Operations, Pioneer Natural Resources CompanyTheme 2: Emphasis on Free Cash Flow to Reduce Debt and Reinforce DividendsIn our prior quarterly analysis, we noted that the operators seemed inclined to comment on their priorities moving forward.  This was a recurring theme in the Q2 earnings calls.  Short of referring to any such commentary as official guidance, most operators still discussed three to five year strategic goals, driven primarily by the growth of free cash flow projected to result from the cost reductions outlined previously.  Among the priorities set forth by the operators, the two primary goals cited included debt reduction and providing for attractive dividends to shareholders.As I think about the first half of this year, we've made real progress on several priorities that will position us for the future: maximizing our cash flow by adjusting our spend rate, production and cost structure; increasing the strength of our balance sheet; continuing to return capital to shareholders through our dividend; and managing the oil price volatility with capital discipline, while also preserving our operational capacity. – Tim Leach, Chairman & CEO, Concho Resources Inc.With our reduction in forward capital spending, and expectation for true free cash flow generation at current commodity prices in the second half of 2020 and 2021, we will look to reduce both gross and net debt while continuing to return capital to our shareholders through our base dividend. – Travis Stice, CEO, Diamondback Energy, Inc.Initially we'd be looking to prioritize a bit of debt reduction as we then look to ease back into a base dividend structure.  And then, in excess of that, there are a lot of other vehicles that we could consider the variable dividend is one, but certainly even share repurchases is another.  I mean, nothing would be off the table. – Lee Tillman, President & CEO, Marathon Oil CompanyTheme 3: Expectation of Little to No Production Growth… MostlyRemarkably, the pursuit of production growth was not presented as an immediate priority by most operators at this time.We were saying essentially that – and early on – that we should not be, as an industry, overproducing into an oversupplied market. – William Berry, CEO, Continental Resources, Inc.Certainly, we're not seeing any signals that growth is needed from Diamondback or from our industry in general.  So, growth in today's world is pretty much off the table. – Travis Stice, CEO, Diamondback Energy, Inc.Today, the world simply does not need more of our product. – Lee Tillman, President & CEO, Marathon Oil Company The exception was Pioneer Natural Resources, which was the only operator that specifically cited a positive production growth rate estimate:We say 5% plus on production growth, some years it maybe 6%, some years it maybe 7%, but we don’t want to just tie to one number based on rig activity, DUC activity, frac fleet activity.  We can’t hit 5% every year, so we want the flexibility, some years it maybe 7%, 8%, some years it maybe 4%, some years it maybe 5%, and so we’re just saying 5% plus on production growth over the next several years. – Scott Sheffield, CEO, Pioneer Natural Resources CompanyOn the HorizonThe E&P operator earnings calls broadly paint the picture of a mature industry in uncertain times.  The name of the game at this juncture is to shore up the balance sheet, increase efficiencies through capital discipline, and signal resilience by way of free cash flow growth and reinforced dividends to shareholders.However, as these companies stand relatively still as they fortify their positions for sustaining operations over the long-haul, changes and evolution are on the horizon.  Most prominently, the U.S. presidential election looms around the corner.  There is no indication of a consensus among the E&P operators regarding the likelihood of a regime change, or what changes would likely affect the industry if faced with a Democratic Biden administration.It should also be noted that the majority of the E&P operators have forthcoming formal ESG reports, with most slated to come out later this year.  We expect these topics will be featured in our next quarterly review of the E&P operator earnings calls.
Oil Frackers Are Breaking Records Again - In Bankruptcy Court
Oil Frackers Are Breaking Records Again - In Bankruptcy Court
This year has beaten down America’s oil producers. It started bad, with the Russian-Saudi battle for market share, then cascaded into terrible as the COVID pandemic gutted petroleum demand and sent oil prices down to an unheard of -$38 (negative!) per barrel.Those with the weakest hands have taken shelter in bankruptcy court, where it has been a busy six months. With the announcement of offshore producer Arena Energy’s bankruptcy late last week the count of North American bankruptcy filings for producers stood at 36 (31 of those have been in the second and third quarter so far this year). In terms of aggregate debt, the industry is near $53 billion for 2020 so far.  That puts the upstream segment on the precipice of having the most debt dollars exposed to bankruptcy protection in U.S. history and we still have four months to go.Some industry insiders are hearing that around 60-70 additional producers may file before year-end, meaning that a wave of companies are on this precipice. If that is the case, then Chapter 11 records will be left in the dust very shortly. That appears to be a monumental shift for six months of depressed prices, but it is important to remember that at around $50 per barrel (where oil had been most of the year prior) some upstream producers are barely breaking even. So when prices dropped even 15-20%, there wasn’t much margin left to work with.[caption id="attachment_33393" align="alignnone" width="640"]Source: Haynes & Boone Oil Patch Bankruptcy Tracker and Mercer Capital Research [/caption] As the industry heads down this road there will be some differences this time around compared to the surge in 2016, but with familiar signposts as well. What’s Different This Time?In 2016 a lot was different as far as the maturity and costs of drilling in the U.S. The Permian Basin was still getting its bearings on horizontal drilling in its bountiful stacked geologic formations in the Delaware and Midland sub-basins. Optimism and asset values were higher also as supply and demand balances were flipped in the U.S. at the time. While prices for 2016 averaged $43 per barrel, which is surprisingly close to today’s WTI prices of $42, asset values were far different and future drilling inventory (otherwise known as acreage) is currently valued significantly lower. The chart below gives us a glimpse of that.[caption id="attachment_33394" align="alignnone" width="640"]Source: Bloomberg[/caption] Rig counts and production declines are a hot topic right now as rigs and production are becoming scarcer items. This is different from last time because a higher percentage of U.S. production is tied to horizontal shale wells which decline much faster than conventional wells. According to the latest Dallas Fed Energy Survey, 82% of respondents shut-in or curtailed production in the second quarter 2020. Most of those producers expect minor or even significant costs to put those wells back online. This devalues reserves and limits recoveries for unsecured creditors. In contrast, few if any were shutting in wells in 2016. Another difference may be in how Chapter 11 reorganization plans consider future drilling plans and commitments. Let us not forget that an exploration and production company’s primary assets are essentially two things: (i) existing production and (ii) a drilling plan for future production. In the past, companies could effectively drill their way out of bankruptcy to generate cash flow, but as we’ve shown before, that may not be an option for some filers at $42 per barrel. Others that have hedged their production may have more latitude. That is a case by case situation. Drilling commitments and even force majeure are sometimes a significant negotiating point in bankruptcy cases. What’s Not Different This Time?For starters, this is some producers’ second or even third time that they have been in a restructuring situation in the past few years. This is sometimes known as the proverbial “Chapter 22” bankruptcy. Chaparral is one of those companies. In fact, Chaparral is an example of what else might not be different this time around –equitizing debt. Chaparral announced last week it will be equitizing all $300 million of its unsecured debt. Whiting’s bankruptcy will do this as well as their unsecured holders are estimated to recover around 39% of $2.6 billion in claims, but will end up owning 97% of the new company going forward, leaving 3% for the existing shareholders.Speaking of unsecured debt, the magnitude of unsecured debt will set records. However, the mix of secured vs. unsecured debt, overall, is similar to 2016. Asset values on the other hand are in different places, particularly PUD’s. This creates some uncertainty as to exactly where in the debt stack that creditors may recover their capital or otherwise must restructure their interest, often referred to by insiders as the “fulcrum security.” In a Chapter 11 bankruptcy scenario, there is typically a tier of creditors that is only partially “in the money.” For example, if a debtor’s secured debt will be paid in full, but unsecured debt will receive say 20 cents on the dollar, the unsecured debt is what is known as the fulcrum security.   This could also change during the bankruptcy especially if commodity prices change during the process and before plans of reorganization are approved. As challenging as this year has been so far, it is far from over and there may be a glimmer of hope that prices could rise before the end of the year.There are some bullish signs for oil. Drawdowns on inventories exceeding projections and have been coming down since mid-July. They now stand at levels similar to where they were in early April and are much closer to equilibrium than thought even 45 days ago. Fuel demand (except for jet fuel) is likely to recover before the end of the year, thus bringing upward pressure on prices according to ExxonMobil’s (XOM) latest investor presentation.[caption id="attachment_33395" align="alignnone" width="940"]Source: ExxonMobil Investor Presentation and the International Energy Agency (IEA)[/caption] If this happens, it will improve creditor recoveries, and lubricate gears of the bankruptcy process. It would also bring relief to those who are not planning to file and are looking to weather this year’s storm. Nonetheless, it is unlikely that even a precipitous rise in prices could stop this year from breaking bankruptcy records. That is the unfortunate reality that makes 2020 a frustrating year for many. Originally appeared on Forbes.com on August 25, 2020.
Themes from Q2 2020 Earnings Calls
Themes from Q2 2020 Earnings Calls

Part 1: Mineral Aggregators

As discussed in our quarterly overview, the oil & gas industry experienced a volatile path to price stability as COVID-19 and the Saudi-Russia price war took a toll on supply and demand. The road to recovery was apparent late in the quarter and was driven by supply cuts from OPEC+, curtailments by U.S. producers, and an increase in demand. Mercer Capital has aimed to focus on the mineral aggregator space, most recently with the release of the second quarter mineral aggregator valuation multiples analysis. In this post, we capture the key takeaways from mineral aggregator second quarter 2020 earnings calls.Theme 1: M&A Activity Is Momentarily Taking a Back SeatAlthough mineral aggregators have the reputation to seek acquisitions through reinvesting strategies, they seem hesitant to pull the trigger as the current environment is providing many challenges.The world’s greatest deal would have to present itself, and that’s always possible. But the world’s greatest deal would have to present itself, given where we’re currently trading. – Daniel Herz, President & CEO, Falcon MineralsI think it’s fair to say that it’s always more difficult to get deals done when the bid ask spread is just so severe. I mean, the volatility in oil prices kills deals. I mean, it just makes it really hard to get things done. – Davis Ravnaas, President, CFO & VP of Business Development, Kimbell Royalty PartnersThe balance sheet is most important, holding us back from M&A. I mean, if we saw the best deal in the history of minerals, we’d have to think hard about it, but unfortunately those deals just aren’t out there. – Kaes Van’t Hof, President, Viper Energy PartnersTheme 2: Consolidation and Operators’ Stability Is Affecting AggregatorsAs the difficult environment plays out, a number of operators will be forced to liquidate or consolidate, leading to opportunities for aggregators to work with new, and often financially improved, partners. In Brigham Minerals’ second quarter earnings call, Ben Brigham expressed his excitement to have their assets migrate into the hands of Chevron, subsequent to the closing of Chevron’s acquisition of Noble Energy (expected in the fourth quarter of 2020). As times are tough, aggregators assess the stability of their operators, and may be fortunate, like Brigham, to land a major partner.We expect financially challenged operators to liquidate or consolidate with larger entities and those surviving operators will focus on drilling our highest remaining rate of return wells. So I think that’s going to continue to play out – where you have a weak operator with the weak balance sheet, they’re going to get taken out by a stronger operator with a better balance sheet, and that’s going to benefit our asset base. – Ben Brigham, Founder & Executive Chairman, Brigham MineralsDorchester Minerals states that during the challenging environment they are observing the "Financial stability of our operators and lessees and paying increased attention to operator credit risk and revenue recovery." – Dorchester Minerals Annual Meeting Presentation held May 18, 2020What we have found to be very successful in times like this is that you need to be more of a partner with your operators now than maybe you do in really good times where capital is more available. – Jeff Wood, President and CFO, Black Stone MineralsTheme 3: Natural Gas Optimism Is IncreasingIt is pretty ironic that the industry is shifting its focus to natural gas, as it was viewed as a secondary asset not too long ago. Although at a historically low price, it has shown consistency and resiliency during the first half of the year as opposed to greater volatility in oil prices. Aggregators have not ignored this trend and seem optimistic about the future for natural gas.We're seeing increased deal flow in gas. A lot of Marcellus stuff is coming to market. – Davis Ravnaas, President, CFO & VP of Business Development, Kimbell Royalty PartnersWhile it’s been challenging to find many silver linings lately, one of them is a more constructive outlook for natural gas prices with several of our major equity research firms calling for gas prices well above the strip for 2021. – Tom Carter, CEO & Chairman of the Board, Black Stone MineralsFurthermore, combining this competitive advantage with our robust hedge book and significant natural gas production, which has an increasingly positive macro outlook, provides even more enhanced cash flow stability into the coming quarters, as we emerge from this volatile period. And I think some of our gas positions have been remarkably resilient. – Davis Ravnaas, President, CFO & VP of Business Development, Kimbell Royalty PartnersTheme 4: Balance Sheet Priorities: Preparing for the Worst, Hoping for the BestIt is no surprise that aggregators are paying close attention to their balance sheet positions. Participants on the calls gauged their company’s balance sheet flexibility. The aggregators remained confident that their ability to pay down debt and appease investors continues to be a priority. This may come at a cost to some companies such as Black Stone Minerals, as they sold two asset packages in the Permian in June to strengthen their liquidity position.In early June, we announced the sale of two asset packages in the Permian. Both of those transactions closed in July and brought in net cash proceeds of $150 million. That cash, together with the retained free cash flow from our operations, enabled us to reduce total debt by over $230 million or 60% from the end of the first quarter of this year. – Tom Carter, CEO & Chairman of the Board, Black Stone MineralsWe purposely reduced our acquisition activity in the latter half of the first quarter and largely through the entirety of the second quarter in order to preserve liquidity and maintain optimal balance sheet flexibility and thus position ourselves to capitalize on more attractive opportunities we expected in the second half of the year, that's playing out well for us now. – Robert Roosa, Founder & CEO, Brigham MineralsWe will use the retained amount to strengthen the balance sheet by paying down debt of $2.5 million in the coming days. We continue to manage the Company in a conservative and prudent manner, especially given the risks and uncertainties in the energy sector and the broader economy so far this year. – Davis Ravnaas, President, CFO & VP of Business Development, Kimbell Royalty Partners
Mineral Aggregator Valuation Multiples Analysis
Mineral Aggregator Valuation Multiples Analysis

Market Data as of August 14, 2020

As shown in the report, mineral aggregators’ stock prices have declined substantially over the past twelve months, but have rebounded from lows seen earlier in the year.  The perfect storm of reduced asset values, record-low IRS rates, and the prospect of significant tax law changes early next year make this the ideal time to think about estate planning and tax-efficient ways to transfer assets to the next generation.  With asset values trending upwards, vaccine candidates progressing rapidly, and political polling suggesting a high probability of a regime change in November, this perfect storm may not last long.  Take advantage by taking action.  In the current environment, there is little to gain by procrastinating, but potentially a lot to lose.  We’re here to help with any valuation needs you have in this unique environment. Download our report below.Mercer Capital has its finger on the pulse of the minerals market.  An important trend has been the rise of mineral aggregators, which have largely supplanted the trusts as the primary method of publicly traded minerals ownership.Due to a variety of corporate structures (including master limited partnerships and Up-Cs) and complex capital structures (including preferred equity and non-traded common units), mineral aggregator enterprise values pulled from databases are often missing meaningful components of value, leading to skewed valuation multiples.Mercer Capital has thoughtfully analyzed the corporate and capital structures of the publicly traded mineral aggregators to derive meaningful indications of enterprise value.  We have also calculated valuation multiples based on a variety of metrics, including distributions and reserves, as well as earnings and production on both a historical and forward-looking basis. Mineral Aggregator Valuation MultiplesDownload Analysis
Q2 2020 Exploration & Production Newsletter Release
Q2 2020 Exploration & Production Newsletter Release

Region Focus: Permian Basin

Mercer Capital’s Value Focus: Exploration & Production newsletter provides an overview of the industry through supply and demand analysis, commodity pricing, and public market performance. In addition, each issue of this quarterly newsletter focuses on a region, including, Eagle Ford, Permian, Bakken, and Appalachia, examining general economic and industry trends. In this quarter’s newsletter, we focus on the Permian.  Notable items include an unprecedented decline in oil prices, the Texas Railroad Commission’s proration discussions, and Pure Acquisition Corporation’s announced acquisition of HighPeak Energy. Download the newsletter below.Value Focus: Exploration & ProductionDownload the Q2 2020 Newsletter
Bridging Valuation Gaps With Options
Bridging Valuation Gaps With Options

How Option Pricing Can Be Used to Understand the Future Potential of Assets Most Affected by Low Prices, PUDs and Unproven Reserves

Due to the precipitous drop in oil prices in 2020, oil E&P companies in the U.S. have struggled to pay their debts, and in many cases already have had to file for bankruptcy.  In this post, we re-examine how option pricing, a sophisticated valuation technique, can be used to understand the future potential of the assets most affected by low prices, PUDs and unproven reserves. Whether companies are looking to sell these reserves to improve their cash balance, or are trying to generate reorganization cash flow projections during a Chapter 11 restructuring, understanding how to value PUDs and unproven reserves is crucial to survival in a down market.  The Struggle: Valuation in Distressed MarketsThe petroleum industry was one of the first major industries to widely adopt the discounted cash flow (DCF) method to value assets and projects—particularly oil and gas reserves. These techniques are generally accepted and understood in oil and gas circles to provide reasonable and meaningful appraisals of hydrocarbon reserves.  When market, operational, or geological uncertainties become challenging, such as in today’s low price environment, the DCF can break down in light of marketplace realities and “gaps” in perceived values can appear.The DCF can break down in light of marketplace realities and “gaps” in perceived values can appear.While DCF techniques are generally reliable for proven developed reserves (PDPs), they do not always capture the uncertainties and opportunities associated with the proven undeveloped reserves (PUDs) and particularly are not representative of the less certain upside of possible and probable (P2 & P3) categories. The DCF’s use of present value mathematics deters investment at low ends of pricing cycles. The reality of the marketplace, however, is often not so clear; sometimes it can be downright murky.In the past, sophisticated acquirers accounted for PUDs upside and uncertainty by reducing expected returns from an industry weighted average cost of capital (WACC) or applying a judgmental reserve adjustments factor (RAF) to downward adjust reserves for risk. These techniques effectively increased the otherwise negative DCF value for an asset or project’s upside associated with the PUDs and unproven reserves.At times, market conditions can require buyers and sellers to consider methods used to evaluate and price an asset differently than in the past. In our opinion, such a time currently exists in the pricing cycle of oil reserves, in particular to PUDs and unproven reserves.  In light of oil’s low price environment, coupled with the future price deck, many, if not most, PUDs appear to have a negative DCF value.What does this mean for the E&P companies looking to reorganize under a Chapter 11 Bankruptcy? There are five key concepts for management teams and their advisors to be familiar with to understand how reserve valuation impacts Chapter 11 reorganization.Liquidation vs. Reorganization. The proposed reorganization plan must establish a “reorganization value” that provides superior outcomes for shareholders relative to a Chapter 7 liquidation proceeding.Liquidation Value. This premise of value assumes the sale of all of the company’s assets within a short period of time. Different types of assets might be assigned different levels of discounts (or haircuts) based upon their ease of disposal.Reorganization Value. As noted in ASC 852, Reorganizations, reorganization value “generally approximates the fair value of the entity before considering liabilities and approximates the amount a willing buyer would pay for the assets of the entity immediately after the restructuring.” Reorganization values are typically based on DCF analyses.Cash-Flow Test. A cash-flow test examines the viability of a reorganization plan, and should be performed in order to determine the solvency of future operations. In practice, this test involves projecting future payments to creditors and other cash flow requirements including investments in working capital and capital expenditures.Fresh-Start Accounting. Upon emergence from bankruptcy, fresh-start accounting may be required to allocate a portion of the reorganization value to specific identifiable intangible assets. Fair value measurement of these assets typically requires use of the multi-period excess earnings method or other techniques often used in purchase price allocations following a business combination. If recent market transactions are utilized to establish a liquidation value, then it stands to reason that very little, if any, value will be given to the PUD reserves.  For a company trying to avoid liquidation in a distressed market where sale prices do not indicate the true value, there may still be a way to demonstrate significant value if reserves are retained in reorganization. However, that reorganization value has typically been based on a DCF.  It is possible that the DCF may capture significant value in PUD reserves because in reorganization debt levels are adjusted.  When debt levels are adjusted the cash flow PUD reserves need to generate to be viable is much lower.  This will provide two significant benefits: more time and possibly more cash. More time may allow global and regional oil and gas prices to increase while the additional cash flow from lower interest payments may allow investment in future PUD wells. Unfortunately, it is still the case that the present value calculation is strongly tied to current market conditions, and thus even for companies with reasonable leverage, many PUD and unproven reserves show negative cash flow.  The presence of some sizable transactions made without significant PDPs shows that there are buyers who disagree with this assessment and see value in these reserves.  The issue is demonstrating that value in either a sale or bankruptcy scenario.  An option pricing model is one solution that could account for the value of the increased time provided by restructuring the debt.Option Pricing Providing A Potential SolutionOne of the primary challenges for industry participants when valuing and pricing oil and gas reserves is addressing PUDs and unproven reserves.  As previously discussed, if one relied solely on the market approach many of these unproven reserves would be deemed worthless.  Why then, and under what circumstances, might the unproven reserves have significant value?The answer lies within the optionality of a property’s future DCF values.  In particular, if the acquirer has a long time to drill, one of potentially multiple forces come into play: either the PUDs potential for development can be altered by fluctuations in the price outlook for a resource, or, as seen with the rise of hydraulic fracturing, drilling technology can change driving significant increases in the DCF value of the unproven reserves.This optionality premium or valuation increment is typically most pronounced in unconventional resource or when the PUDs and unproven reserves are held by production. These types of reserves do not require investment within a fixed shorter and/or contractual timeframe.Current Pricing Environment:As oil prices have dropped and temporarily stabilized around $40 PUD values may drop precipitously. After the last recession, some PUDs faced a similar, yet more modest, decline in prices.  In fact, nearly half the companies surveyed this spring by the Federal Reserve Bank of Dallas reported only being able to be solvent for 2-3 years at the most under these values.  We have already seen some declare bankruptcy. Valuation would be made easier if we could determine when oil prices would rise again.  Valuations vary as to producers’ sensitivity to this price.  The Dallas Fed’s latest survey suggests that $40 is about the tipping point to restart shut-in wells, but not necessarily to drill new ones: Experienced dealmakers realize that the NYMEX future projections amount to informed speculation by analysts and economists many times vary widely from actual results.   So what actions do acquirers take when values are out of the money in terms of drilling economic wells? Why do acquirers still pay for the non-producing and seemingly unprofitable acreage?  In many cases, they are following a real option conceptual framework. Real Options: Valuation FrameworkPUDs are typically valued using the same DCF model as proven producing reserves after adding in an estimate for the capital costs (capital expenditures) to drill. Then the pricing level is adjusted for the incremental risk and the uncertainty of drilling “success,” i.e., commercial volumes, life and risk of excessive water volumes, etc. This incremental risk could be accounted for with either a higher discount rate in the DCF, a RAF, or a haircut.  Historically, in a similar oil price environment, as we face today, a raw DCF would suggest little or no value for the PUDs or unproven reserves.An option pricing model can guide a prospective acquirer or valuation expert to the appropriate segment of market pricing for undeveloped acreage.In practice, undeveloped acreage ownership functions as an option for reserve owners; they can hold the asset and wait until the market improves to start production. Therefore an option pricing model can be a realistic way to guide a prospective acquirer or valuation expert to the appropriate segment of market pricing for undeveloped acreage. This is especially true at the bottom of the historic pricing range occurring for the natural gas commodity currently. This technique is not a new concept as several papers have been written on this premise.  Articles on this subject were written as far back as 1988 or perhaps further, and some have been presented at international seminars.The PUD and unproved valuation model is typically seen as an adaptation of the Black Scholes option model.  It is most accurate and useful when the owners of the PUDs have the opportunity, but not the requirement, to drill the PUD and unproven wells and the time periods are long, (i.e. five to 10 years).  The value of the PUDs thus includes both a DCF value, if applicable, plus the optionality of the upside driven by potentially higher future commodity prices and other factors.  The comparative inputs, viewed as a real option, are shown in the table below. When these inputs are used in an option pricing model the resulting value of the PUDs reflects the unpredictable nature of the oil and gas market. This application of option modeling becomes most relevant near the bottom of historic cycles for a commodity. In a high oil price environment, adding this consideration to a DCF will have little impact as development is scheduled for the near future and the chances for future fluctuations have little impact on the timing of cash flows. At low points, on the other hand, PUDs and unproved reserves may not generate positive returns and thus will not be exploited immediately. If the right to drill can be postponed for an extended period of time, (i.e. five to ten years), those reserves still have value based on the likelihood they will become positive investments when the market shifts at some point in the future. In the language of options, the time value of the currently out-of-the-money drilling opportunities can have significant worth. This worth is not strictly theoretical either, or only applicable to reorganization negotiations. Market transactions with little or no proven producing reserves have demonstrated significant value attributable to non-producing reserves, demonstrating the recognition by some buyers of this optionality upside. All that said, there are some challenges and dangers in applying the options model to reserves such as observable markets, risk quantification, assumption sensitivity, service and drilling availability, and time to expiration to name several. Utilization of the modified option theory is not in the conventional vocabulary of many oil patch dealmakers, but the concept is considered among E&P executives as well during transactions in non-distressed markets. If the right to drill can be postponed for an extended period of time, (i.e. five to ten years), the time value of the out-of-the-money drilling opportunities can have significant worth in the marketplace. Careful application is important, but given today’s conditions, the benefit can outweigh the challenges.
Valuation Considerations in Bankruptcy Proceedings
Valuation Considerations in Bankruptcy Proceedings

An Overview for Oil & Gas Companies

The outbreak of the COVID-19 pandemic in the United States has caused a severe public health crisis and an unprecedented level of economic disruption.  While some economic activity is beginning to come back, predictions for longer-term negative economic impacts have also become more prevalent.  The initial thoughts of a quick V-shaped economic recovery have been replaced with a more nuanced consideration of how this situation will impact businesses within different industries and geographic areas over the next several years.  In some of the most hard-hit industries, we are already seeing what is expected to be a prolonged surge in corporate restructurings and bankruptcy filings.While some oil & gas industry bankruptcies have already occurred, expectations for many more to come are widely held.In the first half of 2020, the U.S. oil and gas industry suffered what was arguably its worst six-month period ever.  The combined impact of the Saudi/Russian price war and the drop in energy demand due to the onslaught of the COVID-19 pandemic was unprecedented.  Brent crude prices that had begun the year near $67 per barrel had dropped to $50 per barrel by early March before plummeting to $19 per barrel by the end of the quarter when the Saudi/Russia spat was in full force, but while the impact of the pandemic was still materializing.  Since the start of the pandemic, liquid fuel consumption has dropped by 15% with production levels falling 10%.  Drilling activity has been even harder hit with rig counts (active rotary rigs) now at a mere 30% of early first quarter levels.  Despite oil prices having partially recovered, oilfield activity remains anemic with the OFS industry having shed nearly 90,000 jobs through May.  While in a few areas oil and gas can be produced profitably at mid-year 2020 prices (WTI at 38.31 and Henry Hub at $1.63), most areas cannot.  Thus, while some oil & gas industry bankruptcies have already occurred, expectations for many more to come are widely held.For oil & gas companies, the decision to file for bankruptcy does not necessarily signal the demise of the business.  If executed properly, Chapter 11 reorganization affords a financially distressed or insolvent company an opportunity to restructure its liabilities and emerge from the proceedings as a viable going concern.  Along with a bankruptcy filing (more typically before and/or in preparation for the filing), the company usually undertakes a strategic review of its operations, including opportunities to shed assets or even lines of business.  During the reorganization proceeding, stakeholders, including creditors and equity holders, negotiate and litigate to establish economic interests in the emerging entity.  The Chapter 11 reorganization process concludes when the bankruptcy court confirms a reorganization plan that both specifies a reorganization value and reflects the agreed upon strategic direction and capital structure of the emerging entity.In addition to fulfilling technical requirements of the bankruptcy code and providing adequate disclosure, two characteristics of a reorganization plan are germane from a valuation perspective:11. The plan should demonstrate that the economic outcomes for any consenting stakeholders are superior under Chapter 11 proceeding compared to a Chapter 7 proceeding, which provides for more direct relief through a liquidation of the business. This is generally referred to as the “best interests test.”2. The plan should demonstrate that, upon confirmation by the bankruptcy court, it will not likely result in liquidation or further reorganization of the business. This is generally referred to as the “cash flow test.”Finally, upon emerging from bankruptcy, companies are required to apply “fresh start” accounting, under which all assets of the company, including identifiable intangible assets, are recorded on the balance sheet at fair value.Best Interests TestWithin this context of a best interests test, valuation specialists can provide useful financial advice to:Establish the value of the business under a Chapter 7 liquidation premise.Measure the reorganization value of a business, which, absent liquidation, represents the economic “pie” from which stakeholder claims can be satisfied. A plan confirmed by a bankruptcy court should establish a reorganization value that exceeds the value of the company under a liquidation premise.A Floor Value: Liquidation ValueIf a company can no longer pay its debts and does not restructure, it will undergo Chapter 7 liquidation.  The law generally mandates that Chapter 11 restructuring only be approved if it provides a company’s creditors with their highest level of expected repayment.  The Chapter 11 restructuring plan must be in the best interest of the creditors (relative to Chapter 7 liquidation) in order for it to be approved.  Given this understanding of the law, the first valuation step in successful Chapter 11 restructuring is assessing the alternative, liquidation value. This value will be a threshold that any reorganization plan must outperform in order to be accepted by the court.The value in liquidating a business is unfortunately not as simple as finding the fair market value, or even a book value for all the assets.  The liquidation premise generally contemplates a sale of the company’s assets within a short period.  Any valuation must account for the fact that inadequate time to place the assets in the open market means that the price obtained is usually lower than the fair market value.  Everyone has seen the “inventory liquidation sale” sign or the “going out of business” sign in the shop window.  Experience tells us that the underlying “marketing period” assumptions made in a liquidation analysis can have a material impact on the valuation conclusion.Liquidation value can occur under three sub-sets: assemblage of assets, orderly liquidation, and forced liquidation.From a technical perspective, liquidation value can occur under three sub-sets: assemblage of assets, orderly liquidation, and forced liquidation.  As implied, these are asset-based approaches to valuation that differ in their assumptions surrounding the marketing period and manner in which the assets are disposed.  There are no strict guidelines in the bankruptcy process related to these three sub-sets; bankruptcy courts generally determine the applicable premise of value on a case by case basis.  The determination (and support) of the appropriate premise can be an important component of the best interests test.In general, the discount from fair market value implied by the price obtainable under a liquidation premise is related to the liquidity of an asset.  Accordingly, valuation analysts often segregate the assets of the petitioner company into several categories based upon the ease of disposal.  Liquidation value is estimated for each category by referencing available discount benchmarks.  For example, no haircut would typically be applied to cash and equivalents, while less liquid assets (such as accounts receivable or inventory) would likely incur potentially significant discounts.  For some assets categories, the appropriate level of discount can be estimated by analyzing the prices commanded in the sale of comparable assets under a similarly distressed sale scenario.  Within the oil & gas industry, the operating assets come in many varieties, from oil & gas reserves, industry-specific well-site equipment and midstream assets, and less industry-specific equipment utilized by oilfield service providers.Reorganization ValueOnce an accurate liquidation value is established, the next step is determining whether the company can be reorganized in a way that provides more value to a company’s stakeholders than discounted asset sales.ASC 852 defines reorganization value as:2The value attributable to the reconstituted entity, as well as the expected net realizable value of those assets that will be disposed of before reconstitution occurs. This value is viewed as the value of the entity before considering liabilities and approximates the amount a willing buyer would pay for the assets of the entity immediately after restructuring.Typically, the “value attributable to the reconstituted entity” (i.e., the new enterprise value for the restructured business) is the largest element of the total reorganization value.  Unlike a liquidation, this enterprise value falls under what valuation professionals call a “going concern” value premise.  This means that the business is valued based on the return that would be generated by the future operations of the emerging, restructured entity and not what one would be paid for selling individual assets.  The intangible elements of going concern value result from factors such as having a trained workforce, a loyal customer base, an operational plant, and the necessary licenses, systems, and procedures in place.  To measure enterprise value in this way, reorganization plans primarily use a type of income approach, the discounted cash flow (DCF) method.  The DCF method estimates the net present value of future cash flows that the emerging entity is expected to generate.  Implementing the discounted cash flow methodology requires three basic elements:1. Forecast of Expected Future Cash Flows. Guidance from management can be critical in developing a supportable cash flow forecast. Generally, valuation specialists develop cash flow forecasts for discrete periods that may range from three to ten years, or in the case of upstream companies, the economic life of the company’s reserves. Conceptually, one would forecast discrete cash flows for as many periods as necessary until a stabilized cash flow stream can be anticipated.  Due to the opportunity to make broad strategic changes as part of the reorganization process, cash flows from the emerging entity must be projected for the period when the company expects to execute its restructuring and transition plans.  Major drivers of the cash flow forecast include projected revenue, gross margins, operating costs and capital expenditure requirements.  The historical experience of the petitioner company, as well as information from publicly traded companies operating in similar lines of business, can provide reference points to evaluate each element of the cash flow forecast.2. Terminal Value. The terminal value captures the value of all cash flows after the discrete forecast period. Terminal value is determined by using assumptions about long-term cash flow growth rate and the discount rate to capitalize cash flow at the end of the forecast period.  This means that the model takes the cash flow value for the last discrete year, and then grows it at a constant rate for perpetuity.  In some cases, the terminal value may be estimated by applying current or projected market multiples to the projected results in the last discrete year. An average EV/EBITDA of comparable companies, for instance, might be used to find a likely market value of the business at that date.  For upstream oil & gas companies, a terminal value is typically not utilized given the finite nature of the underlying resource.  Instead, the discrete cash flows are projected for the entire economic life of the reserves.3. Discount Rate. The discount rate is used to estimate the present value of the forecasted cash flows. Valuation analysts develop a suitable discount rate using assumptions about the costs of equity and debt capital, and the capital structure of the emerging entity.  Costs of equity capital are usually estimated by utilizing a build-up method that uses the long-term risk-free rate, equity risk premia, and other industry or company-specific factors as inputs.  The cost of debt capital and the likely capital structure may be based on benchmark rates on similar issues and the structures of comparable companies.  Overall, the discount rate should reasonably reflect the operational and market risks associated with the expected cash flows of the emerging entity.The sum of the present values of all the forecasted cash flows, including discrete period cash flows and the terminal value (if appropriate), provides an indication of the business enterprise value of the emerging entity for a specific set of forecast assumptions.  The reorganization value is the sum of that expected business enterprise value of the emerging entity and proceeds from any sale or other disposal of assets during the reorganization. Since the DCF-determined part of this value relies on so many forecast assumptions, different stakeholders may independently develop distinct estimates of the reorganization value to facilitate negotiations or litigation.  The eventual confirmed reorganization plan, however, reflects the terms agreed upon by the consenting stakeholders and specifies either a range of reorganization values or a single point estimate.In conjunction with the reorganization plan, the courts also approve the amounts of allowed claims or interests for the stakeholders in the restructuring entity.  From the perspective of the stakeholders, the reorganization value represents all of the resources available to meet the post-petition liabilities (liabilities from continued operations during restructuring) and allowed claims and interests called for in the confirmed reorganization plan.  If this agreed upon reorganization value exceeds the value to the stakeholders of the liquidation, then there is only one more valuation hurdle to be cleared: a cash flow test.  This is an examination of whether the restructuring creates a company that will be viable for the long term—that is not likely to be back in bankruptcy court in a few years.Cash Flow TestFor a company that passes the best interest test, this second requirement represents the last valuation hurdle to successfully emerging from Chapter 11 restructuring. Within the context of a cash flow test, valuation specialists can demonstrate the viability of the emerging entity’s proposed capital structure, including debt amounts and terms given the stream of cash flows that can be reasonably expected from the business.  The cash flow test essentially represents a test of the company’s current and projected future financial solvency.The cash flow test essentially represents a test of the company’s current and projected future financial solvency.Even if a company shows that the restructuring plan will benefit stakeholders relative to liquidation, the court will still reject the plan if it is likely to lead to liquidation or further restructuring in the foreseeable future.  To satisfy the court, a cash flow test is used to analyze whether the restructured company would generate enough cash to consistently pay its debts.  This cash flow test can be broken into three parts.The first step in conducting the cash flow test is to identify the cash flows that the restructured company will generate.  These cash flows are available to service all the obligations of the emerging entity.  A stream of cash flows is developed using the DCF method in order to determine the reorganization value.  Thus, in practice, establishing the appropriate stream of cash flows for the cash flow test is often a straightforward matter of using these projected cash flows in the new model.Once the fundamental cash flow projections are incorporated, analysts then model the negotiated or litigated terms attributable to the creditors of the emerging entity.  This involves projecting interest and principal payments to the creditors, including any amounts due to providers of short term, working capital facilities.  These are the payments for each period that the cash flow generated up to that point must be able to cover in order for the company to avoid another bankruptcy.The cash flows of the company will not be used only to pay debts, and so the third and final step in the cash flow test is documenting the impact of the net cash flows on the entire balance sheet of the emerging entity.  This entails modeling changes in the company’s asset base as portions of the expected cash flows are invested in working capital and capital equipment, and modeling changes in the debt obligations of and equity interests in the company as the remaining cash flows are disbursed to the capital providers.A reorganization plan is generally considered viable if such a detailed cash flow model indicates solvent operations for the foreseeable future.  The answer, however, is typically not so simple as assessing a single cash flow forecast.  It is a rare occurrence when management’s base case forecast does not pass the cash flow test.  The underpinnings of the entire reorganization plan are based on this forecast, so it is almost certain that the cash flow projections have been produced with an eye toward meeting this requirement.  Viability is proven not only by passing the cash flow test on a base case scenario, but also maintaining financial viability under some set of reasonable projections in which the company (or industry, or general economy) underperforms the base level of expectations.  This “stress-testing” of the company’s financial projection is a critical component of a meaningful cash flow test.“Fresh Start” AccountingCompanies emerging from Chapter 11 bankruptcy are required to re-state their balance sheets to conform to the reorganization value and plan.On the left side of the balance sheet, emerging companies need to allocate the reorganization value to the various tangible and identifiable intangible assets the post-bankruptcy company owns. To the extent the reorganization value exceeds the sum of the fair value of individual identifiable assets, the balance is recorded as goodwill.On the right side of the balance sheet, the claims of creditors are re-stated to conform to the terms of the reorganization plan. Implementing “fresh start” accounting requires valuation expertise to develop reasonably accurate fair value measurements. ConclusionAlthough the Chapter 11 process can seem burdensome, a rigorous assessment of cash flows, and a company’s capital structure can help the company as it develops a plan for years of future success.  We hope that this explanation of the key valuation-related steps of a Chapter 11 restructuring helps managers realize this potential.However, we also understand that executives of oil & gas companies going through a Chapter 11 restructuring process need to juggle an extraordinary set of additional responsibilities—evaluating alternate strategies, implementing new and difficult business plans, and negotiating with various stakeholders.  Given executives’ multitude of other responsibilities, they often decide that it is best to seek help from outside, third party specialists. Valuation specialists can relieve some of the burden from executives by developing the valuation and financial analysis necessary to satisfy the requirements for a reorganization plan to be confirmed by a bankruptcy court.  Specialists can also provide useful advice and perspective during the negotiation of the reorganization plan to help the company emerge with the best chance of success.With years of experience in both oil & gas and in advising companies through the bankruptcy process, Mercer Capital’s professionals are well-positioned to help in both of these roles.  For a confidential conversation about your company’s current financial position and how we might assist in your bankruptcy-related analyses, please contact a Mercer Capital professional.1 Accounting Standards Codification Topic 852, Reorganizations (“ASC 852”). ASC 852-05-8.2 ASC 852-10-20.
Current Environment Challenges America’s Most Prolific Basin
Current Environment Challenges America’s Most Prolific Basin

Permian Basin Update

The economics of oil and gas production vary by region. Mercer Capital focuses on trends in the Eagle Ford, Permian, Bakken, and Marcellus and Utica plays. The cost of producing oil and gas depends on the geological makeup of the reserve, depth of reserve, and cost to transport the raw crude to market. We can observe different costs in different regions depending on these factors. In this post, we take a closer look at the Permian Basin.Production and Activity LevelsPermian production grew approximately 3% year-over-year through June, in line with Appalachia and avoiding the declines observed in the Bakken and Eagle Ford (down 28% and 10%, respectively).  The Permian is still one of the focus areas of supermajors Exxon and Chevron, and also relatively well-capitalized independents such as Concho, Diamondback, Parsley, and Pioneer.  As such, it has been more resilient than other oil-focused basins and experts expect to see production growth. Rig count in the Permian at June 26th stood at 131, down 70% from the prior year.  While significant, this decline is less severe than reductions seen in the Bakken and Eagle Ford of 82% and 85%, respectively.  Appalachia rig counts declined by a more modest 52%, though the gas-focused basin had fewer rigs to drop and faced a more benign commodity price environment.  With companies beginning to bring production back online, this may be the nadir, though significantly lower E&P capex budgets will likely keep a lid on rig counts in the near term. The Permian is also seeing gains in new-well production per rig.  While this metric doesn’t cover the full life cycle of a well, it is a signal of the increasing efficiency of operators in the area.  New-well production per rig in the Permian increased 2% on a year-over-year basis through June, compared to changes of -42%, 12%, and 6% in the Bakken, Eagle Ford, and Appalachia, respectively.  (Note that the decline in Bakken production is an artifact of the significant production curtailments in the basin.  The EIA forecasts a normalization in July.) Commodity Prices Rebound After Unprecedented DeclineWTI front-month futures prices increased over 90% during the second quarter of 2020, though it was a bumpy road getting there.  Prices at the beginning of the quarter were ~$20/bbl, still depressed in the wake of the Saudi/Russian price war, and demand destruction caused by COVID-19.  In early April, prices generally increased, approaching nearly $30/bbl by the middle of the month.  However, on April 20, WTI futures prices collapsed, falling below $0 to settle at negative $37/bbl.  While there are numerous technical reasons for the collapse, there was significant concern regarding crude storage capacity as production had not declined in tandem with demand. However, crude futures prices generally increased thereafter, driven by supply cuts from OPEC+, curtailments by US producers, and a recovery in demand.  WTI front-month futures prices ended the quarter at $39.34/bbl. Financial PerformanceAll Permian E&P operators analyzed have had year-over-year stock price declines.  Pioneer and Parsley were the best performers in the Permian group, only down 37% and 44%, respectively.  Concho also outperformed the broader E&P index (XOP), down 50% compared to the XOP’s 52% decline. Centennial was the worst performer in the group, down 88% year-over-year, though it has rebounded significantly since its lows in early April. While the Permian has been less affected by the most recent batch of E&P bankruptcies, it has not been immune.  At the end of June, two Permian operators filed for bankruptcy.  Sable Permian filed for bankruptcy on June 25 with approximately $1.3 billion of interest-bearing debt.  The company previously underwent debt restructurings in 2017 and 2019.  On June 29, Lilis Energy filed for Chapter 11.  The company entered proceedings with a Restructuring Support Agreement with certain investors.  Under the terms of the agreement, common equity holders will not receive any consideration in the restructured entity. Though commodity prices have recovered from recent lows, they remain below levels at which certain operators can cover operating expenses on existing wells (and well below prices required to drill new wells), according to a Dallas Fed survey.  As such, more Permian bankruptcies are likely coming. Texas Railroad Commission Decides Against ProrationOn April 14, the Texas Railroad Commission (which, despite its name, regulates oil & gas activities in the state of Texas) held a meeting to discuss prorating production in the state in light of significant demand destruction and concerns regarding oversupply.  Proponents of proportion, led by Scott Sheffield of Pioneer and Matt Gallagher of Parsley, argued that proration was needed to save American jobs and ensure that the energy industry is able to respond once demand returns.  Opponents argue that government mandates were unnecessary and that operators should adjust production in response to market prices.  Some, specifically midstream operators, were concerned that such a mandate would allow E&P companies to eschew contractual commitments.On May 5, two of the three Texas Railroad commissioners voted against proration.ConclusionWhile commodity prices have recovered from recent lows, they remain below levels at which certain E&P companies can operate sustainably.  Two Permian operators have filed for bankruptcy, and more are likely coming.  However, the Permian’s economics remain superior relative to most basins, so it will likely fare better than other areas in this difficult environment.We have assisted many clients with various valuation needs in the upstream oil and gas space in both conventional and unconventional plays in North America, and around the world.  Contact a Mercer Capital professional to discuss your needs in confidence and learn more about how we can help you succeed.
EP Third Quarter 2020 Bakken
E&P Third Quarter 2020

Bakken

Bakken // The third quarter of 2020 experienced a relatively stable price environment compared to the volatile prices seen in the first half of the year.
M&A in the Permian Basin
M&A in the Permian Basin

The Road Ahead: Deal Count and Deal Motives Changing in Challenging Times

Transaction activity in the Permian Basin, and frankly elsewhere as well, is in a unique, and potentially critical situation as companies are facing unpredictable consequences and uncertain futures.A table detailing E&P transaction activity in the Permian over the last twelve months is shown below.  Relative to 2018-2019, deal count decreased by ten and median deal size declined by roughly $60 million year-over-year.  Although this table looks busy with a number of deals, the transactions that occurred before March are most likely not indicative of the road ahead.  Industry participants are much more concerned with deals that have been announced following the dramatic fall in oil price due to COVID-19 and the Russian-Saudi price war, which in this case was determined to be after March 1, 2020.  Looking at the table, only four deals have been announced post-March.  Although the sample is small, they could be the best indication of what is to come, assuming prices remain depressed.Black Stone Minerals Letting Go of Core Permian AcreageIn early June, Black Stone Minerals announced that they were selling a total of $155 million of royalty interest assets in two separate transactions to strengthen their balance sheet and liquidity position.  This appeared to be core acreage in the Permian as the price per flowing barrel was a premium compared to average private transactions of $40,000 per flowing barrel in March and April.  The deal with Pegasus Resources included a 57% undivided interest across parts of the company’s Delaware Basin position and a 32% undivided interest across parts of the company’s Midland Basin position.  Black Stone noted that proceeds from the sale will be used to reduce the balance outstanding on the company’s revolving credit facility.  Black Stone expects its total debt levels to be under $200 million after closing the two transactions.HighPeak Energy & Pure Acquisition Combine Forces After Early ComplicationsPure Acquisition, a blank-check company, announced in early May that it was acquiring Howard county focused HighPeak Energy in a deal worth $845 million.  The original deal, which was terminated due to the crash in oil prices and market uncertainty, included a three-way merger agreement with private-equity-backed Grenadier Energy Partners.  The new business combination between HighPeak Energy and Pure Acquisition will hold a pure-play 51,000-net-acre position in the northern Midland Basin.  Jack Hightower, HighPeak Energy’s Chairman and CEO, commented, “With the decline of energy prices over the last few months, several energy companies are struggling.  However, due to our low drilling and completion costs and our low operating costs, our breakeven prices are much lower than our competitors which enables us to operate profitably at lower price levels.”  Time will tell whether the merger will be able to capitalize.  The transaction is expected to close in the third quarter of 2020, with the combined company trading on the NASDAQ.Ring Energy Taking a Conservative Approach Moving ForwardIn mid-April, Ring Energy agreed to sell its Delaware Basin asset located in Culberson and Reeves Counties, Texas for $31.5 million to an undisclosed buyer.  The asset included a 20,000 net-acre position with current production of 908 boepd (63% oil) at the time of the deal.  Kelly Hoffman, CEO of Ring Energy stated, “The proceeds from this transaction will be used to reduce the current balance on the company’s senior credit facility.  The current environment mandates a cautious, conservative approach going forward, and strengthening our balance sheet is a step in the right direction.”  Ring Energy continues to hold positions in the Permian and Ventral Basin Platform and the Northwest Shelf.  The company recently completed a redetermination of its senior credit facility and expects the transaction to close before the end of July.ConclusionM&A transaction activity in the Permian was skewed, in terms of deal count, as most activity during the last twelve months occurred in the second half of 2019.  Deal motives moving forward will be interesting to monitor as companies may be forced to let go of premium acreage, notably in the Permian Basin, to improve their liquidity positions.  It does not appear to be a seller’s market, as sellers realize the intrinsic value associated with acreage.  If companies have the luxury and are not forced to sell, they seem to be holding on tight searching for the light at the end of the tunnel.
Impairment Testing of Oil & Gas Reserves
Impairment Testing of Oil & Gas Reserves

2020 Global Events Causing Significant Reserve Write-Downs

Oil & gas producers have been forced to take steps to improve their liquidity and make production cuts as prices have fallen to the lowest in decades, primarily due to a price war between Saudi Arabia and Russia as well as a demand slump amid the coronavirus pandemic. Weakness in the equity markets at the end of Q1 and through Q2 in 2020, due to the virus outbreak and substantial decline in commodity prices, have forced public oil & gas companies to take large impairment charges in recent quarterly reports (See table below for a non-exhaustive list of companies that have taken Q1 impairment charges). Even before prices started to collapse, energy companies were cutting outlooks and planning major asset write-downs. Last fall, Schlumberger planned to take a $12.7 billion charge as shale drilling slowed, and Chevron Corp. announced a $10 billion charge related to offshore assets in the Gulf of Mexico and its Appalachia shale assets. This post is aimed at discerning whether an oil & gas company may need to make interim impairment assessments in light of recent major global events and discuss the impairment testing process. The Basics of Impairment TestingIn an earlier post from Mercer Capital titled Goodwill Impairment Testing in Uncertain Times, we cover the basics of impairments, namely when it is appropriate to assess and how to perform tests of impairment with the most notable item for testing relating to goodwill on a company’s balance sheet.In short, under ASC Topic 360 impairment tests for long-lived assets should follow a two-or three-step process:Assess Impairment IndicatorsTest for RecoverabilityMeasure the Impairment In addition to the listed indicators in the accounting guidance, an entity may identify other indicators or “triggering events” that are particular to its business or industry. Once an indicator is identified, a company then tests for recoverability. For oil & gas companies, conditions such as extreme volatility of supply, demand, and sustained periods of low commodity prices brought on by international commodity price wars, adverse global politicking, and the novel coronavirus pandemic can constitute as triggering events to necessitate interim impairment testing.Oil & Gas Reserves – Accounting MethodologyAs opposed to the vast majority of companies outside of the energy sector, oil & gas companies have reserves that are considered long-lived assets for accounting purposes. These reserves are subject to the same impairment testing rules outlined above such that they are required to be tested on a periodic basis or when triggering events occur.Before performing any impairment testing, however, the accounting methods used to account for these oil & gas reserves need to be considered. Under ASC Topic 932, companies can use one of two methods to account for their oil and gas operations: the successful efforts method or the full cost method.Under the successful efforts method, the cost of drilling an oil well cannot be capitalized unless the well is successful. Costs for unsuccessful wells (dry holes) must be charged as an expense against revenue in the matching period.Under the full cost method, companies may capitalize all operating expenses relating to searching for and producing new oil reserves. Costs are then totaled and grouped into cost pools.Impairment Considerations Related to Oil & Gas Reserves In Statement of Financial Accounting Standards No. 19, the FASB requires that oil & gas companies use the successful efforts method. However, the SEC allows companies to use the full cost method. Guidance for impairment testing of reserves under both methods differ but are available to valuation and other practitioners conducting the tests.Successful Efforts MethodOil & gas companies that use the successful efforts method apply the guidance in ASC 932-360-35 and ASC 360-10-35 to account for the impairment of their reserve assets.Timing of Impairment Testing and Impairment IndicatorsUnder the successful efforts method, an oil & gas company generally performs a traditional two-step impairment analysis in accordance with ASC 360 when assessing reserves for indications of impairment. As mentioned above, impairment assessment for reserves may be determined on an annual basis or in the case of a triggering event. To begin, we bifurcate the total reserve assets into two major groups: proved properties and unproved properties.Proved properties in an asset group should be tested for recoverability whenever triggering events or changes in circumstances indicate that the asset group’s carrying amount may not be recoverable. Generally, companies that apply the successful efforts method will perform an annual impairment assessment upon receiving their annual reserve report by preparing a cash flow analysis. Companies can consider proved (P1), probable (P2), and possible (P3) reserves and other resources since these are all included in the value of the assets. Typically, the impairment evaluation of proved properties are performed on a field-by-field basis. Property groupings may differ due to specific circumstances like shared platform infrastructure or other logical reasons.Oil & gas companies should also assess unproved properties periodically to determine whether they have been impaired. The assessment of these properties is based mostly on qualitative factors and are generally assessed on a property-by-property basis.Measurement of Impairment LossA company that applies the successful efforts method then evaluates each asset group for impairment using the two-step approach under ASC Topic 360. In step one, the company will perform a cash flow recoverability test by comparing the summation of an asset group’s undiscounted cash flows with the asset group’s carrying value. If the undiscounted cash flows are less than the asset group's carrying value, the assets are likely impaired. The company would then proceed to step two of the impairment test to compare the asset group’s determined fair value with its carrying amount. An impairment loss would be recorded and measured as the amount by which the asset group’s carrying amount exceeds this determined fair value.Recognition of Impairment LossAn impairment loss for a proved property asset group will reduce only the carrying amounts of the group’s long-lived assets. The loss should be allocated to the long-lived assets of the group on a pro rata basis by using the relative carrying amounts of those assets. However, the loss allocated to an individual long-lived asset of the group should not reduce the asset’s carrying amount to less than its fair value if that fair value is determinable without undue cost and effort.For unproved properties, if the results of the assessment indicate impairment, a loss should be recognized by providing a valuation allowance. Under the successful efforts method and consistent with U.S. GAAP, companies are prohibited from reversing write-downs.In most cases, write-downs occur when oil & gas reserves cannot be extracted economically, such as on properties where drilling has not started or where properties were expected to be developed based on higher oil prices than are currently estimated. As evidenced in recent market events, if oil prices drop too low, the cost to develop the properties may outweigh the net revenues associated with production.Full Cost MethodAlthough less common in U.S financial reporting, companies that use the full-cost method of accounting should apply the guidance in Regulation S-X, Rule 4-10; SAB Topic 12.D; and FRC Section 406.01.c.Timing of Impairment Testing and Impairment IndicatorsUnder the full-cost method, a full-cost ceiling test must be performed on proved properties each reporting period. This “ceiling” is a formulaic limitation on the net book value of capitalized costs prescribed by SEC guidance listed above. This ceiling formula is equal to: + The present value of estimated future net revenues, minus any estimated future expenditures to develop and produce proved reserves, using a discount rate of 10% + The cost of any properties not being amortized + The lower of cost or the estimated fair value of unproved properties that are included in the amortized costs - Any income tax effects associated with differences between the book and tax basis of the excluded properties and the unproven properties being amortized Similar to the successful efforts method, unproved properties must be assessed periodically for inclusion in the full-cost pool, subject to amortization.Measurement and Recognition of Impairment LossIf a full cost pool ceiling is exceeded, the excess amount must be recorded as an expense. If the cost center ceiling later increases, like the successful efforts method, write-downs may not be reversed and the amount written off may not be reinstated.Determination of Fair Value of Oil & Gas ReservesIn the event that a step two analysis needs to be performed, the determination of fair value of the reserve assets can be performed under three approaches:Income approach — Under this approach, valuation techniques are used to convert future cash flows to a single present amount using a discount rate. The measurement is based on the value indicated by current market expectations about those future amounts.Market approach — This approach requires entities to consider prices and other relevant information in market prices and transactions that involve identical or comparable assets or companies. Valuation techniques commonly used under the market approach include the guideline public company and guideline transaction methods.Asset approach —Also known as the cost approach, the value of a business, business ownership interest, or tangible or intangible asset is estimated by determining the sum of total costs required to replace the investment or asset with similar utility. When determining the fair value of oil & gas reserves, companies use various methods and approaches. The vast majority utilize a discounted cash flow (DCF) model to estimate the fair value of reserves. Depending on circumstances other approaches or a mix of approaches may be appropriate for determining fair value of a company’s reserves.Concluding ThoughtsThe oil & gas market and the energy sector as a whole have taken a beating and experienced unprecedented events due to the global impacts from the pandemic and international price wars. While the scale of the full economic effects from these events has yet to be seen, companies are having to question and consider the need for interim impairment testing on reserves.At Mercer Capital, we have experience in implementing both the qualitative and quantitative aspects of interim oil & gas reserve impairment testing. To discuss the implications and timing of triggering events, please contact a professional in Mercer Capital’s Energy Group.
Mercer Capital's Mineral Aggregator Valuation Multiples Analysis
Mercer Capital's Mineral Aggregator Valuation Multiples Analysis

Market Data as of June 2, 2020

Mercer Capital has its finger on the pulse of the minerals market.  An important trend has been the rise of mineral aggregators, which have largely supplanted the trusts as the primary method of publicly traded minerals ownership.Due to a variety of corporate structures (including master limited partnerships and Up-Cs) and complex capital structures (including preferred equity and non-traded common units), mineral aggregator enterprise values pulled from databases are often missing meaningful components of value, leading to skewed valuation multiples.Mercer Capital has thoughtfully analyzed the corporate and capital structures of the publicly traded mineral aggregators to derive meaningful indications of enterprise value.  We have also calculated valuation multiples based on a variety of metrics, including distributions and reserves, as well as earnings and production on both a historical and forward-looking basis. Download our report below.Mineral Aggregator Valuation MultiplesDownload Analysis
Hedging And Bank Retreats Complicate Royalty Aggregators’ Valuation
Hedging And Bank Retreats Complicate Royalty Aggregators’ Valuation
As the clouds begin to clear from the oil patch storm that began three months ago, management, analysts and investors are wondering what is going to happen next. Has the proverbial storm system passed? Is it time to venture out and rebuild, or are we still in the eye of the hurricane, with the back wall on its way? Both are possibilities.As for management teams of royalty aggregators and MLPs, they have mostly given up on gambling on a specific outcome for now. The ones who have initiated new policies are battening down the hatches for another wave to come through. Of the six publicly traded upstream royalty aggregators (VNOM, MNRL, FLMN, KRP, BSM and DMLP) most either suspended guidance or locked down their hedging positions over the last few months so they don’t have to extend their risk profiles. “We really only have today what we have in front of us, which is a strip, and we had to make the tough decision based on the first quarter being one of the biggest cash inflows that we’re going to have over the next five quarters or six quarters, based on where the strip is today,” explained Travis Stice of Viper Energy Partners, LP. This rationale makes sense considering the motives of various stakeholders, particularly bankers.Just about every public aggregator has had their borrowing bases shrunk by their bankers, typically in the range of 20%-25%. This is not a big problem per se for most as they did not have much debt leverage anyway, but it is indicative of the recoil mentality going on. Another indicator of this mentality is the cut in distributions. Kimbell and Viper dropped payout ratios substantially for the short-term. Thus, changing yields significantly. The charts below show this before/after effect of reduced payouts as of last week. [caption id="attachment_32106" align="aligncenter" width="800"]Source: Company Filings, Capital IQ and Mercer Capital Analysis[/caption] Dorchester is the outlier here, but it is paying out 140% of its earnings right now which is unsustainable. It will have to pull back its payout ratio sometime, perhaps sooner rather than later. In fact, one of the most dramatic examples of this pullback was Blackstone Mineral’s recent announcement that they were selling $155 million of choice Permian royalty interests for an average of $86,111 per flowing barrel. This does not appear to be non-core acreage they sold either. In fact, it is a significant premium compared to what they are trading at as of early June and is on par with Viper whose assets are almost entirely Permian based. It’s also a big premium to average private transaction ranges of $40,000 per flowing barrel that was cited in my last column. [caption id="attachment_32109" align="aligncenter" width="374"]Source: Company Filings, Capital IQ and Mercer Capital Analysis[/caption] Considering values have fallen significantly, it might be fertile ground for more acquisitions, but management teams generally don’t seem to think so (Kimbell’s Springbok acquisition did happen in late April as an exception). Sellers’ mindsets are stickier and although prices are low, bid ask spreads remain wide. “From our perspective though, the seller’s expectations remain robust, and rightfully so. This is an asset class that’s highly valuable, where if it’s in the best areas, there will be activity over time. There will be production over them and likely growth over time. And so sellers’ expectations will remain, I think, relatively high and they’ll be patient,” said Daniel Herz of Falcon Minerals. This mentality was consistent across analyst calls. Where does that leave aggregators from a valuation perspective? That is more complicated. The change in prices and the mixed bag of hedgers vs. non-hedgers makes it more challenging. A more specifically constructed discounted cash flow analysis will become as relevant as ever as opposed to benchmarking metrics against guidelines or an index. Why? Hedging is just that – hedging. It boxes in commodity price ranges and limits downside, which banks want. It also limits upside, which shareholders do not want. Several aggregators are hedged in varying degrees through 2020 and into 2021 as well. This makes comparison trickier. Prices have already risen to nearly $40 per barrel in West Texas which is faster than many expected. It may bob up and down this year, but what if the supply shock sends prices on a march upward? It could leave hedged aggregators behind and either undervalued or overvalued. It also de-links several of these entities as a more direct proxy to commodity prices and makes it a more fluid exercise in which to attempt to intrinsically value this aggregator group or any royalty company or asset. Commodity mix matters too. Oil has been on the downside of a roller coaster, while gas has been stuck at the bottom for a while now, but has been more stable, local and predictable. As such, gas is becoming more popular than it was even six months ago. Chatter on analyst calls affirm this. [caption id="attachment_32110" align="aligncenter" width="388"]Source: Company Filings, Capital IQ and Mercer Capital Analysis[/caption] Lastly, shut ins and production drops are potentially looming as well. Most management teams believed it would impact them, but not significantly. In fact, it was portrayed as a good thing because it could preserve value for down the road as opposed to realizing little value today. Better to put food in the refrigerator for later than letting it rot on the table now, was the idea. (Not a bad idea by the way). However, if shut ins become more permanent, there will be no food for later. The proverbial fridge will go unplugged. Valuations appear to have reset a bit, and from an EBITDA perspective, earnings are going to slide, but the market appears to think this will be temporary. How temporary will be the question. The recent OPEC+ meeting was an indicator that prices could rebound sooner rather than later, but that remains to be seen. [caption id="attachment_32109" align="aligncenter" width="331"]Source: Company Filings, Capital IQ and Mercer Capital Analysis[/caption] Whatever may happen going forward, it has been a turbulent ride the past few months. It is also a signal that things are strange when public aggregators stop aggregating and even go so far as to sell premium assets. It likely will not happen for very long, but it has turned some things upside down. That is both a risk and an opportunity. Originally appeared on Forbes.com on June 9, 2020.
Themes from Q1 2020 Earnings Calls (1)
Themes from Q1 2020 Earnings Calls

Part 2: Mineral Aggregators

As discussed in our quarterly overview, the oil & gas industry took arguably its worst beating in history due to Saudi Arabia-Russia price war and demand destruction caused by COVID-19.  Rather than restating the events and underlying economics behind the drastic downturn in the market, it would be more beneficial to read Part One of this series and cut to the chase with Part Two of the Q1 2020 earnings calls, which focuses on mineral aggregators.Theme 1: Dividend Policies Varying Moving ForwardParticipants and investors seemed to question aggregators’ current and future distribution plans, as this asset class is primarily a yield investment vehicle.“The $0.025 dividend payment reflects a payout ratio of 23% of pro forma free cash flow.  It really is simply about getting back to a more stable economic and energy environment.  I would expect that we’ll see our payout ratio return to its traditional level of 90% plus.” – Daniel Herz, President & CEO, Falcon Minerals“We committed to a 100% payout ratio through the first quarter, and we want investors to know that our word is important, and we remain committed to following through and doing what we said we were going to do.” – Robert Roosa, CEO & Director, Brigham Minerals“That resulted in us cutting the distribution to 25% of available cash.  And I think it’s going to be a very fluid process.  I can only really use the baseline of 25% for now.” – Travis Stice, CEO, Viper Energy PartnersTheme 2: Hedging: Defensive Strategies Leading to Limited Upside ExposureAlthough mineral aggregators enjoy certain advantages relative to operators, their performance remains tied to commodity prices.  As a result of the uncertain and volatile pricing environment, there have been difficult decisions made in regard to hedging.  Some aggregators are hedged through 2021, limiting the potential upside of these investments if prices continue to increase.“We currently have a substantial portion of our oil and natural gas production hedged in the form of swaps going out two years with prices for oil averaging in the low $40s and natural gas averaging around $2.49 per MMBTU.” – Robert Ravnaas, CEO & Chairman, Kimbell Royalty Partners“Because of this market uncertainty and our concern that it may persist for some time, we have put in place substantial hedges for 2021 for both oil and has to further our already robust 2020 hedge positions.” – Jeff Wood, President & CFO, Black Stone MineralsTheme 3: Aggregator Advantages Muted for the MomentUnlike traditional royalty trusts, mineral aggregators reap the benefit of reinvesting capital to acquire new acreage.  This advantage, however, has been paused as the M&A market is in a standstill due to the wide bid-ask spread between buyers and sellers.  It will be interesting to monitor the performance of the aggregators closely if they are unable to benefit from their acquisition strategies.“Right now, our acquisition machine is silent for the foreseeable future.  Now, mineral owners tend to be stickier with respect to perception of value, and there’s often less leverage in the mineral space.  So, I think it’s going to be pretty quiet here for the next couple quarters.” – Travis Stice, CEO, Viper Energy Partners“The A&D market, as you might imagine, is pretty slow currently, but we expect it to pick up in the next, let’s call it, 2 to 6 months.  From an M&A perspective, we plan to continue to fund our micro acquisition strategy at current depressed commodity prices and continue to be well positioned as a consolidator in the highly fragmented minerals industry.” – Robert Ravnaas, CEO & Chairman, Kimbell Royalty Partners“There will be production over time and likely growth over time.  And so sellers’ expectations will remain, I think, relatively high and they’ll be patient. – Daniel Herz, President & CEO, Falcon Minerals
Themes from Q1 2020 Earnings Calls
Themes from Q1 2020 Earnings Calls

Part 1: E&P Companies

In the first quarter of 2020, oil benchmarks ended arguably their worst quarter in history with a thud.  The concurrent overlapping impact of (i) discord created by the OPEC / Russian rift and resulting supply surge; and (ii) the drop in demand due to COVID-19 related issues was historic.  Brent crude prices began the quarter around $67 per barrel and dropped to $50 per barrel by early March before plummeting to $19 per barrel by the end of the month. WTI pricing behaved similarly although it continued to trail Brent pricing by a narrowing margin (about $5 per barrel) at the end of the quarter.  For context, WTI recovered to a range of roughly $25 per barrel to $30 per barrel relative to when the earnings calls occurred in late April and early/mid-May.  As of yesterday, WTI closed at $37.29 per barrel.  Natural gas has trended downward but has been more stable in the U.S. as its pricing is generally more tied to region-specific factors.This week, we examine some of the most discussed items and trends from E&P companies’ Q1 earnings calls. We will turn our attention to those in the mineral aggregator space in a subsequent post.E&P CompaniesOperators experienced mixed earnings in the first quarter.  Although operators started the year with a positive outlook, the events that occurred in March quickly forced them to reconsider their forecasts.  Investors and participants were far less concerned with earnings figures for the quarter than future implications of current events.Theme 1: Setting Priorities During Uncertain TimesOperators seemed inclined to comment on their priorities moving forward.  Making cuts to capital expenditures was predicted and unanimous among the group; however, the operators discussed other measures that they are implementing to combat the current depressed environment.“Paying our interest expense, retaining our people and paying our dividend remain our priorities through these uncertain times.” – Travis Stice, CEO, Diamondback Energy“First, optimizing our cash flow by adjusting our spend rate, production and cost structure.  Second, maintaining a strong balance sheet.  Third, continuing to return capital to shareholders through our dividend.  And finally, maintaining flexibility to cut further while also preserving our operational capacity.” – Timothy Leach, Chairman & CEO, Concho Resources“Our capital allocation priorities are balance sheet, dividend and capital spending.” – Scott Sheffield, Chairman & CEO, Pioneer Natural ResourcesTheme 2: Maintaining Bank Relationships in Times of NeedBanks will continue to play a substantial role as many of the operators relied on tapping into their credit lines and/or other debt instruments to satisfy liquidity needs.“Our banks are very strong.  Our credit facility is strong.  We don’t have covenants really in there, debt-to-capital covenants, only one we have, and we’re well south below that and we’re not in any realm of even approaching that.  Our debt would have to go up by $8 billion to hit that covenant level.  So, I told you we’ve got a lot of cushion.” – John Hart, CFO & Treasurer, Continental Resources“As of today, the undrawn capacity on our credit facilities total $6.75 billion.  We believe a strong balance sheet is essential to succeeding in this industry and we are committed to maintain our investment grade credit rating.” – Don Templin, CFO, Marathon Petroleum CorporationTheme 3: Prepared for the Worst While Hoping for the BestMany operators focused on their individual advantages to convey their resilience during the difficult pricing environment.“Diamondback is prepared to operate in a lower oil price environment and our cost structure will prove to be a differentiator through this downturn.  Low interest expense, low leverage, industry leading low cash G&A, a full hedge book, strong midstream contracts and benefit of Viper and Rattler will allow them to operate effectively through these uncertain times.” – Travis Stice, CEO, Diamondback Energy“Just as Pioneer entered this downturn as one of the best positioned companies, we will emerge just as strong.  The key points here, obviously, is maintaining our top-tier balance sheet through capital discipline, combined with significant cost reductions in 2020.” – Scott Sheffield, Chairman & CEO, Pioneer Natural Resources“We still have levers we can pull if conditions deteriorate further, and we will maintain flexibility to make additional cuts to our spending.” – Timothy Leach, Chairman & CEO, Concho ResourcesTheme 4: Providing Flexibility with LiquidityE&P companies are attempting to maximize liquidity to allow financial flexibility.“Just to be on the safe side, we did increase our liquidity position in early April by adding a 364-day credit facility, a little over $900 million that get our liquidity up to $2.4 billion.” – Scott Sheffield, Chairman & CEO, Pioneer Natural Resources“We’ve taken steps to maintain our financial flexibility.  We’ve secured $3.5 billion of additional liquidity, including a new $1 billion 364-day revolver, and issued $2.5 billion of senior notes.” – Mike Hennigan, CEO, Marathon Petroleum Corporation“With our reduction in spending, current hedge protection and suspensions of our buyback program, we expect to maximize liquidity and retain cash to pay down debt.” – Travis Stice, CEO, Diamondback Energy There is no question that E&P companies were forced to react quickly during the first quarter of 2020.  Macroeconomic events mixed with a global pandemic slashed demand and caused prices to plummet.  The operators tried to convey their confidence and resilience with their strategies moving forward.  Time will tell whether they come out of this situation as stronger companies.
Royalties And Minerals: A New Market Is Emerging
Royalties And Minerals: A New Market Is Emerging
The marketplace has delivered some jarring blows over the past few months to players in the mineral and royalty space. Although this asset class enjoys certain benefits relative to oil and gas producers, its value is still connected to commodity prices. The recent swing downward has staggered market participants and quickly changed several assumptions regarding a sense of normalcy. In analyzing the sector, we pulsed EnergyNet, one of the largest private mineral transaction platforms in the market. Chris Atherton, EnergyNet’s CEO, is about as close to the royalty and mineral market as anyone. How close? Consider the following:EnergyNet has closed over 400 royalty, overriding royalty, and/or mineral transactions this year through April 2020.The platform frequently handles transactions with participants ranging from individuals all the way to integrated majors such as Chevron CVX and Shell.Geographically, they handle transactions across the contiguous United States.They regularly broker transactions across the dollar size spectrum in this market, ranging all the way from five figures to eight figures. Therefore, it is reasonable to suggest EnergyNet represents an excellent glimpse into the royalty and mineral market at large (no – I did not get paid to say that). In the course of my correspondence with Chris Atherton, several interesting market movements began to emerge. After the March 7th launching point with the OPEC+ impasse, EnergyNet’s platform has taken several twists and turns. Both demand and supply shocks have squeezed the market and values have plummeted. The timeline below chronicles this: [caption id="attachment_31848" align="alignnone" width="709"]Source: EnergyNet[/caption] ObservationsThe fact that valuations have decreased is not news at this point, but what is interesting is that this environment has changed a lot of things along the way:Buyer Pool – Currently EnergyNet has 33,000 buyers vs. 7,000 sellers on its platform. Buyer registrations have skyrocketed in the past few months. New investors are seeking what they perceive as a potential good deal. At the same time, many of the larger participants on their platform (majors and independent producers) have paused much of their selling activity. Possibilities for this hiatus can vary. Changing economics are certainly a factor, but sellers also may be concerned about entering restructuring negotiations and do not want to be divesting assets in the time leading up to what may eventually be a bankruptcy filing.Liquidity and Valuations – Although typically not falling as far as upstream producers, valuations for minerals and royalties have plummeted. Deals, even in quality basins, are trading for half of what they were a few months ago. Liquidity has been a part of this. As buyers and sellers wallow in uncertainty, more and more deals are either terminating or not happening at all. [caption id="attachment_31849" align="alignnone" width="640"]Source: EnergyNet [/caption] Basin Preferences – During this time, a previously unexpected occurrence has happened: gas assets are considered a more “tradeable” investment. Said Atherton: “With gas in the proverbial doghouse, buyers are becoming more attracted to its relative stability. Sellers have noticed this too and are more reticent to trade. The transaction volume is still thin, but interestingly, the rationale has shifted.” This has led to an uptick in Appalachian and East Texas interest. Colorado has lost favor, as much due to its changing regulatory climate as commodity prices. The Bakken has had decreasing interest as well with its higher breakeven prices and transportation issues. [caption id="attachment_31850" align="alignnone" width="640"]Source: EnergyNet [/caption] Takeaways“We are going to have a different market coming out of this.” says Atherton. What exactly that market will look like is another question. Speaking of questions, what will drilling activity look like going forward? How might the relationship between the mineral owner and operator change? It is possible that litigations between royalty owners and operators will pick up?Arguably, the most pertinent question above all is this: How will horizontal wells respond to being shut-in? This is an experiment that has never been tried before. Nobody knows how the wells may or may not respond when the spigots get re-opened at some future point. This uncertainty is part of why values are so depressed right now. The answer, whenever it comes, could be the lynchpin to what royalty and mineral valuations will look like in the future.Originally appeared on Forbes.com.
2020 Commodity Prices Upend 2019 E&P Bankruptcies
2020 Commodity Prices Upend 2019 E&P Bankruptcies
The recent historic decline in oil prices has strained the balance sheets of E&P companies.  Whiting Petroleum Corporation, the first publicly traded U.S. E&P company to declare bankruptcy in 2020, announced its Chapter 11 reorganization process on April 1.  More are expected to follow.Despite a much more benign commodity price environment of ~$50-$60/bbl in 2019, a number of E&P companies declared bankruptcy last year and have seen their reorganization processes derailed in 2020 as a result of low oil prices.Sanchez Energy DIP Financing ImpairedSanchez Energy filed for bankruptcy in August 2019, citing a misalignment between the company’s capital structure and the “continued low commodity price environment.”  At the time of filing, Sanchez had approximately $2.3 billion of debt outstanding, according to Haynes Boone.As part of the bankruptcy process, Sanchez secured $200 million of debtor-in-possession (DIP) financing.  DIP financing is generally senior to the company’s other indebtedness, and thus usually recovered in full.  However, in light of commodity price declines caused by COVID-19’s energy demand destruction, Sanchez is only worth an estimated $85 million according to the court-approved reorganization plan.  This implies a substantial impairment of the DIP financing (to say nothing of the other $2.3 billion of debt).Despite the approved reorganization plan, the ultimate ownership of the company is still in question.Alta Mesa Sale Terms RevisedAlta Mesa announced its bankruptcy in September, a month after Sanchez, citing a need to “reorganize its capital structure.”  According to Haynes Boone, Alta Mesa’s debt totaled $871 million.Alta Mesa received a $310 million stalking horse bid on December 31 from a joint venture between Mach Resources (an E&P company) and Bayou City Energy (a private equity firm).  The joint venture won the subsequent auction in January 2020, bidding $320 million, but was unable to secure the necessary financing amid the initial stages of the Saudi/Russian price war in March.  The sale ultimately went through, but at a $100 million discount.EP Energy Restructuring Plan ScrappedEP Energy, an Eagle Ford and Permian-focused producer, filed for bankruptcy in October.  The company was spun out from El Paso Corp. during 2012 in a leveraged buyout (LBO) led by Apollo and subsequently taken public in 2014.  The LBO left EP Energy with a massive debt balance, which stood at $7.3 billion per Haynes Boone.EP Energy’s restructuring plan was approved on March 6, the same day Saudi Arabia and Russia failed to come to terms on an OPEC+ supply cut.  It soon fell apart, as Apollo and other financial backers pulled out.The company has submitted a motion requesting an extension, which would give EP Energy until October 31, 2020 to file a revised restructuring plan.Approach Resources Buyer Backs OutApproach Resources was the last U.S. public E&P to file for bankruptcy in 2019, seeking to explore strategic alternatives including “the restructuring of its balance sheet or the sale of its business” as stated in its November press release.  The company received a stalking horse bid of $192.5 million from Alpine Energy Capital in February.  The court approved the sale in early March.  Later in the month, Alpine announced that it was terminating the agreement.  The approach subsequently sought to force Alpine to complete the purchase.The matter has not yet been resolved.ConclusionRecent commodity price volatility has driven certain E&P producers to file for bankruptcy and has prevented several more from emerging.  While prices have bounced back from recent lows, they remain below breakeven costs for many producers.  As such, we expect to see continued bankruptcy filings and protracted restructuring processes.If you want to learn more about the valuation side of the bankruptcy process, and how we at Mercer can use our years of experience in bankruptcy and the oil & gas industry to help you emerge from Chapter 11 well-prepared for future success, contact one of our valuation analysts for a confidential discussion.
Uncharted Valuation Territory: What Is A Barrel Or An Acre Worth Today?
Uncharted Valuation Territory: What Is A Barrel Or An Acre Worth Today?
Even with Saudi estimations of a 20-million-barrel supply cut, times are tumultuous for the oil and gas industry.  News earlier this month was met with no rise in West Texas Intermediate pricing at the time.  It hovered around $20.00 per barrel.  Last week it fell to the seemingly unconscionable negative territory.  It was worse in other places.  In Western Canada heavy select oil was around $4.50 per barrel and dropped to $0 last week.  It went negative as well.That was not a typo.  (The only beacon of “normalcy” was Brent was still trading above $25 per barrel.)World demand for oil has dropped somewhere between 20% and 35% by some estimations, and excess supply has been building for weeks.  Thus, we may not even be at the nadir of the market shock.  When the smoke clears from this explosive market disruption, there will possibly be some major market ripple effects such as swaths of the Canadian oil market (1.5 million barrels per day) and U.S. backyard “stripper” wells (representing 10% of total U.S. production) permanently going offline, representing a material change in U.S. supply going forward.Something must give, and something will.  While global supply and demand imbalance has the industry scrambling in unseen territory, how does this convert to what upstream companies and reserves are worth amid the situation?  Is it a 1:1 price to value change ratio?  Depending on perspective, the answer is both simple and complicated.Not surprisingly, most potential or actual sellers of upstream assets and companies are praying that they don’t have to find out.  Translation: they hope the market will correct itself before they choose (or have) to sell.  The reasons for this are multifold.  The obvious rationale is that the value of today’s production could fetch the lowest relative prices seen in decades.  Secondary rationale is that tomorrow’s production, i.e. reserves, are being hit even harder.  Those reserves represent the optionality, expectations, and hopes of an investor for a brighter market tomorrow.  Therefore, sellers don’t want to give that up, whilst on the other side of the coin, buyers aspire to acquire the potential opportunity.  What is the likely result?  Wide bid-ask spreads and little to modest market activity.  Put another way – the asset and transaction market could go dark until restructuring transactions hit the market.Navigating Today’s Upstream EconomicsThere are still indicators that can shed light on a dark market.  Those include public valuations, reserve metrics, production metrics, and cash flow metrics.   In terms of reserve metrics, value erosion usually starts in the bottom categories of a reserve report and moves upwards.  Possible and probable reserves typically diminish in value first, then up to the proven categories, and finally to producing reserves.  This makes sense because producing reserves are less risky and less expensive to produce, and thus are more value resilient in lower price environments.  Consider the costs to produce an existing barrel of oil.  In West Texas, this averages about $26 per barrel – some can produce cheaper and others more expensively.  This means the average producer is losing $5-6 per barrel today on existing wells.    What’s also notable is that these costs are much lower than they were just a few years ago for U.S. shale producers, but still aren’t low enough.  Compared to the rest of the world, Saudi Arabia and Russia have the lowest production costs (of which we won’t expound on the reasons why here) and thus the rawest economic ability to weather this low-price environment. [caption id="attachment_31065" align="alignnone" width="619"]Source: Dallas Fed Energy Survey, Reuters, Seeking Alpha[/caption] However, when it comes to undeveloped reserves the costs are much higher.  Even in the most efficient areas of Texas, oil prices need to be at least $46 per barrel to profitably drill a new well.  This illustrates why even proven undeveloped (“PUD”) reserves are worth relatively (and often significantly) less than developed reserves.Therefore, upstream producers are de-incentivized to drill new wells, leading to the value of new inventory decreasing at an even proportionally higher rate.  This dynamic has been exacerbated by the market’s focus on cash flows in priority to reserves in recent years.  Investors had already been pulling valuations down as their standard tilted more towards shorter-term returns as opposed to longer-term reserves.  To be sure, producers have reduced capital expenditures by historic amounts in the past 45 days or so.  Extending that perspective, some might think non-producing reserves are worthless.  However, they would be wrong.  There is an optionality value to those future reserves, also known as acreage, that bears out in the marketplace and is evidenced by transaction prices.  Valuations are based on future expectations, and many people believe that prices will not stay low permanently.  Therefore, the market is willing to pay a relative premium to immediate economics to account for potential future upside.  It also shows up in implied public market valuations as well.Ceding Latitude To Public ValuationsImplied valuations of public companies can provide a living proxy for market values, assuming efficient market theory.  There are several metrics that investors and the industry utilize as potential benchmarks including cash flows such as EBITDA and EBITDAX.  However, I note in this instance that the first quarter 2020 earnings have not been released yet, so trailing cash flow metric indications are not concurrent.  Other metrics can be followed more contemporaneously such as enterprise value per flowing barrel of production.  In addition, the drop in equity values push debt ratios higher, thus potentially triggering bank covenants.Predictably, valuations have been in a free fall.  What may be unexpected is how those valuations have changed relative to prices or even other companies that are operating in different basins.  Mercer Capital tracks groups of public oil and gas companies and categorizes them according to focus.  There are integrated global producers, non-integrated global producers, North American focused producers, and even basin focused producers.  Mercer Capital follows several valuation-related data points, but some key ones include enterprise value per flowing barrel which shows a company’s publicly traded enterprise value relative to its daily production.  The table below shows the median results from those groups and from the entire sample.It's notable that general North American and basin-focused companies typically traded at a relative discount to global companies with one key exception – Permian focused companies.  This group, including names such as Concho, Pioneer, and Diamondback, traded at multiples closer to its global counterparts.  It’s also notable that debt ratios for most companies were between 30% - 40%, a reasonable historical range.  Then the chaos hit, and recent valuation metrics look gaunt comparatively.As of the end of the first quarter, while WTI oil prices per barrel dropped from $61 to $21 or a 66% decline, price per flowing barrel fell only 47% in Mercer Capital’s group indicating that enterprise and asset values were more resilient than short term price fluctuations.  This is, in part, a function of the previously mentioned reserve optionality.  However, it’s also notable how much equity was lost and how relative debt ratios skyrocketed.  The Bakken (Continental, Whiting and Oasis Petroleum) group’s debt ratios were the hardest hit, which may be a response to its pre-existing leverage issues relative to other groups.Finding Transactional DirectionAlthough the merger and acquisition market is likely to reveal limited information, it doesn’t mean that there are no transactions.  In fact, just this month there were a few transactions announced that give a glimpse into how valuations are being set from a production and acreage value perspective.  Value per acre is another metric that ranges based on numerous factors.  However, in recent years depending on those factors, many deals traded around $8,000 to $12,000 per acre.  In the Permian Basin, deals often traded above $20,000 per acre.  Below is a sample of transactions in 2019 in the Eagle Ford shale area that illustrate this:In the past few weeks, there have been three transactions announced across the SCOOP-STACK area of Oklahoma, the Permian Basin in West Texas and New Mexico, and the Barnett Shale area in North Texas with some revealing financial disclosures.  Potential motivations vary in these deals ranging from bankruptcy to prior strategy commitments.  They also show why sellers are not incentivized to divest assets right now:Although this is not an apple to apple basin analogy, the contrast is stark.  As can be seen in comparison, acreage values have slunk relatively further down than price per flowing barrel metrics indicating more erosion from the bottom of a company’s reserve report.  There is a clear disconnect between PV-10 figures and the GAAP-driven Standardized Measure figure compared to market values at present.Destination Unknown?So where does this leave us?  Lost?  The market could potentially recover the sooner that economies open again.  Each day that passes without positive indicators, the state of uncertainty continues.  Many small producers can’t hang on much longer.  During the Dallas Fed’s recent survey, nearly 40% of respondents would remain solvent for less than two years if prices stayed at $40 per barrel.  Figuratively, that was a long time ago.Banks may extend credit lifelines since so many producers are in the same boat.  Historically banks have preferred to leave the oil and gas business to their clients, however, this time around may be different as it is reported that major banks are setting up oil companies to operate seized assets.  The question is – how realistic and pragmatic is that option?  Even so, asset valuations may find a bottom near these prices.   Even with today’s bloodbath, the valuation metrics from March 31st appear to be holding.  Upstream prices are holding up much better than forward month oil futures.  One other note – the oil market is not the only energy sector impacted.  Renewable projects have been hammered as well and their economics are not as established as the oil industry.  This could set back oil’s energy competition for some time as well.  We’ll see.Originally appeared on Forbes.com.
Saudi Arabia, Russia, or the United States – Did One of the Players Blink?
Saudi Arabia, Russia, or the United States – Did One of the Players Blink?
It’s been a truly dizzying time in the world of international oil production over the last five weeks.  With so much macroeconomic activity, twists and turns, it’s been easy to fall behind as to “what’s gone on”, and for even those who’ve been paying reasonably good attention, you may not be sure what all has occurred.  What suggestions were made? What deals were cut?  What cooperation was gained?  What threats were made, and who, if anyone, “blinked”?  To some extent, we may never know the answers to all those questions.How We Got HereSo, what occurred in the last few months that got us to this very dynamic point in time?  To summarize:January-February 2020 – The coronavirus “goes” pandemic, spreading throughout the world.  While the full extent of damage from the pandemic remains unknown, it’s expected that at least 2 million people will contract the virus, the death toll will easily surpass 120,000 and the economic damage will be of a magnitude that hasn’t been seen in several generations.  Due to the need for quarantines, travel restrictions, forced business shutdowns and stay-at-home orders to limit the spread and speed of the spread, oil demand plunged and oil prices sagged.March 6, 2020 – The three-year OPEC+ (OPEC represented by Saudi Arabia and “+” effectively meaning Russia) production/price cooperation pact, set to expire on March 31, fell apart when Moscow refused to support Riyadh’s demand for additional production cuts aimed to offset the reduced demand for oil resulting from the coronavirus pandemic.March 8, 2020 – So what do two strong-willed centrally-run countries do when their oil production control negotiations (for the purpose of supporting oil prices, on which both countries rely) break-down?  Keep negotiating?  Give-in a little for their mutual good?  No.  Instead they purposefully shove their thumb into the other party’s eye by boosting production?  Make sense?  Not really.  Unless there are ulterior motives in-play such as, curbing the U.S. shale revolution that buoyed the U.S. to energy/oil independence and the top spot in world oil production.  Not a certain motivation, but a potential motivation that has a lot of people talking about the possibility. Late March 2020 – At this point, Covid-19 has significantly reduced oil demand.  In the meantime, the Saudis and the Russians have boosted oil production and oil prices have tanked.  The U.S.’s shale producers are in free fall with bankruptcies staring them in the face.  U.S. energy independence and oil production leadership are in the crosshairs and the Saudis and Russians are showing no signs of any rational behavior on energy production.  Here’s where the geopolitical, oil-production-tied-relationships game starts to get “interesting”. What’s a Newly Leading Oil Producer With a Threatened Leading Position to Do?It’s at this point that all sorts of possible actions on the part of the U.S. begin to be discussed.  Various suggested actions include:Lure Saudi Arabia away from OPEC and into a production-setting relationship with the U.S. – This one was simply a bit hard to imagine having much of a chance at all.  First, the U.S. has always been very critical of production controlling cartels, and production setting with the Saudis would be the exact opposite of our long-held free-market values.  Second, U.S. anti-trust laws simply wouldn’t allow the U.S. government to engage in limiting production, or oil companies to join together for the purpose of controlling oil production.That being said, the Wall Street Journal reported in late March that officials at the Energy Department were seeking to convince the Trump administration to push for Saudi Arabia to quit OPEC and work with the U.S. to stabilize oil prices.  At the same time, Hart Energy was reporting that Energy Secretary Dan Brouillette had indicated that he didn’t know if a U.S.-Saudi oil alliance was going to be presented as a path forward in any formal way as a part of the public policy process, and that no decisions regarding any such alliance had been made.  However, it was also reported that the Trump administration would soon send a special energy representative from the Energy Department, to Saudi Arabia, in order to improve talks between the two countries.  Brouillette also indicated that the Trump administration would at some point engage in some sort of diplomatic effort with Saudi Arabia and Russia on oil production levels and that he would work with Secretary of State Mike Pompeo and other officials on that effort.  This all left the likelihood U.S.-Saudi cooperation open to individual interpretation.U.S. Production Limits Via the Texas Railroad CommissionAlthough the U.S. government may be prohibited from entering into oil production agreements by anti-trust laws, that’s not the case for individual states.  In late March, reports began to surface of the Texas Railroad Commission having been approached by two major Texas oil producers with the idea of negotiating for production limits with OPEC.  The Texas Railroad Commission?  Despite the Commission’s name, it long ago ceased any regulation pertaining to the railroads, however, its regulation of Texas oil production (control granted to it back in 1919) continues to this day.  Although the Commission has long had a reputation for markedly lenient regulation of production levels, the current crisis has powerful voices calling for the Commission to consider working with OPEC to reduce production levels in order to save the U.S. oil industry from the devastating impact of sub-$25/barrel oil prices.While this may pose a “workable” process, it comes with multiple layers of required cooperation and agreements.  Does the Commission address OPEC directly, or through the Trump administration?  OPEC itself requires member cooperation, and the Commission would need the cooperation of other U.S. oil producing states.  After all, if the Commission limited production in Texas, but such limits simply triggered higher output in other U.S. states, the effort would be for naught.  President of the Texas Oil & Gas Association (TXOGA), Todd Staples, commented on that very matter indicating that if Texas oil and gas operators cut back production in isolation, that reduced production would likely be filled by operators producing in other states.Even if the Commission’s involvement gained the necessary cooperation from the Trump Administration, OPEC and other states, the idea faces headwinds both from a purely practical standpoint and from those that simply don’t want the Commission involved in the production quotas.  Some additional items on the practical side of things:Wayne Christian, the Commission’s Chairman, noted that the Commission hasn’t imposed such limits in more than 40 years, the Commission doesn’t have staff with any experience in implementing production limits, the Commission would have to track production across thousands of independent producers, and the Commission’s technological capabilities for handling such a process are quite limited.The Commission’s next meeting was, at that time, weeks away on April 21st, meaning that no action in pursuit of limiting production levels would occur for some time.Other high oil producing states, unlike Texas, don’t have similar regulatory bodies to the Texas Railroad Commission. Without such regulatory bodies, those states may not have the ability to effectively limit in-state oil production. Even if these practical barriers could be overcome, there remain powerful voices that are opposed to any moves that go beyond market forces.  Mike Sommers, the CEO of the American Petroleum Institute, has pushed back against proposals that would involve U.S. officials negotiating a joint production cut with OPEC and Russia.  Sommers noted that the U.S. has always supported the market as the determinant of oil prices, and that during times of crisis, those principles shouldn’t be abandoned.  Sommers was particularly opposed to the proposal from a Texas Railroad Commission commissioner, that would regulate oil production within Texas.  Commissioner Sommers further indicated that any such proposal would be damaging to our posture in the world, and that imposing a production quota on Texas produced oil would penalize the most efficient producers while supporting less efficient companies.  Frank Macchiarola, Senior Vice President of Policy, Economics and Regulatory Affairs at the American Petroleum Institute echoed Sommers sentiments indicating that the Institute's position is very simple– quotas are bad.  He added that quotas have been proven to be ineffective and harmful, and that there’s no reason at this time to be imitating OPEC. However, Texas Railroad Commission commissioner Ryan Sitton noted that he’d already spoken with OPEC Secretary-General Mohammad Barkindo regarding an international agreement that would ensure economic stability as the world recovers from the coronavirus outbreak. Sitton stated that Barkindo had invited the commissioner to OPEC’s meeting in June to further discuss the matter.  Commissioner Sitton further noted that international cooperation was absolutely necessary if Texas were to decide to limit production.  He commented that if Texas limited production as part of an international agreement to balance the markets, he thought the odds of success would be very good.  However, he further noted that if reductions were only implemented by Texas, without collaboration with others, the odds of success were near zero.Forget the “Carrot”, Use the StickOf course, there’s always those in favor of the straight-forward approach to motivating others to a preferred course of action through of the “stick”, rather than the “carrot”.  Especially those that view the Saudi-Russian production spikes as an overt attempt to damage the U.S. shale oil industry.  Senators, including Lisa Murkowski of Alaska and John Hoeven of North Dakota, noted that the American people are not without recourse in responding to the Saudi-Russian actions.  They’ve noted that tariffs and other trade restrictions, investigations, safeguard actions, sanctions, and much else are within the arsenal of potential responses.  Another similarly minded suggestion is to remove U.S. armed forces from the Saudi kingdom.Others, such as oil industry analyst Ellen Wald indicate that the best option for U.S. in this situation is for the Trump administration to pursue diplomatic efforts to settle things down.  Wald noted that sanctions and embargoes aren’t realistic and will having a negative impact for the United States.  Sitton seemed to concur with Wald’s position indicating that a diplomatic solution and planned production cuts would be better for everyone.  He added that although the Trump administration could embargo Russian and Saudi oil as a form of punishment, his hope was that we don’t end-up going there.Interestingly, suggested use of these more “stick” type actions have not been coming from the Trump administration.  Instead, President Trump has remained more measured in his comments, only noting that if the Saudis and Russians didn’t resolve the matter on their own in short-order, that he would get involved at the appropriate time.The Art of the DealPresident Trump, ever the deal-maker, may be looking to a solution that avoids violation of the U.S. anti-trust laws, sidesteps brokering a deal on behalf of the Texas Railroad Commission and doesn’t include the actual application of any “stick” – although maybe using the threat of the “stick.”  Within the last week, President Trump tweeted that he expected Russia and Saudi Arabia to agree to cut production by millions of barrels a day.  Although the Kremlin soon thereafter denied any talks with the Saudis, officials from the kingdom then noted that they would consider significant production cuts as long as other members in the G-20 group of nations were willing to join the effort.  On April 9, OPEC and Russia announced plans to reduce their oil production by more than 20%, albeit also indicating that they expect the U.S. and other top producers to join the effort to prop-up prices.  U.S. officials noted that while they had not committed to any specific cuts in production, expectations were that U.S. output would fall substantially over the next two years, sounding ever so much like the U.S. is on-board with participating in the reductions, albeit without crossing the line into anti-trust law triggering commitments.  However, one sticking point to the agreement was Mexico, who on April 10 balked at the plan.  Mexican President Lopez Obrador refused to sign-off on the agreement as it would necessitate putting his plans for Pemex’s revival on hold.  That resulted in Obrador getting a call from President Trump from which the U.S. seemed to be offering to take part of Mexico’s required production cut with some sort of undefined “repayment” to occur at a later date.   Ultimately, a deal was reached, with OPEC+ nations agreeing to reduce output by 9.7 million barrels per day, representing approximately 10% of global demand before the coronavirus pandemic.  However, with demand down an estimated 35%, the cut does not fully balance supply and demand.  Oil prices were largely unchanged on the news of the agreement.Conclusion, or Lack ThereofAs we indicated, it’s been a truly dizzying time in the rough-n-tumble world of oil production.  Like they say, if you miss a day, you miss a lot.  For now, it at least appears that someone may have just blinked.  The Trump administration seems to be on the verge of a truly historic deal to cut worldwide oil production and bring oil prices up to a modestly workable level.  And that with the U.S. not committing to forcing domestic producers to cut production levels but indicating that U.S. production would “naturally” decline without the government’s intervention.  That coupled with a potential side-deal with Mexico to “cover” part of the production decrease that was being sought from that country, but that Mexico is unwilling to shoulder on its own.  Will it work?  Will the deal be accomplished?Although an agreement was reached to reduce oil production in light of demand destruction caused by the coronavirus pandemic, oil markets appear to remain oversupplied.  Will OPEC+ and other nations agree to another deal to further reduce production?  Will U.S. production decline faster than anticipated due to low oil prices?  Will the Texas Railroad Commission implement proration orders for Texas producers?  All we can say is, stay tuned – and expect the unexpected.
1st Quarter 2020 Oil & Gas Industry Overview
1st Quarter 2020 Oil & Gas Industry Overview
In the first quarter of 2020 oil benchmarks ended arguably their worst quarter in history with a thud.  The concurrent overlapping impact of (i) discord created by the OPEC / Russian rift and resulting supply surge; and (ii) the drop in demand due to COVID-19 related issues was historic.  Brent crude prices began the quarter around $67 per barrel and dropped to $50 per barrel by early March before plummeting to $19 per barrel by the end of March. WTI pricing behaved similarly although it continues to trail Brent pricing by a narrowing margin (about $5 per barrel) at the end of the quarter. In some areas of the Permian, local spot prices were as low as $7 per barrel towards the end of March.  Natural gas, however, has trended downward, but has been more stable in the U.S. as its pricing has become increasingly more regionally tied and relatively less dependent on world oil price drivers. We will examine the macroeconomic factors that have affected prices in this first quarter.Global Economics: OPEC+ Production Growth Collides With Covid-19 Demand DestructionOn March 5th OPEC and its allies (often referred to as OPEC+) held a meeting in Vienna.  The result of that meeting was no agreement on additional production cuts beyond the end of March 2020.  This was unexpected and immediately pushed prices downward about 10%.  In the meantime, the COVID-19 outbreak has continued to escalate.  Worldwide measures have been put in place such as quarantines, shut-ins, social distancing and other actions.  This has slowed much economic activity to a crawl and, in a matter of weeks, has led to worldwide demand destruction for oil leading to the collapse of oil prices.  Impacts and ripple effects abound, however many of them have yet to be easily observed.  This development has upended nearly all prior market estimations from organizations such as the IEA, EIA, research institutions, and investment banks as to demand expectations.  As of the end of Q1, worldwide consumption decline in 2020 is now very likely.  New and revised estimations were still being developed as this has taken the market by surprise.Logistical Consequences: Physical Markets and Force MajeureOne of the clear indicators that this situation is not simply a supply glut is that refinery margins and oil prices declined simultaneously.  A dynamic such as this demonstrates demand decline.  Another factor to consider is since COVID-19 originated in China, and China is a demand marker for oil and refined products, how was demand impacted there?  In February, Chinese oil demand dropped by about 3 million barrels per day out of about 13 million barrels per day – a 20% drop.This turn of events leads to some potential temporary logistical issues such as tanker demand and ultimately shut-ins if the price doesn’t move upwards soon.  Storage capacity is very limited in most exporting nations, perhaps two to three months of storage ability at this pace, so there are not many places the excess supply can go.  Therefore, producers may have to consider and analyze whether the cost to shut down is less than the cost to produce.  Canadian oilsands may be one of the first to start this potential trend.  However, even the lowest cost producer, Saudi Arabia, was struggling to find buyers for its excess supply by the end of March.  This excess supply battle between Russian and Saudi Arabia will play out prominently in Europe, where Russia could possibly lose hundreds of thousands of barrels a day of production.Additionally, back in January, the International Maritime Organization (IMO) began enacting the Annex VI of the International Convention for the Prevention of Pollution from Ships (MARPOL Convention), which lowers the maximum sulfur content of marine fuel oil used in ocean-going vessels from 3.5% to 0.5%.  The implementation of MARPOL will see the marine fuels landscape change significantly as over 95% of the current market will be displaced.  This disruption was already happening beforehand, impacting tanker supply and market share for liquids.On the gas front, LNG import deliveries have been suffering from oversupply and a warm winter. There is no “gas-OPEC” to proffer a supply agreement either.  China’s CNOOC has declared force majeure to turn away LNG shipments, even though China reached an accord with the U.S. to reduce tariffs on LNG imported from the U.S.U.S. Production Headed Towards DeclineIn September 2019, the U.S. became a net petroleum exporter, marking the first net export month ever since monthly records began in 1973.  This may change soon.  Capital expenditures for exploration and production companies immediately fell hard.  Rystad expects this to drop by as much as $100 billion worldwide, the most in at least 13 years.  With the steep decline curves of existing U.S. shale wells, production should drop in a matter of months.In addition to the investment decline, another historic thing happened in March.  The Texas Railroad Commission began engaging with Russian Energy Minister, Alexander Novak about trimming oil output.  This kind of thing hasn’t happened in Texas or the U.S. since the 1970’s.  However, this is necessary for the U.S. Production costs for oil in the U.S., particularly shale oil, are higher than either Russia or Saudi Arabia.  The upstream industry’s existing well base in the U.S. are underwater at low 20’s per barrel pricing.  That was happening at the end of March.Sources: Dallas Fed Energy Survey, Reuters, Seeking Alpha However, even though Russia and Saudi Arabia can operate existing wells in this environment, it does not mean that this is sustainable for very long.  No one knows how long this price war will last.  That said, even a few months of this pricing environment could create chaos for the U.S. energy sector.  It had already severely impacted stock prices and demonstrated even day to day volatility in public markets.The CARES ActIn March, the President indicated that the U.S. government may become a material buyer for about 30 million barrels of U.S. produced oil in order to fill the strategic petroleum reserve.  However, the funding was not authorized by congress in the CARES Act. Congressional Republicans pushed for it, but Democrats did not want to include a “bailout for big oil.” This could hasten bankruptcy acceleration for leveraged energy companies, however since this is a global event and potentially temporary, banks may table defaults and foreclosures and instead better collateralize their exposures and add more commodity price hedges according to an analyst call by UBS.Interest RatesThe U.S. Federal Reserve cut interest rates twice in the month of March. On March 3, the Fed made an emergency decision to cut interest rates by 0.5% in response to the foreseeable economic slowdown due to the spread of the coronavirus. This cut was anticipated and largely shrugged off by the markets as interest rates continued their precipitous decline.Benchmark rates were again cut on March 15 by a full percent to near zero. The central bank also stated that it would increase bond holdings by $700 billion on the same day. These rate cuts however failed to tame oil and gas markets as Brent fell by 10% and U.S. crude fell below $30. Lower interest rates and new bond repurchasing programs are ineffective in a weak demand environment, and prices continued to plummet through the remainder of the month.ConclusionThe shockwave effects of these events have likely surprised even Russia and Saudi Arabia.  However, even though these countries have more ability to weather low prices (see chart above), it is not in their best interest to do so.  On April 2, the POTUS tweeted optimism about a 10-million-barrel production cut.  This was only speculation, but markets reacted quickly and positively.  Middle East, U.S. and Russian tensions will be a highlight going into the next OPEC+ meeting, which as of today has been delayed.  Increased disruption could significantly affect global oil demand and price and lead to a flood of bankruptcies.  In the meantime, prior expectations of U.S. production growth and exports have been tabled.  The situation is dynamic, and much could change in the days and weeks to come.  Stay tuned.At Mercer Capital, we stay current with our analysis of the energy industry both on a region-by-region basis within the U.S. as well as around the globe. This is crucial in a global commodity environment where supply, demand, and geopolitical factors have varying impacts on prices. We have assisted clients with diverse valuation needs in the upstream oil and gas industry in North America and internationally. Contact a Mercer Capital professional to discuss your needs in confidence.
EP Second Quarter 2020 Permian Basin
E&P Second Quarter 2020

Permian Basin

Permian Basin // WTI front-month futures prices increased over 90% during the second quarter of 2020, though it was a bumpy road getting there.
Eagle Ford Update
Eagle Ford Update
Production and Activity LevelsEagle Ford production grew approximately 2% year-over-year through March, lagging behind the Permian (18%), Bakken (6%) and Appalachia (5%).  This is driven, in part, by the maturity of the Eagle Ford play relative to other areas, as well as the Eagle Ford’s relatively high proportion of gas production. The rig count in the Eagle Ford at March 20th stood at 67, down 18% from the prior year.  This decline is more severe than reductions seen in the Bakken and Permian, though better than Appalachia and the overall US rig count.  The Eagle Ford’s rig count has also seen a strong bounce back from November’s lows.  However, rig counts are a lagging indicator, so may fall further in light of recent commodity price declines. The Eagle Ford is also seeing gains in new-well production per rig.  While this metric doesn’t cover the full life cycle of a well, it is a signal of the increasing efficiency of operators in the area.  New-well production per rig in the Eagle Ford increased 8% on a year-over-year basis through March, compared to increases of 15%, 13%, and -18% in the Bakken, Permian, and Appalachia, respectively. Commodity Prices Fall Amid Coronavirus Outbreak and Russian / Saudi Price WarAfter hitting recent highs in early January, oil prices generally declined in January and February as the spread of the coronavirus raised investor concerns regarding oil demand due to potential travel restrictions and declining economic activity.  The decline accelerated on March 6, as Saudi and Russia could not come to an agreement regarding production cuts in light of declining demand, sending WTI futures down 10% to $41.28.  The feud escalated over the weekend as Saudi Arabia slashed its official crude oil selling prices and indicated its intent to ramp up production.  WTI futures fell an additional 25% the following Monday, March 9. Since then, prices continued to decline, with WTI front month futures settlement prices hitting $20.83 on March 18.  Prices have rebounded somewhat from this level but remain extremely volatile. Financial PerformanceAll Eagle Ford E&P operators analyzed have had year-over-year stock price declines.  EOG and Magnolia outperformed the broader E&P universe (XOP), though Penn Virginia and Silverbow are both down more than 90%. Despite this financial performance, no Eagle Ford operators have filed for bankruptcy in the immediate wake of the price downturn.  However, the commodity price environment has impacted the restructuring processes for Eagle Ford operators that entered bankruptcy in 2019.  According to bankruptcy proceedings, Sanchez Energy may not be able to repay its debtor-in-possession (DIP) loan, which would result in no recovery for any legacy creditors.  EP Energy announced in early March that its restructuring plan had been approved by the bankruptcy court.  However, the deal was called off later in the month as lenders for the company’s exit financing pulled their support. InfrastructureOne of the Eagle Ford’s key advantages is its proximity to Gulf Coast refineries and export infrastructure.  However, that benefit is eroding as demand for refined products is tanking (though storage costs are surging) and some importers are seeking to invoke force majeure clauses to reject LNG shipments.This also comes at a time when new pipelines are coming into service to carry Permian production to the Gulf Coast.  The EPIC crude pipeline entered service in February, carrying oil volumes from Orla, Texas, to Corpus Christi.  In September 2019, Kinder Morgan’s Gulf Coast Express was placed in service, transporting natural gas from the Permian to Agua Dulce (just southwest of Corpus Christi).  Early next year, Kinder Morgan’s Permian Highway natural gas pipeline is expected to come online, carrying volumes from the Permian’s Waha hub to the Gulf Coast.  While this infrastructure build-out is helping make energy markets more efficient, it is diminishing the Eagle Ford’s previous marketing advantages.ConclusionCommodity prices are putting immense strain on E&P companies, and there is little relief in sight.  The Eagle Ford’s maturity means that many of the lowest-cost, highest-return locations have already been drilled.  The basin’s marketing advantages are eroding as new pipeline infrastructure transports surging Permian volumes to the Gulf Coast.  With two Eagle Ford operators already in bankruptcy (Sanchez and EP Energy) and unable to exit, we’ll see if anyone joins them over the next twelve months.We have assisted many clients with various valuation needs in the upstream oil and gas space in both conventional and unconventional plays in North America, and around the world.  Contact a Mercer Capital professional to discuss your needs in confidence and learn more about how we can help you succeed.
Eagle Ford M&A
Eagle Ford M&A

Steady Transaction Activity Restrained by Unforeseeable Circumstances

Over the last year, deal activity in the Eagle Ford Shale was relatively steady, picking up towards the end of 2019 and carrying into early 2020.  The recent uncertainty caused by the coronavirus pandemic and the Saudi-Russian oil production level conflict, however, has hindered M&A activity in the region, and frankly everywhere else.  WTI closed below $23/bbl on March 18 with futures prices indicating a depressed price environment persisting for the near term.  Although deal count has decreased as of late, the M&A landscape has the potential to ramp up as some companies will need to sell assets in order to bolster their balance sheets amid the challenging commodity price environment, though wide “bid/ask” spreads between buyers and sellers may be difficult to overcome.Recent Transactions in the Eagle FordA table detailing E&P transaction activity in the Eagle Ford over the last twelve months is shown below.  Relative to 2018, deal count decreased by six transactions and the average deal size declined by roughly $650 million.Ensign Natural Resources Entering, Pioneer Natural Resources ExistingEnsign Natural Resources made its first acquisition as a company in May of 2019, acquiring Eagle Ford acreage from Pioneer Natural Resources.  Brett Pennington, President and CEO of Ensign, explained that the assets included meaningful production and attractive drilling inventory.  Pioneer on the other hand, was ready to become a pure-play Permian operator.  In total, Pioneer has sold approximately $1 billion of assets located outside the Permian Basin.  Pioneer seemed to make it clear that they are throwing all of their eggs in one basket.Callon Petroleum Expanding their FootprintThe biggest deal, in terms of dollars, was Callon Petroleum’s acquisition of Carrizo Oil & Gas.  Callon, a Permian Basin focused company, expanded its position in the Permian and entered the Eagle Ford with the acquired acreage.  The deal terms had to be revised after significant investor pushback.  The amended agreement stated that Callon shareholder would own approximately 58% (up from 54% initially) of the combined company and Carrizo shareholders will own approximately 42% (down from 46% initially).  It should be noted that this deal is not pure Eagle Ford shale.  Carrizo’s asset details included 76,500 acres in the Eagle Ford with roughly 600 undrilled locations and 46,000 acres in the Delaware Basin with about 1,400 undrilled locations.  The combined assets will include 120,000 net acres in the Permian and 80,000 net acres in the Eagle Ford.  The core positions in the Permian and Eagle Ford plan to produce over 100,000 boe/d of pro forma production.  Joe Gatto, president, and CEO of Callon, explained his vision of the larger company, which is to employ a more efficient scaled development model that aims to drive a lower cost of supply.  The multibillion-dollar merger officially closed in December of 2019, and now seems like unfortunate timing due to the current price environment.Repsol S.A. Picking Up Where Equinor Left OffEquinor, a Norway based petroleum refining company, agreed to sell its Eagle Ford assets to Repsol for $325 at the end of 2019.  The agreement gives Repsol, a Spain headquartered oil & gas company, 100% control of the asset while making them the operator.  In 2017, Equinor took an $850 million impairment on the asset due to lower than expected output.  In 2018, Equinor also released that part of their acreage lies on areas with high water stress variables.  Repsol expressed that the acquisition will give their producing assets portfolio a boost while taking advantage of operating synergies and efficiencies.  The acquisition is also aligned with Repsol’s intentions to expand in North America.  The deal plans to increase total production for Repsol in the Eagle Ford to approximately 54,000 boe/d.ConclusionM&A transaction activity in Eagle Ford was fairly consistent throughout 2019, as companies focused to acquire valuable acreage with production potential.  However, no one can ignore the tough current conditions in the energy industry.  Acquisitions that closed at the end of last year seem like the least of worries, as companies are simply trying to avoid bankruptcy.  If conditions allow only the strongest to survive, it could lead to an increase in transaction activity ahead.We have assisted many clients with various valuation needs in the upstream oil and gas industry in North America and around the world.  In addition to our corporate valuation services, Mercer Capital provides investment banking and transaction advisory services to a broad range of public and private companies and financial institutions.  We have relevant experience working with companies in the oil and gas space and can leverage our historical valuation and investment banking experience to help you navigate a critical transaction, providing timely, accurate and reliable results.  Contact a Mercer Capital professional to discuss your needs in confidence.
Energy Valuations: Freefall Into Bankruptcy Or Is This Time Different?
Energy Valuations: Freefall Into Bankruptcy Or Is This Time Different?
This post originally appeared on Forbes.com on Monday, March 9, 2020. Energy valuations are taking an epic pummeling. Considering declining demand amid COVID-19 concerns, the initial fallout to the Saudi-Russia feud was predictable. Within hours, prices had dropped like an anchor (to $33 a barrel as of this morning). Several companies have already announced cutbacks, including Diamondback Energy, as they dropped two additional drilling crews. Parsley Energy made a similar announcement and more are sure to follow. Perhaps even more draconian, SM Energy’s unsecured bonds fell to $0.42 on the dollar and pushed the yield up to around 25%. These bonds traded above $0.90 as recently as February 24th. Trading has been halted this morning amid the panic. Whether the market fallout has hit rock bottom remains to be seen. Regardless of what Russia may have been thinking, the geopolitical climate has put more pressure on U.S. producers and bankers. Operators who were contemplating hedging production at $50 per barrel but waiting to act are kicking themselves today. Energy and related bankruptcies that were estimated to rise in 2020 will likely accelerate a few notches. According to Haynes and Boone’s Oilfield Services Bankruptcy Tracker, there were six (6) new bankruptcies in the oilfield services area in the fourth quarter of 2019. Up until this point in 2020, Pioneer Energy Services is the only major oilfield services company to enter Chapter 11 bankruptcy. That’s almost undoubtedly going to change soon. As upstream companies have vowed to spend within their cash flow, oilfield services will take the biggest brunt of this at first. However, producers with high leverage capital structures could quickly follow. Gas prices have held their ground but they’re so low anyway, it’s hard to know how much lower they could go.Can Banks Hold On?The looming factor for companies is how banks will go about determining borrowing bases this year. It’s a tough position to be in at this point. Bankers at the Hart Energy Capital Conference in Dallas last week did their best to portray patience towards the upstream sector, but were also clear about expectations. Those expectations were that borrowers can meet their obligations, and that borrowing bases will shrink with valuations. One of the speakers, Tom Petrie, expressed concern about $110 billion in debt coming due in the next decade for the energy market.As working interest values for producing interests dive, the expected returns have changed from PV10 to closer to PV20. This has degraded credit quality. The mix of below-investment grade debt has worsened in the past year. In high yield markets, CCC or below is the most common rating according to some recent data.High Yield Debt Rating MixSOURCE: JP MORGAN CORPORATE ENERGY & POWER PRESENTATION Even if bankers lending on reserves maintain their lending ratios, the borrowing bases will shrink accordingly. However, based on recent indications, lending ratios have and will continue to shrink alongside values. Debt-to-EBITDA ratios which used to often float in the 3.5x to 4.5x range are now, not surprisingly, in the 2.5x to 3.5x range. Enterprise values for upstream producers were often between 6.0x to 8.0x EBITDA too. That is in the past.Shifting Credit RatiosSOURCE: OCC GUIDELINES AND AMEGY BANK PRESENTATION Impacts appear bad and immediate. However, this plunge could, ironically, buy the market a little more time. The founder of OnyxPoint Global Management, L.P., Shaia Hosseinzadeh, told Bloomberg just last week that “Things are so bad now, that the banks can kick the can down the road and say ‘there’s no point of rushing everybody into bankruptcy, we’ll wait until October.’ But if it’s business as usual, it’s going to be a horror show.” That may be a prescient thought. Another consideration is that fewer banks are even lending to energy companies anymore. The rise of the environmental, social, and governance (“ESG”) movement, alongside weak returns, have pushed many bankers and other investors out of the space. There isn’t as much capital to go around, not that it’s cheaply available right now anyway.Due to valuations being so low, the recovery for bankers coming out of Chapter 7 situations may be less attractive, especially on the oilfield service side. The market value of intangible assets is so depressed compared to other times in the commodity cycle, that it may not make economic sense to rush into the process for some.Can Values Recover?This prognostication about delayed bank behavior may be a moot point if liquids values can’t recoup over time. This is an undercurrent that has been a factor in keeping values down recently. Electrification trends and the idea that liquids demand will wane have proffered the notion that demand for liquids will be flat to even shrinking in the future, all while supply becomes bountiful. Some project the electrical passenger car trends to reach around 20% by the end of this decade. However, while the short-term appears bleak, many projections about the medium- and longer-term remain more optimistic for upstream producers and servicers. J.P. Morgan Cazenove recently suggested that the oil industry may be under-equipped to meet demand recovery in 2021 and beyond. Another way of putting that is downward pressure on prices could be its own cure in the medium term. Capex budgets have been slashed and continue to be. Over 200 oil drilling rigs (and counting) have been shut down in the past six months. Production will suffer, even with drilling and production efficiencies achieved in recent years. Especially in the U.S. shale markets, declines on existing wells drop off so fast, that their effect on supply will show up sooner rather than later.Producers are hopeful for this. Regardless of the market’s relentless pounding down on reserve values, producers know that, particularly proven reserves are next year’s production. They do not want to sell or unload them for the pennies on the dollar (or less) that implied valuation multiples suggest right now. Intrinsically, they have much more value than inferred by market capitalizations. Management teams believe that enterprise values shouldn’t be trading at a fraction of PV10 values over a long period of time. At a minimum, many producers believe there is an optionality to their future drilling inventory.The question remains, could that happen fast enough to save a bankruptcy slog this year? Only time will tell.
Current Commodity Price Environment May Lead to Next Round of OFS Bankruptcies
Current Commodity Price Environment May Lead to Next Round of OFS Bankruptcies
When I was given the assignment to author this blog post this week, I thought "Could one possibly 'draw' a more timely assignment?" Several weeks ago, Mercer Capital’s Energy Team noted that we should consider the current condition of the oilfield services ("OFS") industry as the topic of one of our upcoming blog posts. The price for West Texas Intermediate ("WTI") had been declining since mid-February, due largely to decreased demand related to the coronavirus, and the Russia-Saudi Arabia failure to reach an agreement on production cuts. Industry participants were growing a least somewhat concerned – and then came the March 6 news that the Russian-Saudi negotiating difficulties might lead to an actual price war – and then came the March 9 actual start of the price war.More Possible OFS Bankruptcies? How Did We Get "Here"?By way of "background," the U.S. OFS industry went through a major round of bankruptcies following the late 2014 drop in oil prices. From the WTI peak in June 2014 at $106/bbl, prices fell to $58/bbl in mid-December 2014 and on to $30/bbl in January 2016. While there were a couple of upward moves in WTI in April and August of 2015, those were short-lived with the "trend" remaining a fairly clear path downward. Data provided in Haynes and Boone, LLP’s Oilfield Services Bankruptcy Tracker report (January 2020) show the annual number of identified OFS bankruptcies rising from 33 in 2015, to 72 in 2016, before easing to 55 in 2017 and 12 in 2018.  Although the WTI price was generally rising during 2016, the price remained below $55/bbl with the impact of the fall from $60+/bbl pricing continuing to ripple through the industry well into 2017. During 2018 – through October – WTI had generally ranged between $61 and $74/bbl.  OFS bankruptcies slowed, but the industry was hardly prospering. Many industry participants were more accurately described as "hanging-on" or "maintaining operations" – hoping for a rise in demand, or a drop in supply, to lift prices and move the industry to more favorable profitability.  However, in November 2018, rising worldwide inventories caused by global supply running well ahead of demand, fueled in part by the continuing growth in U.S. production, resulted in prices dipping to a low point of $43/bbl in December. While pricing improved somewhat in 2019, with WTI generally between $54 and $64/bbl, the loss of $62+/bbl pricing led to an uptick in the number of OFS bankruptcies late in 2019. Source: Haynes and Boone, LLP Recent Events – Industry and Non-IndustryAs we entered 2020, there didn’t seem to be any specific indications of change ahead for oil prices. Few had ever heard the term coronavirus and no one was anticipating a Russian break from OPEC+, or using the term "price war" in regard to the Russian-Saudi failure to reach an agreement on OPEC+ production cuts. The World Health Organization’s China office had begun receiving reports in December of an unknown virus that had led to cases of pneumonia in Wuhan, a major city in eastern China, but the term "outbreak" wasn’t being used.Within eight weeks that had all changed markedly.  By late February we had already gone beyond "outbreak" and had moved on to regularly hearing of the possibility of a pandemic.  People and countries began to react. Multiple countries were significantly limiting travel in order to slow the spread of what we all now know as the novel coronavirus, or Covid-19. Quarantines, self-imposed and government-imposed, were reducing economic production and travel, thereby reducing the level of demand for transportation fuels and fuels as a means of production. In addition, it was becoming clear that the Russian-Saudi disagreement on production cuts was more than a minor matter. The possibility of a split in the Russian-Saudi production alliance to maintain oil prices was being actively discussed as having real potential. Oil prices naturally responded with a downward turn, reaching as low as $45/bbl near the end of February.On Friday, March 6th, it was reported that Moscow had outright refused to reduce its crude production in order to offset the fall in demand related to the coronavirus.  Over the subsequent weekend, rumors swirled as to the magnitude of the impasse. Then, on Monday, March 9th, the worst possible scenario for oil prices became more than a possibility. An actual price war was initiated as both Russia and Saudi Arabia announced production increases.  The anticipated glut immediately pitched prices into a dive with the WTI falling from $41/bbl to $31/bbl by day’s end for a single-day decline of 24%.What to ExpectAs to what we can expect going forward from here, we don't know. The coronavirus, now a pandemic, is obviously spreading. How much and how far are the unknowns, along with how large the impact will be on the U.S. and global economy, and thus, the demand for oil. What is know is that oil demand will be down for a time.  What’s also known is that the outbreak will eventually be contained and the economic impact reversed when things return to "normal."So, What About Oil Supply?Well, we have two very significant oil exporters, formerly allied on oil production levels, now markedly un-allied on oil production. Not only un-allied, but both purposefully increasing production levels, in the face of lower demand, for the purpose of causing economic pain to each other. Unfortunately, that economic pain radiates, by extension, to all oil producers and the businesses that provide equipment and services to the oil producers. What does that mean for U.S. OFS market participants in the near term? Pain. Economic pain. For those that have more economic "wriggle-room," better margins, lower financial leverage, more defendable market position, it won’t be good. For those with less of that economic wriggle-room, it could go well beyond "not good." If the alliance break isn’t remedied fairly quickly and the two belligerents remain belligerent, the production glut could last long enough that a new round of OFS bankruptcies could be in the making.What’s absolutely certain is the uncertainty of it all – and at least some very real OFS industry economic pain if either the virus impact, or possibly the Russian-Saudi dust-up, lasts long enough to keep oil prices down at the new current level, or an even worse scenario, lower than the current level.
Themes from Q4 Earnings Calls
Themes from Q4 Earnings Calls
The energy sector gained slight momentum in the fourth quarter as crude prices steadily increased from $54 per barrel at the beginning of October to $61 at the close of 2019.  The gradual increase in prices was fueled partly by optimistic market expectations in early 2020, and the announcement of the United States and China Phase One trade deal.  In early December, OPEC announced their intent to deepen production cuts through March 2020, applying upward pressure on prices.  However, $60 pricing was short-lived in 2020 as concerns regarding the coronavirus, and its impact on global growth and energy demand, sent WTI prices to the $40s.  In this post, we examine some of the most discussed items and trends from the Q4 earnings calls, specifically E&P companies and those in the mineral aggregator space.E&P CompaniesOperators experienced a positive earnings quarter to close 2019 as many beat expectations on both EPS and revenue.  Cost reductions coupled with an increase in oil production fueled organic growth and allowed E&Ps to produce a level of free cash flow to investors.  Participants on the calls were curious on the outlook for 2020, as topics discussed centered around the coronavirus and ESG (environmental, social, and governance) efforts moving forward.Global Health Affecting Supply and Demand Due to the calls occurring in early 2020, participants seemed inclined to question the outlook of the energy sector in light of recent news regarding the coronavirus.  Operators, Pioneer Natural Resources and Continental Resources commented on the subject.“Obviously, more bullish, especially with U.S. shale essentially slowing its growth significantly going in 2020 once we get through the coronavirus demand issues. I'm more optimistic that we're going to see a much higher price deck over the next five years.” – Scott Sheffield, President and CEO, Pioneer Natural Resources“We see the oil and gas market as fundamentally oversupplied, with demand even further impacted by the coronavirus. By preserving our high-quality asset for a more structurally sound market; we are further enhancing future value for shareholders.” – Harold Hamm, Chairman, Continental Resources The Wall Street Journal recently reported that that the coronavirus has sent natural gas prices to their lowest level in years, as natural gas futures for April delivery closed at $1.756/MMbtu.  Operators remain optimistic, however, that the outlook of the industry remains positive, assuming the virus is contained.ESG Efforts Intensifying“I want to highlight Continental's continued commitment to ESG. As one of the leaders of the horizontal American energy renaissance and a major contributor to U.S. energy independence we are proud to be a part of the approximately 15% rollback in CO2 emissions that has occurred since 2006, thanks to the affordability and availability of clean-burning natural gas and light sweet crude oil produced as a result of horizontal drilling.” – Harold Hamm, Chairman, Continental Resources“Every individual’s compensation is going to be tied to ES&G metrics. Things like water recycle, spill control, total recordable incidence rate, flaring, those are not subject to discretion. Those are quantitative measures that we will incentivize you know a better performance on. That's one thing that we've proven at Diamondback is, what gets rewarded gets done and we intend to do that in our scorecard.” – Travis Stice, CEO, Diamondback Energy“When you look at Slide #23, where the lowest of our peers in emissions intensity where Pioneer on both greenhouse gas intensity and also methane intensity. And what are the major changes we're making in our ESG in regard to compensation, we're increasing that these from 10% to 15% going forward in 2020.” – Scott Sheffield, President and CEO, Pioneer Natural ResourcesMineral AggregatorsAs we discussed in a previous post, mineral aggregators have continued to attract equity capital in the energy space amid depressed investor sentiment regarding the industry as a whole.  While some mineral aggregators centered their attention on acquisitions heading into 2020, others were quiet and reiterated their patience that we covered in our third quarter earnings call post.  In the fourth quarter, Kimbell Royalty Partners declared a record financial performance along with their acquisition of the Springbok assets in the Delaware Basin.  On the other hand, Brigham Minerals emphasized their patient strategy, in search for larger mineral packages to meet their strict investment guidelines.  As the price environment remains uncertain, aggregators are being questioned with their strategy moving forward.Uncertain Price Outlook Leading to Alternative Strategies“That is primarily to give us more exposure to the upside when the gas markets do come back when – if they do, we’re – and also on the downside, adding cash flow to the system in 2021 and 2022 to hedge distributions. So we’re really – we’re playing it in a hedged manner. We’re going to keep a fair amount of exposure to the upside, but we’re also going to put some acreage into play now." – Tom Carter, Chief Executive Officer, Black Stone Minerals“We have received approval to add hedging to our program. We certainly if these prices aren’t going to be hedging oil but some sort of protection on both the spread side or even the gas Waha spread side given the outlook for permitting gases is pretty dire here in 2020. I think we're looking to take that risk out of the Viper story. So we'll be looking at the market and now have approval to hedge from a downside and spread protection perspective.”       –Kaes Van’t Hof, President, Viper Energy Partners“It's opportunities like this that only present themselves every three years to four years in terms of being a little consolidate and take advantage of this type of situation where people are concerned about crude oil prices. So, there is some time that has to go by. But I think our message is, if people are panicky, we can be patient and picky in terms of what we buy.”  – Robert Roosa, Chief Executive Officer, Brigham Minerals“Oil, natural gas, and natural gas liquids revenues in the fourth quarter increased 18% compared to the fourth quarter of last year to $27.2 million. This increase reflects strong performance from acquisitions made in the past 12 months despite the decrease in realized commodity prices. While current pressures persist for many exploration and production companies operating in the U.S., our broad-based, high-quality asset portfolio continues to outperform expectations.” – David Ravnaas, President and Chief Financial Officer, Kimbell Royalty Partners The difficult price environment in the energy industry is leading mineral aggregators to plan for the future.  The topics discussed revolved around strategies, particularly hedging and reinvestment, to capitalize on the unpredictable nature of the industry over the next few years.
Mercer Capital's 2019 Energy Purchase Price Allocation Study
Mercer Capital's 2019 Energy Purchase Price Allocation Study
Have you downloaded Mercer Capital’s 2019 Energy Purchase Price Allocation Study yet?The study provides a detailed analysis and overview of valuation and accounting trends in these subsectors of the energy space.  It enables key users and preparers of financial statements to better understand the asset mix, valuation methods, and useful life trends in the energy space as they pertain to business combinations under ASC 805 and GAAP fair value standards under ASC 820. Download here.
An Overview of Salt Water Disposal
An Overview of Salt Water Disposal

Part 3 | Valuation Considerations

Our previous posts on salt water disposal covered provided an overview of the sector and detailed the economics of the industry.  In this post, we’ll be taking a deeper dive into specific considerations that are critical to understanding the value of salt water disposal companies.What Does the Valuation Process Entail?There are three commonly accepted approaches to value: asset-based, market, and income. In the realm of business valuation, each approach incorporates procedures that may enhance awareness about specific economic attributes that may be relevant to determining the final value.  Ultimately, the concluded valuation will reflect consideration of one or more of these approaches (and perhaps several underlying methods) as being most indicative of value for the subject interest under consideration.The Asset-Based ApproachThe asset-based approach can be applied in different ways, but the general idea is that the equity value of a business is given by subtracting the market value of liabilities from the market value of assets.  However, the value of these assets is not always readily available and must be established through other methods, such as the market approach and the income approach.  These values can also sometimes be proxied by replacement costs or build multiples, though location and intangible items (like permits and contracts) can make the asset-based approach challenging.The Income ApproachThe income approach can be applied in several different ways.  Generally, analysts develop a measure of ongoing earnings or cash flow, then apply a multiple to those earnings based on market risk and returns.  An estimate of ongoing earnings can be capitalized in order to calculate the net present value of an enterprise. The income approach allows for the consideration of characteristics specific to the subject business, such as its level of risk and its growth prospects relative to the market through the use of a capitalization rate.  Stated plainly, there are three factors that impact value in this method: cash flows, growth, and risk. Increasing the first two are accretive to value, while higher risk lowers a company’s value.As discussed in our previous post, cash flows are generally a function of disposal fees and the volume of water processed (with some incremental potential revenue coming from selling oil “skimmed” from the water), less cash operating costs.While some cash flow growth may be driven by operational efficiencies and increasing utilization rates, there is less potential for organic growth relative to other industries given capacity limitations and permitting requirements.  Most growth will come in the form of increasing capacity, which requires capital expenditures.  And as the sector continues to be the recipient of significant public and private capital, the economics of new projects may deteriorate.The riskiness of the cash flows is determined in part by the contract mix and location.  Longer contracts with minimum volume commitments or take-or-pay requirements serve to reduce the risk of the cash flow stream.  Uncontracted volumes or shorter contracts based on acreage dedications serve to increase the risk of the cash flow stream.  Additionally, salt water disposal operators are subject to a host of regulatory and environmental risks, including concerns regarding potential links between SWD wells and seismic activity.The Market ApproachThe market approach utilizes pricing multiples from guideline transaction data or valuation multiples from a group of publicly traded companies to develop an indication of a subject company’s value.  In many ways, this approach goes straight to the heart of value: a company is worth what someone is willing to pay for it.In many industries, there are ample comparable public companies that can be relied on to provide meaningful market-based indications of value.  While there are numerous publicly traded companies with salt water disposal operations, none are “pure play.”In fact, the salt water disposal sector sits at an interesting nexus between three oil & gas verticals: exploration & production, midstream, and oilfield services.  Rattler Midstream went public in 2019 as a carve-out of E&P company Diamondback Energy.  Most of Rattler’s revenues are attributable to salt water disposal operations.  NGL Energy Partners was a traditional midstream company providing pipeline transportation for crude oil, NGLs, and refined products.  However, over the past several years, it has transitioned its focus to water, with water solutions expected to generate over half of the company’s EBITDA going forward.  Select Energy Services is an oilfield services company that provides water-focused services including flowback and well testing, water storage, and fluids handling, but is increasingly investing in pipeline infrastructure and SWD wells.As such, there must be careful consideration of the appropriateness of using public company multiples given operational, size, and geographic differences, among other factors.Fortunately, there have been numerous acquisitions of smaller, private companies in the sector, and valuation multiples can be derived from these transactions.  However, this data is often self-reported, and there can be inconsistencies across transactions for both the implied transaction values (e.g., treatment of earnouts) as well as the earnings measure (e.g., does EBITDA include substantial pro forma adjustments from historical levels?) used to derive multiples.The market-based approach is not a perfect method by any means.  Industry transaction data may not provide for a direct consideration of specific company characteristics.  Clearly, the more comparable the transactions are, the more meaningful the indication of value will be.Synthesis of Valuation ApproachesA proper valuation will factor, to varying degrees, the indications of value developed utilizing the three approaches outlined.  A valuation, however, is much more than the calculations that result in the final answer. It is the underlying analysis of a business and its unique characteristics that provide relevance and credibility to these calculations.  This is why industry “rules-of-thumb” (be they some multiple of revenue or earnings, or other) are dangerous to rely on in any meaningful transaction.  Such “rules-of-thumb” fail to consider the specific characteristics of the business and, as such, often fail to deliver insightful indications of value.  A business owner executing or planning a transition of ownership can enhance confidence in the decisions being made only through reliance on a complete and accurate valuation of the business.ConclusionMercer Capital has long promoted the concept of managing your business as if it were going to market.  In this fashion, you promote the efficiencies, goals, and disciplines that will maximize your value.  Despite attempts to homogenize value through the use of simplistic rules of thumb, our experience is that each valuation is truly unique given the purpose for the valuation and the circumstances of the business.Mercer Capital has experience valuing businesses in the oil and gas industry.  We hope this information, which admittedly only scratches the surface, helps you better shop for business valuation services and understand valuation mechanics.We encourage you to extend your business planning dialogue to include valuation, because sooner or later, a valuation is going to happen.  Proactive planning and valuation services can alleviate the potential for a negative surprise that could complicate an already stressful time in your personal and business life.For more information or to discuss a valuation or transaction issue in confidence, do not hesitate to contact us.
Understanding Oilfield Services Companies & How to Value Them
Understanding Oilfield Services Companies & How to Value Them

New Whitepaper

Understanding the value of an oilfield services (OFS) company is by its very nature a complex matter.  As participants in the greater energy industry, situated between the exploration and production (E&P) companies and midstream companies, the OFS sub-sector is quite broad.  It includes, businesses that have the commonality of their connection to oil and gas prices, but also the significant differences between service providers and equipment manufacturers. It also includes businesses that focus on technology advantages and those that focus on relationships, those that specialize in narrow service/product niches and those that provide a broad range of services/products.  Not to mention the differences in the economics that drive OFS companies with a focus on existing production, as opposed to those that focus on exploration. Also, the differences between those that focus on services that are particular to conventional oil versus unconventional oil, oil versus gas, shale versus tight sands.Having a firm grasp on the many similarities and distinctions is crucial in performing valuations of these businesses.  That understanding plays into the choice of which valuation approaches and methods are to be applied, and which of those approaches and methods are more reliable, or less reliable, depending on the subject company’s positioning and where the industry is in it’s potentially wide ranging cycles.As part of any OFS company appraisal, one must consider expectations for both shorter-term and longer-term operating results.  Industry cyclicality creates challenges in evaluating expectations that can lead to material over-valuations, or under-valuations, unless one has the depth of experience and industry understanding to navigate the many considerations that impact OFS companies.In our latest whitepaper, Understanding Oilfield Services Companies & How to Value Them, we provide invaluable guidance in regard to these aspects of the OFS industry. Click below to download whitepaper.>>Download Whitepaper
Understanding Oilfield Services Companies & How to Value Them
WHITEPAPER | Understanding Oilfield Services Companies & How to Value Them

Understanding the value of an oilfield services (OFS) company is by its very nature a complex matter. The unpredictable cyclicality of the oilfield services industry requires careful consideration of many industry-wide and company-specific factors in developing a reasonable forecast of future operating results. While consideration of such factors should be part of the analysis in the appraisal of businesses in all industries, the impact of these considerations is magnified in highly cyclical industries such as that served by OFS businesses.This whitepaper provides invaluable guidance in regard to these aspects of the OFS industry.
Aggregators Continue to Attract Equity Capital
Aggregators Continue to Attract Equity Capital
In previous posts, we have delineated between royalty trusts and mineral aggregators and discussed the valuation implications of prevailing high dividend yields of public royalty trusts.  Yields remain elevated, and these trusts have declined in their usefulness from a valuation benchmarking perspective. In this post, we focus on mineral aggregators.  We also offer insights on the investment landscape at large and particularly as it relates to the minerals subspace by providing an update on the most recent IPO, Brigham Minerals (MNRL).Market Data for Aggregators and TrustsThe following tables provide some critical market data for valuation purposes. Since our last update, SandRidge Mississippian Trusts I and II (SDT and SDR, respectively) were delisted in mid-November as the stocks fell below $1.00 in May and traded below that mark for six months.  All else equal, public royalty trusts are expected to decline in value as investors get their return almost exclusively from yields because production declines over time. Thus, trusts eventually being delisted is not a surprising outcome due to restrictions on acquiring additional acreage or wells. Given the eponymous operator SandRidge Energy’s struggles, it’s even less surprising these two trusts were delisted.  SandRidge Permian Trust has avoided this fate for the time being, due in part to its attachment to the prolific Permian and sale to Avalon Energy, but the trust has also been put on notice. Unlike public royalty trusts, mineral aggregators are not restricted from acquiring additional interests, which makes them more of a going concern by comparison.  This is among many reasons investors have increasingly turned towards mineral aggregators. Long-time readers of the public mineral interest portion of our blog will note the revamped look at value drivers and key benchmarks for mineral aggregators. Public Markets Unreceptive of Energy SectorThe stock market has been booming over the past decade as the economy has ridden the longest expansion in history.  Investors in the energy sector, however, have not experienced the same joyful ride.  In 1990, energy made up 15% of the S&P 500 sector weightings, but in 2019, that figure was down to 5%.  Ironically, over the same period, the United States’ oil and gas production surpassed all countries and claimed the top of the leaderboard, becoming the world’s largest producer. Depressed commodity prices have also likely aided valuations for companies in other sectors as transportation costs are lower in an increasingly globalized economy with two-day shipping becoming common place.The graph below shows the relationship between the Vanguard Energy ETF, created in 2004, and the SPY Index over a 15-year period.  Slow economic growth coming out of the recession caused Energy to outperform, but commodity price declines in late 2014 began a reversal that has widened since 2017.Energy vs. S&P 500 There are many reasons that this story has unfolded such as diminishing return on investment, fluctuation in commodity prices, and oversupply, but we do not dive into that in this post.  Instead, we want to illustrate the ways in which mineral aggregators have been able to manage some of these issues. Mineral aggregators are constructed to diversify capital among many superior plays and specific operators.  This niche in the energy market allows investors to capitalize on both current yield and capital appreciation with the aggregators’ reinvestment capabilities.  Crucially, royalty holders do not bear operating and drilling costs as these costs are paid by upstream E&P companies.  Brigham Minerals articulates the benefits of the business model as follows: “There are many advantages of the mineral acquisition model, including no development capital expenditures or operating costs, no exposure to fluctuating oilfield service costs and higher margins than E&P operators without associated operational risks.”Mineral aggregators receive a royalty based on revenue and are thus isolated from a number of field-level economic issues. This is not unlike the restaurant industry, where franchisors command a much higher valuation than the operators to whom they franchise.  Declining same-store sales figures in that industry are hurting profitability for operators grappling with the necessity for capital expenditures to fund future growth while those collecting royalties off the top can prosper with their asset-light models.  Sound familiar?Brigham Minerals Seasoned Equity OfferingIn a previous post, we discussed the much-anticipated Brigham Minerals’ IPO in April 2019.  The upsized offering was sparked by higher than expected demand.  Many saw the IPO as an investment opportunity that promoted cash flow, something that operators in the market were not providing.  There was speculation that additional mineral companies would likely IPO over the course of 2019 given the demand for Brigham Minerals, but that turned out not to be the case.  In December of 2019, however, Brigham Minerals announced in an S-1 a seasoned equity offering of 11 million common shares.  The Company offered 6 million new shares of its common stock, and some selling shareholders sold an additional 5 million shares.  Shares were priced at $18.10, likely a psychological threshold, as it was priced just ten cents above the IPO price only eight months prior. Credit Suisse, Goldman Sachs, and RBC Capital Markets acted as lead booking-running managers for the offering, and they were granted a 30-day greenshoe option totaling an additional 1.65 million shares though these were not exercised as the share price remained above the issuance price, averaging $19.70 for the first month of trading. Generally speaking, 2019 was a poor year for IPO’s with ride-share companies Uber and Lyft among the high-profile unicorns that floundered. Peloton opened 6.9% below its trading price and multiple companies, perhaps most notably WeWork, decided to scrap the IPO altogether. Brigham’s IPO success and perhaps more importantly its ability to issue additional equity just eight months later may encourage private equity firms invested in minerals companies to test the IPO market.ConclusionMineral aggregators appear to have supplanted public royalty trusts as a key means for investors to get exposure to the sector while avoiding costly drilling expenses. While functionally related to drilling activity and well performance, aggregators allow investors to avoid cost burdens.  As such, valuations for the aggregators behave differently than other participants in the energy sector.We have assisted many clients with various valuation and cash flow questions regarding royalty interests. Contact Mercer Capital to discuss your needs in confidence and learn more about how we can help you succeed.
Exploration & Production Purchase Price Allocations
Exploration & Production Purchase Price Allocations

A Review of E&P Transactions Analyzed in Mercer Capital’s 2019 Energy Purchase Price Allocation Study

Last week, Mercer Capital released its 2019 Energy Purchase Price Allocation Study.  In this post, we’ll be taking a deeper dive into the Exploration & Production transactions reviewed in the analysis.The E&P sector had the lowest average allocation to intangible assets, at just 2% of total purchase consideration.  In fact, only two of the eleven transactions analyzed had any intangible allocation at all.  Oasis Petroleum recorded a small ($1 million) intangible asset related to a non-compete agreement in connection with its acquisition of Forge Energy.  The major outlier was Concho Resources, which recorded over $2.2 billion of goodwill related to its acquisition of RSP Permian.Exploration & Production is not an intangible asset-driven business model.  These companies sell a commodity, so there is no real brand value leading to trademark or trade name allocations.  Bill Barrett and Fifth Creek rebranded as HighPoint Resources after their merger, and recently two E&P companies (Ovintiv, formerly Encana, and Battalion Oil Corporation, formerly Halcon Resources) changed names, the latter likely influenced by its emergence from bankruptcy.The commodity is generally sold at market hubs, so specific customer relationships have minimal value.  (To the extent the company has derivatives that result in above-market pricing realizations, that asset is captured separately.)And while E&P companies tout their technical prowess, few outside of the majors spend meaningfully on R&D or have protected intellectual property.  None of the transactions analyzed in this year’s study included allocations to Developed Technology or In Process Research & Development.Ultimately, the value of an E&P company is driven by its reserves, and purchase price allocations generally reflected that.  Based on the transactions reviewed in our analysis, ~90% of purchase consideration was allocated to reserves.Again, the outlier in the data is Concho’s acquisition of RSP Permian, in which over $2.2 billion was allocated to goodwill.  In its 2018 10-K filing, Concho rationalized the goodwill value as follows:Goodwill recognized is primarily attributable to the following factors: (i) operating and administrative synergies and (ii) net deferred tax liabilities arising from the differences between the purchase price allocated to RSP’s assets and liabilities based on fair value and the tax basis of these assets and liabilities. For the operating and administrative synergies, the total consideration for the RSP Acquisition included a control premium, which resulted in a higher value compared to the fair value of net assets acquired. There are also other qualitative assumptions of long-term factors that the RSP Acquisition creates for the Company’s stockholders, including additional potential for exploration and development opportunities and additional scale and efficiencies in basins in which the Company operates.Despite the headwinds faced by the E&P sector since the Concho / RSP transaction, Concho has indicated that this goodwill value has not been impaired.  The company’s most recent 10-Q indicates that quantitative impairment tests were performed as of July 1, August 29, and September 30, 2019.  (However, Concho did take an $81 million goodwill impairment charge related to certain New Mexico Shelf acreage that was divested in 2019.)In an environment of increasingly complex fair value reporting standards and burgeoning regulatory scrutiny, Mercer Capital helps clients resolve financial reporting valuation issues successfully. We have the capability to serve the full range of fair value valuation needs, providing valuation opinions that satisfy the scrutiny of auditors, the SEC, and other regulatory bodies. Contact our Energy Industry or Financial Reporting Valuation teams to discuss your valuation needs in confidence.
Coming Soon: Mercer Capital’s 2019 Energy Purchase Price Allocation Study
Coming Soon: Mercer Capital’s 2019 Energy Purchase Price Allocation Study
We at Mercer Capital love movies.  One fun aspect of a movie is the anticipation for new releases that comes from watching movie trailers, which inform and tease simultaneously.  If done well, they can build anticipation for the show to come.  While not quite a movie trailer, we wanted to introduce you to a new study from our energy team that we are excited about: Mercer Capital’s 2019 Energy Purchase Price Allocation Study.This study is unlike any other in terms of energy industry specificity and depth.Valuation, by nature, is an inherently forward-looking exercise.  However, as we are still unable to see the future, history remains the window through which we look to gauge it.  As we plunge forward into a new year and a new decade, we take this opportunity to look back at the energy sector through the lens of transactions and GAAP financial reporting.  This study researches and observes publicly available purchase price allocation data for four sub-sectors of the energy industry: (i) exploration and production; (ii) midstream; (iii) oilfield services; and (iv) refining.  We are excited about this study because we think you’ll find it useful, informative, and helpful.  We are also excited because our study is unlike any other in terms of energy industry specificity and depth.Mercer Capital’s upcoming 2019 Energy Purchase Price Allocation Study provides a detailed analysis and overview of valuation and accounting trends in these subsectors of the energy space.  This study enables key users and preparers of financial statements to better understand the asset mix, valuation methods, and useful life trends in the energy space as they pertain to business combinations under ASC 805 and GAAP fair value standards under ASC 820.  We utilized transactions that closed and reported their purchase allocation data in calendar year 2018.This study is a useful tool for management teams, investors, auditors, and even insurance underwriters as market participants grapple with ever-increasing market complexity.  This study provides data and analytics for readers seeking to understand undergirding economics and deal rationale for individual transactions.  The study also assists in risk assessment and underwriting of assets involved in these sectors. Further, it helps readers to better comprehend financial statement impacts of business combinations.  Intangible assets comprised approximately 84% of the S&P 500s market value in 2018, according to a Ponemon Institute study.  Other studies suggest that the energy sector’s concentration of intangible assets approximates less than half of that.  Averages from year’s study across a total sample of 33 transactions bracket those estimates and they vary by sub-sector: When we prepared this analysis, we came across a few noteworthy items: Exploration and production transactions were primarily allocated to reserves, and particularly more proved reserves than unproved reserves. Only one transaction recorded goodwill.Oilfield services transactions had the most diverse set of allocations to intangibles.Midstream transactions (gathering/disposal, processing, compression and terminals) had the highest concentration within the sector groups of customer-related intangible assets as a percentage of purchase consideration.Useful life reporting varied, but oilfield services transactions tended to have longer remaining lives (10 years or longer) ascribed to them. There is a lot to learn from this study as it illuminates some key industry aspects which we will be discussing and referencing in future posts.  In the meantime, we hope the upcoming study will come to serve as a valuable reference.  Get your popcorn ready, you won’t want to miss the premiere.
Q4 2019 Global Macro Review
Q4 2019 Global Macro Review

U.S. Production Hits Milestones Amid Continued Global Political Tensions

Brent crude prices began the quarter around $59 per barrel and have steadily risen to around $68 to close out 2019. WTI pricing has risen at a similar pace although it continues to trail Brent pricing by about $7 per barrel. Natural gas, however, has been trending in the opposite direction as prices have steadily declined since the end of October. In this post, we will examine the macroeconomic factors that have affected prices in the fourth quarter.Global SupplyOPEC conducted its 177th meeting on December 5th to take note of oil market developments since its last meeting in July and to review the oil market outlook for 2020.  Press reports leading up to the meeting indicated that OPEC would extend the existing supply cuts, helping support crude oil prices.  Ultimately, the group went a step further, deepening production cuts by 0.5 million b/d.  However, the cuts were not extended and only run through the end of March 2020.  According to the EIA’s latest Short-Term Energy Outlook (“STEO”), OPEC production is expected to fall in 2020.  This is largely related to production restraint from most OPEC members amid concerns of rising oil inventories, continuing sanctions on Iran, and ongoing declines in Venezuela’s crude oil production.  EIA forecasts that increased non-OPEC production will more than offset those declines and that global liquid fuels supply will rise by 1.5 million b/d in 2020.International Maritime Organization 2020Beginning on January 1, 2020, the International Maritime Organization (IMO) is set to enact the Annex VI of the International Convention for the Prevention of Pollution from Ships (MARPOL Convention), which lowers the maximum sulfur content of marine fuel oil used in ocean-going vessels from 3.5% to 0.5%.  The implementation of MARPOL will see the marine fuels landscape change significantly as over 95% of the current market will be displaced. The EIA demonstrates the recent shifts in share of OECD Europe oil imports. These trends could continue in 2020 based on the IMO 2020 regulations.  The EIA expects U.S. crude oil production to provide approximately two-thirds of total global liquids growth next year.  It is also important to note that U.S. crude oil tends to be a light, sweet grade, which will likely see an increase in global demand due to the implementation of the IMO 2020 regulations, further tilting market share. U.S. Production Hits All-Time High in Q4In September 2019, the U.S. became a net petroleum exporter, marking the first month ever since monthly records began in 1973.  To be exact, the U.S. exported 89,000 b/d more crude oil and petroleum products than it imported in the month of September.  Increasing U.S. crude oil production has resulted in a decrease in U.S. crude oil imports as well as the number of import sources.  Despite the reversal in September, the U.S. remains a net importer of crude oil, however, and 60% of imports come from Canada and Mexico.The EIA expects U.S. crude oil production to average 13.2 million b/d in 2020, a slight increase from the 2019 level.  According to the STEO, slowing crude oil production growth results from a decline in drilling rigs over the past year, which is slated to continue into 2020.  Although the rig count is forecast to decline, the EIA forecasts an increase in production as rig efficiency and well-level productivity rises.U.S. – China Trade Deal Phase OneIn early December, the U.S. and China agreed on the first phase of a trade deal.  The Phase One agreement means the U.S. is suspending tariffs that were planned on $160 billion in Chinese imports.  In addition, the U.S. halved the September tariffs from 15% to 7.5%.  As a part of the Phase One deal, President Trump said Beijing has agreed “to many structural changes and massive purchases of Agricultural Product, Energy, and Manufactured Goods, plus much more.”  With regard to the trade deficit, U.S. officials signaled that China agreed to increase purchases of U.S. products and services by at least $200 billion over the next two years.  Phase One also addressed specific concerns subject to China’s intellectual property practices. President Trump explained that the U.S. and China would begin negotiations over the second phase of the trade deal rather quickly.  On the other side, China confirmed that a deal was reached and that the deal will be signed on January 15, 2020.Interest RatesBy the end of October, the Fed had made three rate cuts in 2019 due in part to trade policy uncertainty.  In early November, following the last round of cuts, the Fed decided to hold rates steady.  After their meeting in early December, the Fed kept the federal funds rate between 1.5% and 1.75%.  The Federal Reserve remained optimistic about economic stability but emphasized that their actions will depend on future events.  Long-term interest rates began to rise over the quarter from the low of 1.47% for the 10-year Treasury in September.  Looking ahead to early 2020, rates are expected to remain flat with quiet Fed activity.Middle East TensionsAn airstrike at the Baghdad Airport on January 3 killed top Iranian military commander, Major-General Qassem Soleimani.  Per the Department of Defense, the airstrike was conducted by the U.S. military at the direction of the President. WTI and Brent prices spiked nearly 4% on the breaking of the news.  Although further escalations are uncertain, moderate to low-level incursions in the first quarter of 2020 may be possible.  Analysts believe that Iran may resume targeting and harassment of oil shipping vessels in the Strait of Hormuz through which almost 25% of global oil consumption passes.  Iran sits at a natural choke point on the Strait, and has threatened to close Hormuz in times of heightened tension.  Disruption of this level of shipping could have large consequences on global oil demand and spikes in pricing if the U.S. and Iran continue to escalate military responses.ConclusionThe next OPEC meeting is scheduled to occur on March 5, 2020, so decisions on increased, steady, or reduced production cuts on the supply side will not be made until the end of the first quarter.  Middle East tensions will be a highlight going into the 178th meeting if the Iran and U.S. conflict escalates.  Increased disruption could significantly affect global oil demand and price.  In the meantime, strong U.S. production is expected to continue in early 2020, and it is unclear whether the U.S. – China Phase One Trade Deal will lead to continued negotiations and cooperation between the two global players.At Mercer Capital, we stay current with our analysis of the oil and gas industry both on a region-by-region basis within the U.S. as well as around the globe. This is crucial in a global commodity environment where supply, demand, and geopolitical factors have varying impacts on prices. We have assisted clients with diverse valuation needs in the upstream oil and gas industry in North America and internationally. Contact a Mercer Capital professional to discuss your needs in confidence.
Appalachian Gas Valuations: The Bad, The Ugly, (And The Good)
Appalachian Gas Valuations: The Bad, The Ugly, (And The Good)
U.S. dry gas consumption will finish at an all-time high of 84.3 Bcf per day in 2019 and that figure will continue to grow into 2020. However, if gas investors are celebrating, no one knows where the party is. In reality, the investing atmosphere is gloomy with commodity prices consistently below $3.00 per MMcf on the NYMEX and even lower in some locations. The valuation environment is dispiriting for many investors in Appalachia. It doesn’t take long to get buried in a cavalcade of adverse indicators, corporate overhauls, depressed EBITDA multiples and state sized swaths of uneconomic acreage. Data suggests some producers could spend the foreseeable future languishing in shareholder jail or bankruptcy court.How can economics get this jilted in arguably the largest gas field in the world? Perhaps it’s better to wonder why, at this point, would anyone even believe the dry gas investment premise at all? These are fair questions that investors and the broader stock market are asking themselves. Interestingly, there may be fair answers to them that, when analyzed closely, might chart a tough, disciplined course and perhaps eventually even position the Marcellus and Utica to be a globally superior gas field.The BadThere’s no question that valuations are floundering at relative historic lows. Mercer Capital’s group of public Appalachian gas producers has dropped approximately 50% since last year. It’s the largest collective decline of any other publicly traded U.S. basin group. Of the publicly traded Appalachian-based gas producers, some are trading at the bottom of EBITDA multiple ranges, and nearly all trade at the bottom from a price per flowing barrel metric.[caption id="attachment_29435" align="alignnone" width="750"] Mercer Capital's Selected Public Company Information Source: Bloomberg[/caption] Transaction activity has been quiet as equity markets are closed and management teams are concerned with stewardship of their existing asset base. Deals that did close were production-oriented; some transacting at higher expected rates of return compared to historical norms (15% or even 20% rates of return). It’s notable to point out that gas prices haven’t fallen nearly by the magnitude that stock prices have. So, what is happening to create such an investor flight? Consider recent developments. Corporate WranglingTrials are front and center for independent producers. They have been pronounced at Gulfport and EQT, where management and shareholders engaged in some tumultuous struggles this year. Gulfport had board turnover and suspended a share repurchase program that it had initiated only earlier this year (in order to switch to a debt buyback program at a discount). At EQT, corporate governance has also been volatile. Toby and Derek Rice, whose eponymous company merged with EQT in November 2017, waged a successful proxy battle this year, proposing a business plan in September which included a 23% reduction in employees alongside a logistical and strategic overhaul of its drilling plan.Throwing In A Major TowelTrouble in Appalachia is not confined to the independents. Chevron recently announced a $10 - $11 billion write-down. More than half of its impairment is attributable to its Marcellus/Utica assets. Chevron’s large position and presence in the region is now mulling an exit from the play.Cash Flow ChallengesDue in part to the lack of available capital, early projections show capex reductions of 23% in 2020.[caption id="attachment_29436" align="alignnone" width="640"] 2020 Drop in CAPEX (millions) Source: Shale Experts[/caption] This strategy cuts both ways. It can conserve cash in the short-term to allocate towards debt repayment or share buybacks, but it can also hamstring growth and production in future years, compounding problems with languishing prices. This is top of mind for many producers as they grapple with how to keep investors happy and stay out of bankruptcy court. Some producers are better positioned than others in this aspect, particularly Cabot. The chart below shows the relationship between the total amount of debt principal due over the next five years as compared to trailing levered free cash flow. It shows that some companies have some real challenges in that area. [caption id="attachment_29437" align="alignnone" width="640"] Cash Flow vs. 5-Year Debt Repayment Source: Capital IQ[/caption] Strangulation Via RegulationThe Marcellus and Utica Shale plays possess one of the best unused potential advantages in the natural gas world – proximity to the Northeast United States. One of the biggest potential consumers of the vast gas reserves is neighbor to the Marcellus, yet so little of it makes its way to its natural customer base. Why is this? One word: regulation. For example, the Constitution pipeline, approved by FERC in 2014, has been in regulatory purgatory since that time in the state of New York. Fracking is banned in New York and the regional political climate is frigid towards the natural gas industry, to say the least. In the meantime, New York-area utilities are struggling with gas pressure shortfalls for new customers. Also, in a twist of irony, increasing appetite for natural gas in Massachusetts is being met, at least partially, by Russian (yes, Russian) imports. Thus, Appalachia’s oversupply of gas continues to search for markets while the Northeast gets it from elsewhere. When a Russian LNG tanker pulls into Boston Harbor in the winter…that’s a bad sign.The UglyThe near-term doesn’t look any prettier when examining broader economic and commodity trends. In fact, some of it is downright ugly. Supply exceeds demand, futures prices remain anemic and huge areas of quality drilling acreage currently have minimal market value ascribed to them. These factors are putting a boot to the throat of producers and keeping valuations from even getting off the ground.Get Production For Nothing And Reserves For FreeAs we consider the supply and demand imbalance right now, we can change the refrain in one of Dire Straits classic songs to “Get Production for Nothing and Reserves for Free.” It can hardly be understated how much the reserves of dry gas in the U.S. have been turned on its head in the past decade. Flippant investors, to the chagrin of some, now view undrilled reserves as a dime a dozen. This was unheard of not long ago. This points out the most fundamental economic driver to these low valuations – oversupply. This hamstrings acreage valuations. According to the 2018 Year End Proved Reserve report which was released in early December, Appalachian dry gas has nearly doubled since just 2015. Even production gain metrics, which surged 48% over this same period, sit in the vapor trail of reserve growth. There is simply too much of a good thing, and it has cheapened gas for everyone else in the Marcellus’ short reach (especially the consumer).[caption id="attachment_29438" align="alignnone" width="640"] Appalachia (PA, WV, OH) Source: EIA[/caption] Gas Price LimboEven years out, NYMEX gas futures look so flat, it can hardly be called a curve. Like a frantic swimmer getting pulled by an undertow, producers struggle to breathe in this environment. To make matters worse, Appalachia’s regional market constraints make its supply and demand even more imbalanced, leading to consistently wide pricing differentials. What little midstream capacity does come online gets filled too fast to influence pricing power. This has been and remains an Achilles heel for Appalachia.[caption id="attachment_29439" align="alignnone" width="640"] Natural Gas Prices / Mcf Source: Bloomberg[/caption] Acreage Values Battling Irrelevancy At these prices, there are hundreds of thousands of Marcellus and Utica acres that are simply uneconomic. According to a recent analysis by Antero Resources, nearly half (45%) of the needed gas supply in the next four years is currently non-economic at strip prices below $2.48. While that price point doesn’t appear sustainable in the long run, it illustrates why values are so gaunt when it comes to acreage and undrilled reserves. Another way to look at this is to examine companies’ enterprise values as compared to the PV10 values of their proved reserves (including undeveloped reserves), a standardized industry metric. [caption id="attachment_29440" align="alignnone" width="640"] Current EV / PV10Source: Capital IQ[/caption] None of the companies even gets very close to a ratio of 1:1. Some companies are trading around production reserve values only. Either way one slices it, future drilling inventory does not appear to be particularly valuable in the market’s view at this juncture. When going through the laundry list of problems that the industry is facing, it can be difficult to see any upside, silver lining or diamonds in the rough. However, if one subscribes to rational market theory, then there are some things, hidden in plain sight, that could make an investor’s journey worth the long ride. The GoodIntrinsically, Appalachia remains one of the most strategically important gas plays in North America. Eventually, amid all the obstacles it faces, it has arguably the most potential of any shale gas field and could develop into one of the most profitable shale gas fields in the world for decades to come.Retrenching – Diet And Exercise PayOffThese challenges are certainly testing the mettle of Appalachian producers. Producers’ intense focus on cash flow has multiple long-term benefits. First, it strengthens balance sheets and makes bankruptcy a more remote concern. Second, the limitations on production growth set a course towards price correction. Third, if and when prices do drift upward, more and more acres become economic. Companies are optimistic about their future. It is notable that Appalachian shareholder returns are manifesting themselves mostly in the form of share buybacks as opposed to dividends. That demonstrates companies believe they are intrinsically undervalued. Remember, the geology and hydrocarbons are there, the question is how cheaply they can be produced. Possibly the most challenging gas environment has forced Appalachian producers to have among the lowest development and operating costs anywhere. Therefore, if producers can survive this, then they can survive and thrive almost anywhere. That’s good because in the future this gas will have places to go.Oversupply Doesn’t Mean Lack Of DemandOne constant positive for Appalachian producers is that the demand is strong and growing. Platts Analytics estimates that around 80 Tcf of new supply is needed in the U.S. through 2023. Appalachia is expected to supply 38% of that figure. Even with all of the associated gas produced in the Permian right now (which also has logistics issues), it’s not enough. Gas will flow into the Gulf Coast and Appalachia will help lead the way. Globally, natural gas is the only fossil fuel expected to grow in global demand all the way through 2035.Exports And The LNG Market – A Brass Ring Worth ChasingThe enduring upside for valuations in Appalachia is capitalizing on what’s already in motion: U.S. domination of the worldwide LNG market. It’s not there today, but it is on its way. Between 2017 and 2027, LNG export capacity in the U.S. will have grown tenfold from around 3 Bcf per day to approximately 34 Bcf per day. Price relief for producers could just be a tanker away. Wallowing at $2.50 per MMcf domestically is tough; selling LNG to end markets at up to $9.00 per MMcf is much easier. Global prices are expected to average around $7.00 per MMcf going forward. How does the U.S. fit in this global market? Well, worldwide LNG production growth is flagging, just in time for the U.S. to fill the gap.[caption id="attachment_29441" align="alignnone" width="640"] Natural Gas Trade Source: U.S. Energy Administration[/caption] The Chinese will need energy to engage in any trade wars and American LNG producers will likely supply it over the next 30 years. The U.S. will make up 67% of the growth in global LNG exports through 2024 and China will be the biggest buyer. Looking again at the Appalachian pricing chart overlaid with historical LNG export prices, the opportunity becomes clear. [caption id="attachment_29442" align="alignnone" width="640"] Natural Gas Prices / McfSource: Bloomberg[/caption] A drawback is that compared to the gas basins more proximate to the Gulf Coast, Appalachia has fewer LNG export options. The Elba Island LNG facility is operational, and Cove Point has some capacity, but this pales in comparison to Gulf Coast capacity. At the same time, there are other demand sources, such as Mexico, that will keep overall gas export demand high. Those factors should allow Marcellus and Utica producers more latitude to meet regional demand for east coast population centers. Even if pipeline constraints remain at a minimum, perhaps a tanker with U.S. gas pulls into Boston Harbor instead of a Russian one. Final ThoughtsOne potential wildcard is the possibility of a renewable energy breakthrough. There is certainly a strong sustained desire by many people for this option. However, economically, there are just no alternative sources that can fill the gap in time to meet domestic and international energy and electricity demand. The gap filler is natural gas, and the basin with long-term solutions is primed to be Appalachia. This is the intrinsic valuation premise keeping long-term investors on board.Originally appeared on Forbes.com.
The Best of 2019
The Best of 2019

Energy Valuation Insights' Top Blog Posts

As we plan for a new year and a new decade, we look back at 2019 to see what was popular with you ­– our readers. Below is a list of the top posts of 2019. Instead of a standard top 10 list, we’ve grouped the posts by topic (Transactions, Saltwater Disposal, Oilfield Services Companies, Royalty and Mineral Markets, and Basin-Specific posts). If you missed one or two posts during the year, now is the time to catch up on your reading.We look forward to 2020 and appreciate your interest in this blog. May you and your family enjoy a happy and prosperous year.TransactionsComstock's Acquisition of Covey Park: A Valuation Analysis of the Multibillion-Dollar Haynesville Deal (Posted 08/02): On July 16, 2019, Comstock Resources, Inc (NYSE: CRK) finalized its acquisition of Haynesville operator Covey Park Energy LLC. Announced on June 10, 2019, the companies entered into an agreement under which Comstock would acquire Covey Park in a cash and stock transaction valued at approximately $2.2 billion, including assumption of Covey Park’s outstanding debt and retirement of Covey Park’s existing preferred units (totaling approximately $1.1 billion). For the purposes of this post, we examine this deal from a few different vantage points and review the fair value of the various components that make up total deal value. We also look at how this transaction compares to industry valuation metrics and what kind of strategic advantages Comstock may have a result of the deal.Parsley's Acquisition of Jagged Peak Highlights Key Consolidation Trends (Posted 11/21): On October 14, 2019, Parsley (PE) announced that it was acquiring Jagged Peak (JAG) in an all-stock transaction valued at $2.27 billion.  The market’s reaction to the announcement was generally negative, as Parsley closed down more than 10% on the date of the announcement.  This appears to be driven, at least in part, by investors’ desire for Parsley to be acquired rather than be the acquirer.Brigham Minerals IPO Brings Spotlight to Oil & Gas Market (Posted 05/06):Mineral aggregators are leading the forefront in an underwhelming energy sector. Brigham Minerals (MNRL) is the latest mineral acquisition company to go public following a trend of other large mineral rights and royalty companies to IPO in recent years.Saltwater DisposalAn Overview of Salt Water Disposal (Posted 04/19):Over the last 12 years the oilfield waste water disposal industry has grown exponentially, both on an absolute basis, and by rank of its importance/size among the oilfield services. This growth has been largely driven by the increased volumes of waste water generated in the production of oil from shale plays. This post discusses the basics of salt water disposal which has become so important given the rise of hydraulic fracturing.An Overview of Saltwater Disposal | Part 2: Economics of the Industry (Posted 08/19): In this post, we look at the economics of the saltwater disposal industry and the trends that impact its economics. The outlook for the industry is quite favorable although the economics are, and will continue to be, in a state of flux as the industry grows and matures.  Despite some potential detrimental market dynamics along the way, the overall direction points to strong benefits to investors as the business of saltwater disposal continues to evolve away from being a cost center for operators, to a cash flow generating third-party service provider to operators.Do Oil and Water Mix? The Biggest Energy IPO Of 2019 Might Answer That Question (Posted 09/19):The capital markets in the upstream sector are leaving companies and investors in the lurch right now. Saltwater disposal and integrated water logistics companies have attracted a higher proportion of the sparsely available capital flowing into the sector, highlighted by the largest energy IPO of this year: Rattler Midstream LP. The continuing austerity trend toward cash flow sustainability for shale oil companies has provided limited attractive options for investors. In the meantime, drilling activity (particularly in West Texas) continues to grow, and therefore efficiency and scale grow ever more important across the board for upstream companies to remain competitive. One of the challenges producers face is handling the enormous amounts of water that have become part and parcel to the Delaware and Midland Basins. This is where saltwater disposal enters the picture. (Originally appeared on Forbes.com)Oilfield Services CompaniesWhat Is an Oilfield Service Company? (Posted 05/24):In this post, we describe what an oilfield services company does and who its customers are, how oilfield services companies fit in the broader oil and gas industry and identify the key drivers of the oilfield services industry.How to Value an Oilfield Service Company (Posted 06/03):When valuing a business, it is critical to understand the subject company’s position in the market, its operations, and its financial condition. A thorough understanding of the oil and gas industry and the role of oilfield service companies is important in establishing a credible value for a business operating in the space. Our blog strives to strike a balance between current happenings in the oil and gas industry and the valuation impacts these events have on companies operating in the industry. After setting the scene for what an oilfield service company does and their role in the energy sector, this post gives a peek under the hood at considerations used in valuing an oilfield service company.How to Perform a Purchase Price Allocation for an Oilfield Services Company (Posted 10/25):When performing a purchase price allocation for an oilfield services company, careful attention must be given to both the relevant accounting rules and the specific nuances of the oil and gas industry. We address both in this post.Forecasting Future Operating Results for an Oilfield Services Company (Posted 06/10):In this post, we address the special considerations that must be given attention in the appraisal of oilfield services companies. The unpredictable cyclicality of the oilfield services industry requires careful consideration of many industry-wide and company-specific factors in developing a reasonable forecast of future operating results.Royalty & Mineral MarketsRoyalty MLP Is Delivering Yield Against Backdrop of Energy Sector Struggles (Posted 11/25):Right now, exploration and production companies and oilfield service providers are grappling with austerity measures that investors are demanding. Most other upstream areas are struggling too; however, publicly-traded royalty and mineral aggregators are performing relatively better than their operating counterparts. While equity prices have dropped by approximately 30% for producers (according to SPDR Oil and Gas ETF), six publicly-traded royalty aggregators outperformed the SPDR Index.Royalty and Mineral Value Proposition Highlights Otherwise Underperforming Energy Sector (05/17):The burgeoning mineral market is leading the way for an energy sector that has lagged in returns for several years now. The interest in the segment has been undergirded by the attractive cash returns coupled with fewer liability risks, operating risks, and expense burdens.  In addition, royalty owners retain ownership rights to perpetuity.  These characteristics of royalty and mineral plays have drawn investors in as compared to the market’s negative response to upstream management teams merely seeking to beef up the size of their reserve reports.Basin-SpecificPipeline Bottlenecks and Worthless Acreage: The Downsides Of World-Leading Oil Production (Posted 10/31):In this post, we discuss pipeline capacity and flagging prices for undeveloped acreage, specifically in the Bakken. (Originally appeared on Forbes.com)Valuations in The Permian: Gearing Up for the Long Haul or Running in Place? (Posted 07/12):When it comes to the oil patch, the word “growth” can be a vague term. It’s a word that can be masqueraded around to suit the perspective of whomever utters it. What does it mean in an industry whose principle resources are constantly in a state of decline? When it comes to the Permian Basin these days, growth applies to resources, drilling locations, and production. Unfortunately, the same can’t be said for profits, free cash flow or new IPOs. Don’t misunderstand, the Permian is the king of U.S. oil plays and by some measures could be taking the crown as the biggest oil field in the world. However, various economic forces are keeping profits and valuations in check. (Originally appeared on Forbes.com)2019 Eagle Ford Shale Economics: Challenging for Valuation Title Belt (Posted 04/30):Investors and boxing fans have some things in common. First, they both prefer champions. Second, there tends to be attention on heavyweights, when the best fighters may be in a different class. In the oil patch’s proverbial basin battle of economics and relative value, the Eagle Ford Shale is coming on strong. Granted, the Eagle Ford Shale may not reside in the same heavyweight class as the Permian Basin; however, from a pound for pound well economics standpoint, the Eagle Ford Shale is currently a formidable challenger to the Permian due to several advantages in key areas: breakeven prices, well costs, certain productivity metrics and proximity. These attributes put it among the most profitable shale basins in the U.S. Some well-known operators such as BP and Chesapeake have noticed and are putting big money behind this play. (Originally appeared on Forbes.com)Bryce Erickson Writing for Forbes.comIn case you’ve missed it, Bryce Erickson, leader of Mercer Capital’s Oil & Gas industry group, is a regular contributor to Forbes.com. He addresses industry developments, economic trends, and the impact on valuation for companies operating in the Permian, Eagle Ford, Bakken, and Marcellus & Utica regions, among others. Additionally, he covers these issues as they pertain to mineral rights and royalty interest owners.
EP First Quarter 2020 Eagle Ford
E&P First Quarter 2020

Eagle Ford

Eagle Ford // In the first quarter of 2020 oil benchmarks ended arguably their worst quarter in history with a thud.
Appalachia M&A
Appalachia M&A

Rangebound Gas Prices and Preoccupied Management Teams Cause Slowdown in Activity

It was a quiet year for M&A in Appalachia as only a handful of transactions occurred.  Surging associated gas production in places like the Permian and Bakken have kept a lid on gas prices, which have largely remained between $2 and $3/mmbtu for the year.  Near term expectations aren’t much better, with futures prices below $3 through 2029.  Management teams were likely preoccupied with various corporate and capital structure issues instead of changes to the underlying reserve base.  However, a bright spot is the easing of takeaway constraints that previously plagued the region.Recent Transactions in AppalachiaA table detailing E&P transaction activity in Appalachia during 2019 is shown below.  Overall, deal count and average deal size declined relative to 2018.  Diversified Gas & Oil’s acquisition of HG Energy II was the only non-royalty transaction of meaningful size during the year.  Cabot recently announced a $256 million divestiture of its 20% interest in NextEra Energy’s Meade Pipeline, though that transaction is not included in the E&P transactions listed below.Range Resources ORRI SalesRange Resources was the most active market participant in the basin with two overriding royalty interest (ORRI) sales and the sale of 20,000 non-producing acres in Pennsylvania.  The company intends to use the proceeds to paydown debt, offsetting much of the lost cash flow from the assets with decreased interest expense.  The company also announced a $100 million share repurchase program.Diversified Gas & Oil Acquisition of Unconventional Assets from HG Energy IIDiversified Gas & Oil acquired 107 gross producing wells and related surface rights from HG Energy II.  The acquisition is consistent with the company’s strategy of buying mature, low-decline PDP assets in Appalachia.  However, the transaction does represent somewhat of a departure from the company’s historical focus on conventional (non-shale) assets.  Management indicated that the transaction would be accretive on various per-share metrics including earnings and free cash flow.Operators Focused on Changes to Corporate and Capital Structure Rather than Asset BaseWhile it has been a quiet year in Appalachia on the M&A front, it was a tumultuous year for management teams and board members.Toby and Derek Rice’s proxy battle for control of EQT made headlines during the first half of the year.  The Rice brothers cited EQT’s poor operational performance after its acquisition of Rice Energy as a reason to shake up management and the board.  The brothers proposed a business plan which they indicated would generate an estimated incremental $400 - $600 million of pre-tax cash flow and unlock shareholder value.  They succeeded in July with Toby Rice replacing Robert McNally as President and CEO of EQT.  An organizational streamlining was announced in September, which included a 23% reduction in employees.Gulfport Energy, which has been targeted by activist investor Firefly Value Partners, announced a $400 million stock repurchase program in January 2019.  However, the company suspended the program in November, citing “current market conditions and a weak near-term gas price outlook.”  The same press release also announced that the company reduced its headcount by 13%, two board members were stepping down, and the chairman of the board would not seek re-election at the next shareholder meeting.Diversified Gas & Oil Company announced a novel financing transaction that may pave the way for other E&Ps looking for creative ways to fund operations.  The company created a special purpose vehicle that issued non-recourse, asset-backed securities collateralized by a working interest in the company’s PDP assets.  The company plans to utilize the proceeds from the financing to pay down borrowings on its existing revolving credit facility.Antero Resource’s midstream affiliate, Antero Midstream (AM), completed one of the more complicated MLP simplifications earlier in 2019.  In June, after Warburg Pincus divested its remaining ownership interest in the company, Warburg’s two board members resigned, reducing Antero’s board to just seven directors.  In December, Antero announced a $750 million to $1 billion asset sale program, which the company kicked off by selling $100 million of AM shares back to the midstream affiliate.  Management indicated that future asset sales could consist of “lease acreage, minerals, producing properties, hedge restructuring or sale of AM shares to Antero Midstream.”  As management teams work to fix capital structures through potential asset sales, 2020 might be a more active year for transactions in the basin.ConclusionM&A transaction activity in Appalachia was muted in 2019 as gas prices remained rangebound and management teams focused on corporate and capital structure issues rather than M&A.  However, with operators feeling the pressure from sustained low gas prices, and Antero’s announced asset sale program, 2020 will hopefully be a more active year.We have assisted many clients with various valuation needs in the upstream oil and gas industry in North America and around the world.  In addition to our corporate valuation services, Mercer Capital provides investment banking and transaction advisory services to a broad range of public and private companies and financial institutions.  We have relevant experience working with companies in the oil and gas space and can leverage our historical valuation and investment banking experience to help you navigate a critical transaction, providing timely, accurate and reliable results.  Contact a Mercer Capital professional to discuss your needs in confidence.
Themes from Q3 2019 Earnings Calls
Themes from Q3 2019 Earnings Calls
The energy sector in the third quarter has experienced a general decline as crude prices have exhibited volatility and have remained depressed relative to last year. U.S. producers continue to cut rigs and capital expenditures due to continued excess supply and concerns of declining demand. In this post, we examine some of the most discussed items and trends from the Q3 earnings calls, specifically E&P companies and those in the mineral aggregator space.E&P CompaniesE&Ps experienced mixed earnings although many beat expectations and were cash flow positive as the industry has been trending in this direction. The two major topics discussed in E&P earnings calls have been capital discipline and treatment of free cash flow.Capital Discipline: Doing More with LessWe also want to highlight our capital discipline. Third quarter non-acquisition CapEx came in slightly lower than the second quarter and almost 10% lower than the first quarter. As we look to the fourth quarter, we continue to expect CapEx to be significantly lower around $550 million. Each quarter it's been lower throughout the year. This is by design as we expect to be roughly in line with CapEx expectations for the year. -John Hart, CFO, Continental ResourcesI'm happy to report that the third quarter operating cash flow before working capital changes of $706 million exceeded exploration and development capital of $670 million. This marks an important return to free cash generation for the company primarily driven by better capital cost. -Jack Harper, President, Concho ResourcesAs we move forward as a combined company, our commitment to capital discipline and returning capital to shareholders remains unchanged. We remain on track to spend within our full year pro forma combined capital budget of $8.6 billion, excluding Africa. Furthermore, we have established a capital budget for 2020 that we expect will fully optimize free cash flow and position us to grow production in a capital-efficient manner while maintaining the safety of our dividend. -Cedric Burgher, SVP & CFO, Occidental Petroleum Corp The topic of capex budgets and spending has been a major talking point for E&P companies since the oil and gas market took a big hit at the end of 2018. Rising prices for the first three quarters of 2018 begat exuberance, and producers below through their budgets only to see prices fall precipitously. Uncertainties surrounding future commodity prices as well as diminishing capital outlays from the public and private markets forced companies to trim capital budgets and rigidly stick to them to ensure that free cash flow generation was positive.Uncertainties surrounding future commodity prices as well as diminishing capital outlays has forced companies to trim capital budgets.Many of these companies for the first six months of the year were near or over budget in capital spending. And while capital expenditures may be frontloaded for various reasons, a consequence of trying to remain in bounds of the budget has been decreasing active rig counts during the year.However, the reduction in rigs counts for several companies has allowed for more strategic capex dollars to be spent on target infrastructure resulting in improvements in cost per foot. Overall the efficiencies and cost savings have enabled companies to be free cash flow positive for the third quarter.Where is Free Cash Flow Going?As of October 29, we have repurchased 5.5 million shares for $187 million. We plan to continue prioritizing our share buybacks with our excess cash. We see tremendous value in the acquisition of our stock as our share price does not reflect our strong earnings, cash flow and the deep oil-weighted inventory we have for future growth. -John Hart, CFO, Continental Resources, Inc.Well, we're going to look at primarily toward, what is our free cash flow and our free cash flow and I'm debating, I'm still traveling around, we're going to go out and see all of our long shareholders again early next year. But we're trying to determine a long-term strategy of what's best between share buybacks in regard to in addition to increasing the dividend, whether or not to go to variable dividend and balance sheet… we have roughly approximately over the next several years about $5 billion. And so we're trying to come up with the ideal plan to disperse that in regard to all three of those. Obviously, with two-thirds of that going toward shareholder friendly measures such as buybacks and dividends. -Rich Dealy, EVP & CFO, Pioneer Natural Resources…on the how we balance dividend versus stock buybacks. I would say that it would kind of laid out a framework for where we think the free cash flow could be under the different side boards. And I think philosophically you'll see us kind of increase the dividend more in a systematic way and in a way that we can sustain forever. And then every other dollar that's available especially at this price, I'm going to be buying stock back. -Tim Leach, CEO, Concho ResourcesOur consistent industry-leading operational results, combined with our ability to fully deliver on value capture, positions us for a full cycle success and enhances our ability to generate increased excess free cash flow to reduce debt and to return cash to shareholders. Returning excess capital to our shareholders is a part of Oxy's DNA. In the third quarter, we returned approximately $600 million to shareholders. -Vicki Hollub, CEO, Occidental Petroleum Corp. E&P’s appear to be answering the longtime demands from investors of capital return in the form of dividends and share repurchases. Many companies are continuing large stock repurchase programs through combinations of free cash flow generation and ongoing asset sales. This treatment of free cash flow is a result of the strict capital discipline seen across the industry and may prove to be a worthwhile investment should commodity prices improve going into 2020. External and political changes could help (or mute) this effort.The trade-off for increased free cash flow is slower production growth.However, the trade-off for increased free cash flow is slower production growth. Many companies are putting “caps” on growth in order to achieve their desired levels of free cash flow generation. Vicki Hollub of Occidental says in their latest earnings call, “Our intent is to cap our annual production growth at an average of 5% as we balance the vast opportunities in our portfolio with growing free cash flow.”It's clear that E&P’s believe that their current stock valuations do not reflect the intrinsic value they think they bring to the table, particularly as commodity prices bounced back from year-end 2018 lows but stock prices received less of a boost. However, excessive share buybacks may put limitations on growth and future production, straining growth of cash flow yield should the commodity environment remain depressed.Mineral AggregatorsMineral aggregators had mixed earnings in the third quarter of 2019, but were more stable than E&Ps.  While Kimbell Royalty Partners realized a record-breaking performance in the quarter, others such as Brigham Minerals seem more concerned with future performance in the face of underwhelming past performance.Mineral aggregators have had to answer a number of questions regarding potential acquisitions.  Although acquisition and divestiture activity is the defining characteristic of the aggregator space, companies among the group seem hesitant to make acquisitions that are perceived as too aggressive at this juncture.  The consensus is that it will be worth the wait.Acquisition Opportunities and Strategies: Playing the Waiting GameWe are actively searching for those larger transactions and working with those, dialoguing with individuals. And so, I think what's going to happen is over time and then whether that's in the next, say, 3-months to 12-months or so, we'll find that larger transaction, be able to use our equity to acquire with. -Rob Roosa, Founder and CEO, Brigham MineralsThe macro environment is, frankly, tough right now. And in response to that, we've pulled in our horns, some on acquisition–on the acquisition front and are being more selective. We haven't seen anything that we can't live without. We're being a bit more defensive at the moment. And while we're in that mode, we'll prioritize paying down the revolver, which will position us for future acquisitions or share repurchases. -Thomas Carter, Chairman and CEO, Black Stone MineralsLastly, the acquisition market remains robust, and we continue to evaluate opportunities across our many basins. We continue to see great value for acreage outside of the Permian Basin, even considering dramatically reduced drilling activity in 2020 and beyond. So while just about everyone else is focused on the Permian and although we continue to evaluate the Permian, we are having more success in other basins with significantly less competition. –Bob Ravnaas, Chairman and CEO, Kimbell Royalty PartnersThat said, in this environment, and with the asset base that we have and the operators we have and the clear growth that's immediately in front of us, it seems for us inappropriate to dilute that with acquisitions. -Daniel Herz, CEO and President, Falcon Minerals Although they have an increasingly specific appetite for acquisitions, mineral aggregators have emphasized their preference for larger packaged transactions.  Travis Stice, CEO and Director of Viper Energy Partners, demonstrates this strategy as they expanded their footprint in the Permian via large acquisitions during the third quarter.  Large swaths of contiguous acreage continue to be more valuable to aggregators, which opens up the market opportunity for larger players to come in and consolidate some of these mineral owners and sell the combined acreage at a premium.  It will be interesting to monitor the transactions space to determine whether the waiting game will pay off.
Royalty MLP Is Delivering Yield Against Backdrop Of Energy Sector Struggles
Royalty MLP Is Delivering Yield Against Backdrop Of Energy Sector Struggles
Energy commodity cycles can sometimes proffer interesting market dynamics. At various points, participants along the energy chain can benefit or suffer from the natural consequences of these changes. In the long run, commodity prices ultimately drive economics. Right now, exploration and production companies and oilfield service providers are grappling with austerity measures that investors are demanding. Most other upstream areas are struggling too; however, publicly-traded royalty and mineral aggregators are performing relatively better than their operating counterparts. While equity prices have dropped by approximately 30% for producers (according to SPDR Oil and Gas ETF), six publicly-traded royalty aggregators relatively outperformed the SPDR Index. These Royalty MLP’s (a bit of a misnomer as all are not partnerships) have tracked closer to crude oil prices, anchored by sizeable dividend payments, thus buoying sliding equity prices. If dividend yields are added back, some of them have been outperforming crude prices.Upstream Producers Thirsting For CapitalAt recent industry conferences, panelists and management teams for exploration and production companies have consistently lamented the dearth of available capital. As banks re-evaluate their credit facilities, some analysts estimate a 10%-25% reduction in reserve-based lending capacity. Investors have communicated a sink or swim message to the sector and the term “capital discipline” is echoed frequently. Producers must subsist on their own cash flow for the foreseeable future and performance must improve before capital flows back upstream. This trend partially explains why energy currently comprises less than 5% of the sector weighting value of S&P Index, a historical low. It is notable and somewhat ironic that part of the success of the remaining 95% of the S&P has been attributable directly or indirectly to the cheap energy prices being delivered by the energy sector.[caption id="attachment_28934" align="aligncenter" width="813"]Source: S&P 500[/caption] E&P’s Primed For Consolidating? Bankruptcy Bargains?Cost control and efficiencies are on the top of the industry’s mind. In response, the consolidation trend for upstream producers is underway. Parsley’s acquisition of Jagged Peak and Comstock’s acquisition of Covey Park are examples of this, with more likely to come. Consolidation will occur through bankruptcy sales as well. According to Haynes and Boone bankruptcies in the oil patch have consistently ticked up with nearly $13 billion in new debt under bankruptcy in 2019. Therefore, Section 363 sales to consolidators should be available among other things. The big problem circles back to where this article started – where to obtain the funds to buy them? Those with pocketbooks at this time may be able to unearth some bargains and returns down the road to show for it. In fact, Comstock may be back in that distressed market as there are reports about negotiations for buying Chesapeake’s Haynesville Shale assets.Royalty MLP Subsector Still Has Capital Flowing InMeanwhile, like a small oasis in this desert, Royalty MLP’s have been and continue to successfully attract capital flow to this sub-space. Brigham Minerals, for example, not only went public earlier this year but had its line of credit expanded. Recent third quarter call transcripts from these Royalty MLP’s all suggest that acquisitions and growth (while disciplined) will continue. Indeed, Kimbell Royalty Partners has had one of the biggest dividend boosts in the marketplace this year. The primary reason for this is simple, while benefitting from well production, royalty holders do not bear operating and drilling costs. Therefore, they can get the best of both worlds. Of course, returns are also predicated upon the cost to acquire. Even if Royalty MLP’s overpay for the acreage they acquire, this tends to limit or delay returns as opposed to zero or negative returns at the asset level.[caption id="attachment_28935" align="aligncenter" width="640"]Source: Capital IQ[/caption] Additionally, Royalty MLP’s will be the logical and likely recipient of larger packages of minerals as private equity firms, who flocked to this sector a few years ago, begin to monetize their funds. This is significant because it is beginning to change the nature of a typical mineral owner’s profile, mindset and holding period expectations. As more investment-minded participants enter the space, the sophistication and expectations of buyers and sellers change along the way. The public royalty firms are preparing for this, which is why their acquisition budgets are steady or growing as opposed to shrinking across the board for producers. On a side note, this is not isolated to only publicly traded mineral and royalty participants. From a more macro perspective, this growth dynamic can be observed right at the U.S. budget where billions more flow into government coffers. U.S. public lands drove a 30% increase in federal energy and minerals revenue disbursements in fiscal year 2019 to $11.69 billion. The biggest contributor to that boost is in the New Mexico portion of the Permian Basin. ConclusionOverall the upstream sector has challenges right now, but the royalty and mineral sub-sector is weathering the changes better than some other sub-sectors. Strong dividend payments, with the promise for more in the future aligns more with investor expectations right now. As always, the lynchpin to industry health is commodity prices. Crude prices dropped in the late spring and have been treading water for the past several months. Many industry observers suggest stagnant prices in the $50-$60 range for the foreseeable future. However, others suggest that while the industry tightens its belt, prices may creep back up into the $60-$70 range. If that happens, shareholder returns will accrue to more than just producers and royalty holders.Originally appeared on Forbes.com.
Parsley’s Acquisition of Jagged Peak Highlights Key Consolidation Trends
Parsley’s Acquisition of Jagged Peak Highlights Key Consolidation Trends
On October 14, 2019, Parsley (PE) announced that it was acquiring Jagged Peak (JAG) in an all-stock transaction valued at $2.27 billion.  The market’s reaction to the announcement was generally negative, as Parsley closed down more than 10% on the date of the announcement.  This appears to be driven, at least in part, by investors’ desire for Parsley to be acquired rather than be the acquirer. Despite the negative market reaction, we believe this transaction is emblematic of key trends we expect to see during the next wave of consolidation. All-Stock TransactionJagged Peak shareholders will receive 0.447 shares of Parsley stock per JAG share.  Legacy Parsley shareholders will own 77% of the combined company, while legacy Jagged Peak shareholders will own 23% of the combined company.With equity capital markets largely closed to E&P companies and investor concerns regarding leverage, we don’t expect to see any cash/debt-financed acquisitions in the near future.  The exception might be a transaction by a supermajor as Exxon and Chevron reported cash balances of $5.4 billion and $11.7 billion, respectively, at the end of September.Low- or No-Premium AcquisitionConsideration to Jagged Peak shareholders represented an 11.2% premium relative to JAG’s preceding closing price.  However, given JAG’s recent stock price decline, the implied price was only a 1.5% premium to JAG’s 30-day VWAP. Investors are increasingly focused on metrics like return on capital employed and cash flow per share accretion/dilution.  As an acquisition premium increases, these metrics worsen. After Callon announced its acquisition of Carrizo for 2.05 CPE shares per CRZO share, implying a 25% premium based on closing prices before the announcement (though the press release cited the lower 18% premium based on Carrizo’s 60-day VWAP), Callon faced intense investor pushback, especially by hedge fund manager John Paulson.  Last week, Callon and Carrizo announced revised deal terms in which Carrizo shareholders will receive only 1.75 CPE shares per CRZO share, resulting in a more modest 11% premium based on prevailing prices.  However, the press release again cited a lower premium, this time of 7% based on pricing just before the original transaction announcement in July. Low- or no-premium acquisitions are more palatable to sellers in all-stock transactions as they have the potential to realize the transaction’s synergistic benefits over time given their continued ownership interest in the combined entity.  With an all-cash acquisition, benefits to the sellers can only be realized from the purchase price, so meaningful take-over premiums are typically necessary. Corporate, Rather than Asset, TransactionA&D activity recently has been modest, with wide bid/ask spreads separating buyers and sellers.  However, with corporate transactions, public stock prices help align buyers and sellers on value.  Also, the inherent G&A expense associated with a corporation gives the buyer an obvious target for synergies.Focus on Concrete Cost Synergies Rather than Nebulous Strategic RationaleIn the acquisition presentation, the “Synergy Scorecard” slide (page 10) clearly emphasizes the G&A and operational synergies that Parsley expects to realize from the acquisition.  While the strategic benefits are also highlighted (and take up most of the real estate on the page), it is clear that these take a backseat to the tangible cost reductions.ConclusionParsley’s acquisition of Jagged Peak largely follows the playbook we expect to see in upcoming M&A announcements.  Despite the expected cost synergies and strategic benefits, shareholders reacted negatively to the news.  Even with the addition of Jagged Peak, Parsley’s status as the fourth largest operator in the Permian (based on rig count) would remain unchanged.  This will likely cause management teams to re-evaluate their thoughts on optimal size and scale as they survey the acquisition landscape.We have assisted many clients with various valuation needs in the upstream oil and gas industry in North America and around the world.  In addition to our corporate valuation services, Mercer Capital provides investment banking and transaction advisory services to a broad range of public and private companies and financial institutions.  We have relevant experience working with companies in the oil and gas space and can leverage our historical valuation and investment banking experience to help you navigate a critical transaction, providing timely, accurate and reliable results.  Contact a Mercer Capital professional to discuss your needs in confidence.
Public Royalty Trusts: More Than Meets the Eye
Public Royalty Trusts: More Than Meets the Eye

Yield Traps, Depressed Commodity Prices, and Stage of Decline May Decrease Utility of Public Yields

In previous posts, we have discussed the relationship between public royalty interests and their market pricing implications to royalty owners.  We have differentiated between mineral aggregators and public royalty trusts and introduced some other considerations for how to pick the appropriate comparable. In this post, we will discuss the prevailing high dividend yields of public royalty trusts. We will also offer some reasons for why these trusts may be declining not just in production but also their comparability, from a valuation perspective, to some privately held mineral interests.Market Data for Trusts and AggregatorsThe following tables gives some critical market data for valuation purposes:We note that the yields are significantly lower for mineral aggregators than the public royalty trusts, who also have significantly lower market caps. Previously, we’ve explained what a royalty trust is; however, to understand these recently elevated yields, we may need to back up and discuss why royalty trusts are started in the first place.Why a Royalty Trust?Royalty trusts represent a unique financing tool for E&P companies. Instead of holding onto wells and collecting revenue over a longer holding period, operators can monetize these wells upfront by selling the wells to a trust. This allows operators to reinvest the proceeds back into its operations in an industry where cash is key. Trust distributions are determined by the level of production of the wells and commodity prices. By selling the wells to a trust, the operator can avoid the need for hedging the price risk. Also, since production of the wells is expected to decline over time, operators can avoid the drawn out, declining marginal utility of the wells. This is particularly helpful considering a dollar today is worth more than a dollar down the road.Potential Pitfalls of Public Dividend Yields as a Proxy for RiskWe’ve discussed the importance of scrutinizing each royalty trust individually in order to determine the comparability with private interests. Some of these considerations include:Commodity mix (oil vs natural gas)Idiosyncratic issues with the operatorRegion/basin However, these are not the only considerations, and they may not provide the proper sanity check in the context of the elevated yields that have persisted in recent months.Some further considerations include:Stage of productionCalculation method of the dividend yieldFriction in equity market pricingOperating Expenses in a depressed commodity price environmentWhere are you on the Production Decline Curve?As oil and gas is extracted from a well, its production declines over time.  As production declines, the yields tend to increase (more on this later). This can misrepresent the risk to reward opportunity as timing must line up.  The value of a mineral interest that has been producing for an extended period of time should not be compared to a well that has just started production or is even still in the drilling or development stage. These situations are two different points on the production curve and represent different risk profiles. For a PDP (proved, developed, producing), there is less risk than any other stage (compared to PUD, P2 or P3). It is important to consider the relationship between these stages of production instead of simply looking to the public markets and being prisoners of the moment or uninformed of the differences between public trusts and a privately held interest. The stage of production and decline rate must reasonably reconcile to private interests to ensure that yields and commensurate risk are compared apples-to-apples.Trusts are frequently prohibited from acquiring additional wells to replace production, unlike E&P companies and mineral aggregators. With production declining, the share price of trust units tends to decline as well, and the return comes almost exclusively from the dividend yield, with minimal opportunity for capital appreciation. Yield is dividends divided by price, and a declining denominator can lead to higher yields. As production declines, the yields may begin to shift from a reasonable expectation of the risk associated with expected future cash flows to a reflection of the minimal life of the well.Different Dividend Calculations Can Lead to Significantly Different IndicationsThe calculation of dividend yield can also be crucial to understanding risk. Taking the dividends paid in the past year may not be representative of future dividends. While annualizing the most recent dividend may cause issues with seasonality, it may be more appropriate given the commodity price outlook. Annualizing the most recent dividend causes a significant divergence in the implied yield for more than half of the royalty trusts, while the yields change by less than 2% for all of the mineral aggregators.Take Prudhoe Bay (BPT) for example. Its 63% yield as of October 30th includes a $1 dividend per share in January 2019. However, distributions have only been only $1.23 in the next three quarters combined as its 10-K estimated a significantly declining outlook. Annualizing the most recent dividend of 34 cents per share drops the dividend yield closer to 28%, notably lower than 63%. While 28% may seem high even in the context of mature production, current commodity prices indicate the trust may cease payouts after January 2020.  Calculating yields by annualizing more current dividends can help normalize yields to better indicate the underlying value of the trust’s production.Public Equity Markets May Complicate Intrinsic Value of Royalty TrustsIn theory, trading in a public marketplace gives public royalty trusts an indication of market value.  There is friction, however, between the stock market price and the intrinsic value of the trust. It is common for public royalty trusts to have relatively small share prices.  Also, as they age and decline over time, they will become less productive, and investors would be less likely to want to incur the trading costs to build up a position in a stock with little to no residual value. Investing in a small stock creates the need to load up on shares to make a meaningful investment. Doing so, however, can cause the price to move unfavorably. This is particularly the case if the stock is thinly traded.This problem can be compounded by float, that is, the number of shares actually available for trading. As an extreme example, Permianville Royalty Trust (PVL) has just over half of its shares free floating. These issues further complicate the ability to use yields from public royalty trusts as a proxy for risk for private interests.Operating Expenses Become Increasingly ImportantSince royalty trusts are not encumbered with production expenses, trust operating expenses tend to be fixed and minimal. However, revenue tends to be volatile with commodity prices. In the currently depressed commodity price environment, particularly for natural gas, these operating expenses become more pronounced. As we see with the SandRidge Trusts (SDT) (SDR) and ECA Marcellus Trust I (ECT), yields can be higher for trusts with higher operating expenses as a percentage of revenue. Lower prices make the sensitivity to operating expenses more apparent as margins are tighter.ConclusionWhen using it as a pricing benchmark for private royalty interests, there are many reasons to scrutinize the public royalty yields and their comparability. Further analysis is required to ensure these provide meaningful valuation indications.  It is important to assess the implied shelf life of the interest and stage of production. Yield also must be considered both in the context of historical and expected future dividends; they must also consider the equity market ecosystem in which the trusts trade. Lastly, yield and implied risk must consider the prevailing commodity price environment and its impact on royalty trust’s operating expenses.We have assisted many clients with various valuation and cash flow questions regarding royalty interests. Contact Mercer Capital to discuss your needs in confidence and learn more about how we can help you succeed.
Pipeline Bottlenecks And Worthless Acreage: The Downsides Of World-Leading Oil Production
Pipeline Bottlenecks And Worthless Acreage: The Downsides Of World-Leading Oil Production
Oil and gas production in the United States continues to grow. Last year a momentous occasion came and went when the U.S. unseated Russia and Saudi Arabia as the world’s leading oil producer on a daily production basis. The last time that happened was 1973, and a lot has changed since then. There were genuine concerns at the time that conventional oil recovery was at or near a peak. Back then, resources and drilling inventories were widely perceived as limited and thus investors paid a premium for companies that possessed more robust reserve reports while perceived demand for midstream assets waned. This has changed. Some side effects of this current market have included choke points in pipeline capacity and a precipitous drop in prices for undeveloped oil and gas acreage.While fracking techniques have existed in prior forms since the 1940s, the innovations in fracking technology have allowed companies to stimulate previously uneconomic wells. This revolutionized production and reframed mindset as to whether oil recovery was at a peak or not. In fact, production patterns improved so quickly over the past five years that infrastructure such as pipelines, processing and logistics has had trouble keeping up.The Bakken and Three Forks formations located in the Dakotas and Montana are a good example of this. For years, there has been a dearth of pipeline access to the formation and most of the oil produced has been transported out of the region by rail, a less efficient solution compared to pipelines. This issue has been even more acute for natural gas transportation. According to the EIA, in 2017 Bakken operators flared 88.5 billion cubic feet of gas, worth about $220 million and enough to heat 1 million homes.The Dakota Access Pipeline, which was much discussed in the news due to protests, opened in 2017 and is proposed to expand. It helped correct steep pricing differentials as compared to West Texas Intermediate crude pricing. There is still more to come (gas flaring is still prevalent), but constraints should lessen as time goes on.Another trend has been flagging prices for undeveloped acreage. We researched transaction data in the Bakken over the past two years and according to our research from the fourth quarter 2017 going into the fourth quarter 2019, average prices for acreage in the Bakken dropped from $14,250 per acre to $11,919 per acre. While limited in sample size, what’s particularly interesting about these statistics is that on a flowing barrel basis the average price for production increased ($53,338 per flowing barrel in the period entering the fourth quarter 2018 vs. $55,246 going into the fourth quarter 2019).[caption id="attachment_28685" align="aligncenter" width="640"]Source: Shale Experts[/caption] This indicates that current production valuations remain steady while acreage values for future production weaken. The explanation for this dynamic is layered yet connected, and it is not isolated to the Bakken area. At Hart Energy’s A&D Strategies and Opportunities Conference, industry participants emphasized a theme of seeking to buy current oil and gas production as opposed to longer term developmental acreage. This is a result of the capital discipline and returns that investors are demanding. Thus, with public markets struggling to show returns to many investors, acquisition and divestiture activity has slowed. The most prominent transaction oriented activity in the Bakken this year was ironically QEP’s decision to terminate a deal to sell its assets for $1.73 billion. Part of this is driven by public funding drying up. Some companies are turning to creative asset backed bonds to facilitate fundraising. This dearth of funding incentivizes investors to be particularly selective in their asset purchases and be more weighted to current returns. Thus, there is less capital available to invest in longer term drilling inventory. The valuation theory is straightforward: there is more sensitivity of the price paid today for drilling inventory that may not be monetized for 10 or 15 years or more from a net present value perspective. It’s not worth much in today’s dollars, and thus becomes challenging to justify the significant capital outlay considering alternative investments. Another factor driving declines in acreage values is large swaths of private equity backed properties that are considering monetizing their assets due to expiring fund holding periods. While perhaps up to $5 billion of non-operated oil and gas packages are potentially available in the Bakken, many aren’t currently transacting because of the low prices and wide bid-ask spreads. This may not last, and funds will eventually have to sell their assets. When that happens, acreage prices could drop even further if commodity prices or other fundamentals do not improve. It may not appear reasonable to some sellers, but it is fair in many buyers’ minds. It’s a somewhat unexpected side effect alongside a global shift in energy markets. Originally appeared on Forbes.com.
How to Perform a Purchase Price Allocation for an Oilfield Services Company
How to Perform a Purchase Price Allocation for an Oilfield Services Company
When performing a purchase price allocation for an oilfield services company, careful attention must be given to both the relevant accounting rules and the specific nuances of the oil and gas industry. Oilfield services companies can entail many unique characteristics that are not present in non-oilfield related businesses such as manufacturing, wholesale, non-energy related services, or retail.  Our senior professionals bring significant experience in performing purchase price allocations in the oilfield services area where knowledge of these characteristics is crucial to determining the proper allocation among the subject company’s assets.For the most part, current assets and current liabilities are relatively straight forward. The unique factors of an oilfield services company are found in the fixed assets and intangibles: specialized drilling and production equipment, service contracts, proprietary technology (patented, or unpatented), methods, or software, in-process research and development assets (IPR&D), etc.  In addition, the proper consideration of contributory asset charges in the appraisal of existing customer relationships or technology in the context of oilfield services companies requires a thorough understanding of how such contributory assets are utilized in generating the subject company’s expected operating results.  We will explore the unique factors in future entries. In this blog post, we discuss the guidelines for purchase price allocations that all companies must adhere.The unique factors of an oilfield services company are found in the fixed assets and intangibles.Reviewing a purchase price allocation report can be a daunting task if you don’t do it for a living – especially if you aren’t familiar with the rules and standards governing the allocation process and the valuation methods used to determine the fair value of intangible assets. While it can be tempting as a financial manager to leave this job to your auditor and valuation specialist, it is important to stay on top of the allocation process. Too often, managers find themselves struggling to answer eleventh-hour questions from auditors or being surprised by the effect on earnings from intangible asset amortization. This guide is intended to make the report review process easier while helping to avoid these unnecessary hassles.It should be noted that a review of the valuation methods and fair value accounting standards is beyond the scope of this guide. Grappling with these issues is the responsibility of the valuation specialist, and a purchase price allocation report should explain the valuation issues relevant to your particular acquisition. Instead, this guide focuses on providing an overview of the structure and content of a properly prepared purchase price allocation report.General GuidanceWhile every acquisition will present different circumstances that will impact the purchase price allocation process, there are a few general rules common to all properly prepared reports. From a qualitative standpoint, a purchase price allocation report should satisfy three conditions:The report should be well-documented. As a general rule, the reviewer of the purchase price allocation should be able to follow the allocation process step-by-step. Supporting documentation used by the valuation specialist in the determination of value should be clearly listed and the report narrative should be sufficiently detailed so that the methods used in the allocation can be understood.The report should demonstrate that the valuation specialist is knowledgeable of all relevant facts and circumstances pertaining to the acquisition. If a valuation specialist is not aware of pertinent facts related to the company or transaction, he or she will be unable to provide a reasonable purchase price allocation. If the report does not demonstrate this knowledge, the reviewer of the report will be unable to rely on the allocation.The report should make sense. A purchase price allocation report will not make sense if it describes an unsound valuation process or if it describes a reasonable valuation process in an abbreviated, ambiguous, or dense manner. Rather, the report should be written in clear language and reflect the economic reality of the acquisition (within the bounds of fair value accounting rules). This can be particularly daunting if the reviewer of the purchase price allocation report does not have significant experience in working with oilfield services industry participants.  The oilfield services industry is particularly strong in industry-specific terminology and jargon that can lead to a lack of understanding among purchase price allocation report reviewers that lack a deep industry background.Definition of AssignmentA purchase price allocation report should include a clear definition of the valuation assignment. For a purchase price allocation, the assignment definition should include:The definition of the valuation objective should specify the client, the acquired business, and the intangible assets to be valued.The purpose explains why the valuation specialist was retained. Typically, a purchase price allocation is completed to comply with GAAP financial reporting rules.Effective Date. The effective date of the purchase price allocation is typically the closing date of the acquisition.Standard of Value. The standard of value specifies the definition of value used in the purchase price allocation. If the valuation is being conducted for financial reporting purposes, the standard of value will generally be fair value as defined in ASC 820.Statement of Scope and Limitations. Most valuation standards of practice require such statements that clearly delineate the information relied upon and specify what the valuation does and does not purport to do.Background InformationThe purchase price allocation report should demonstrate that the valuation specialist has a thorough understanding of the acquired business, the intangible assets to be valued, the company’s historical financial performance, and the transaction giving rise to the purchase price allocation.Understanding of the BusinessThe purchase price allocation report should include a discussion related to the acquired company which demonstrates that the valuation specialist is knowledgeable of the company and has conducted sufficient due diligence for the valuation. The overview should also discuss any characteristics of the company that plays a material role in the valuation process. The description should almost always include discussion related to the history and structure of the company, the competitive environment, and key operational considerations.In the case of acquisitions within the oilfield services industry, the pertinent facts include a thorough understanding as to the demand for the subject company’s services across the various basins within the target market.  Unlike many other industries, oilfield services businesses may provide services that are specific to certain basins.  Therefore, expectations regarding the specific basins served may be of much greater importance than expectations for the overall oil and gas industry.Intangible AssetsThe discussion of the subject intangible assets should both provide an overview of all relevant technical guidance related to the particular asset and detail the characteristics of the assets that are significant to the valuation. The overview of guidance demonstrates the specialist is aware of all the relevant standards and acceptable valuation methods for a given asset.Upon reading this section, the reviewer of the purchase price allocation report should have a clear understanding of how the existence of the various intangible assets contribute to the value of the enterprise (how they impact cash flow, risk, and growth).Within the oilfield services industry, in particular, one may have to spend a significant amount of time in the determination of what intangible assets were acquired, what intangible assets should recognized as a separate asset from goodwill (based on the legal/contractual rights and separability considerations) and what intangible assets are likely to have a material value.  These can differ markedly across industries and such considerations can be somewhat unique in the oilfield services industry.Past PerformanceThe historical financial performance of the acquired company provides important context to the story of what the purchasing company plans to do with its new acquisition. While prospective cash flows are most relevant to the actual valuation of intangible assets, the acquired company’s historical performance is a useful tool to substantiate the reasonableness of stated expectations for future financial performance.The historical financial performance of the acquired company provides important context to the story.This does not mean that a company that has never historically made money cannot reasonably be expected to operate profitably in the future. It does mean that management must have a compelling growth or turn-around story (which the specialist would thoroughly explain in the company overview discussion in the report).Understanding an oilfield services company’s past financial performance requires knowledge of industry-specific trends that can impact activity levels, pricing for particular services, competing service providers, and profit margins.  The oilfield services industry is subject to potentially wide fluctuations in activity that can be driven by commodity prices and technological changes.  A thorough understanding of these dynamics is necessary in order to correctly interpret past performance among industry participants.Transaction OverviewTransaction structures can be complicated and specific deal terms often have a significant impact on value. Purchase agreements may specify various terms for initial purchase consideration, include or exclude specific assets and liabilities, specify various structures of earn-out consideration, contain embedded contractual obligations, or contain other unique terms. The valuation specialist must demonstrate a thorough understanding of the deal terms and discuss the specific terms that carry significant value implications.Determination of ValueThe purchase price allocation report should provide an adequate description of the valuation approaches and methods relevant to the project. In general, the report should outline the three approaches to valuation (the cost approach, the market approach, and the income approach), regardless of the approaches selected for use in the valuation. This demonstrates that the valuation specialist is aware of and considered each of the approaches in the ultimate selection of valuation methods appropriate for the given circumstances.Any of a number of valuation methods could be appropriate for a given intangible asset depending on the specific situation. While selection of the appropriate method is the responsibility of the valuation specialist, the reasoning should be documented in the report in such a way that a report reviewer can assess the valuation specialist’s judgment.In the closing discussion related to the valuation process, the report should provide some explanation of the overall reasonableness of the allocation. This part of the purchase price allocation report should include both a qualitative assessment and quantitative analysis for support. While this support will differ depending on circumstances, the report should adequately present how the valuation “hangs together.”Within the oilfield services industry determination as to the reasonableness of the indicated allocation of value (purchase price) is often a factor of whether the subject company’s services are subject to proprietary technology, the level of fixed assets required to provide the subject company’s services and the level of personal interaction with customers.  Based on such factors, the allocation of value might be reasonably expected to be skewed to particular types of assets, with higher, or lower, expected levels of goodwill.Keep in Mind, it’s Not a BlackboxA purchase price allocation is not intended to be a black box that is fed numbers and spits out an allocation. The fair value accounting rules and valuation guidance require that it be a reliable and auditable process so that users of financial statements can have a clear understanding of the actual economics of a particular acquisition. As a result, the allocation process should be sufficiently transparent that you are able to understand it without excessive effort, and the narrative of the report is a necessary component of this transparency.
M&A in the Bakken
M&A in the Bakken

Deals May Be Slow, But Production Remains Steady

Acquisition and divestiture activity in the Bakken for last twelve months has been minimal. The lack of deals, however, does not mean that activity or production hasn’t been meaningful. In fact, as mentioned in our most recent post, production has grown approximately 10% year-over-year through September with new well production per rig increasing over 29%. Also, while other major basins have been decreasing rig counts, the Bakken has remained steady year-over-year as of the end of September.While the fundamentals of this basin are strong, relatively few companies remain interested. As such, deal activity has largely involved the familiar faces in the region. Companies with smaller positions in the region have continued to divest “non-core” positions as they focus their efforts in other regions.  Contrast this trend to the controlling acquisitions or takeovers like those that have been popular in the Permian.Recent Transactions in the BakkenDetails of recent transactions in the Bakken, including some comparative valuation metrics, are shown below.Balance Sheet Cleanup: Whiting and AbraxasA recurring theme observed throughout the year in multiple basins has been the optimization of assets. The theme continues in the Bakken for 2019 as transactions in the basin have primarily consisted of offloading portions of non-operated assets, the largest of which was the deal with Whiting Petroleum and an undisclosed buyer for $53 million. However, Whiting remains the third largest holder of net acreage in the basin.Abraxas Petroleum also sold approximately $16 million in non-operated assets in June. These assets were not part of Abraxas’ core Williston position. However, Abraxas appears to be open to conversations with parties interested in acquiring both operated and non-operated assets, as the company is seemingly in deal talks with Whiting Petroleum.Given the age of the basin and smaller number of players, consolidation and strategic deals between operators have been prevalent. Several players have left the Bakken for the Permian, and as a result, the top five net acreage holders account for roughly half of the existing operating acreage in the basin. Abraxas undertook a sizable debt load in 2018 to finance further capital expenditures and restructure debt maturities ($180 million due in 2020-20211).  An exit from the Bakken to pay down its debt and expand their Permian operations does not seem unreasonable.Continued Non-Operator Acquisitions: Northern Oil and GasSimilar to trends observed in the Bakken last year, acquisitions by non-operators have continued into 2019. For instance, Northern Oil and Gas has made several deals in the basin and its acquisition of private equity-backed Flywheel Energy LLC in April 2019 was one of the largest of the year, and represents a continuance of this trend.Northern Oil and Gas has been the basin’s most consistent acquirer of non-operating interests. As a nonoperator, Northern can enjoy cash flows received from acreage without the operator risk that has become ever more prevalent in the current environment, and consequently, the company has the luxury of continuing to strategically consolidate acreage in the basin. Since the start of 2018, the company has made four large publicly announced transactions totaling more than $820 million.Below is a map of the acreage Northern Oil and Gas acquired in the Flywheel transaction as well existing acreage to show its overall footprint in the basin.ConclusionEven though transaction activity in the Bakken has been minimal compared to basins like the Permian, production is up, and rig counts are steady. Acquisitions for operators and non-operators alike have been strategic and pinpointed as the experienced players look to build and maintain their large positions relative to others in the area. Despite a slowdown of A&D activity in the back half of 2019, the operators and non-operators in the Bakken appear undeterred and are staying the course.We have assisted many clients with various valuation needs in the upstream oil and gas industry in North America and around the world.  In addition to our corporate valuation services, Mercer Capital provides investment banking and transaction advisory services to a broad range of public and private companies and financial institutions.  We have relevant experience working with companies in the oil and gas space and can leverage our historical valuation and investment banking experience to help you navigate a critical transaction, providing timely, accurate and reliable results.  Contact a Mercer Capital professional to discuss your needs in confidence.1 Abraxas Petroleum Corporation Annual Report December 31, 2018
Bakken May Lack Flash, But Has Fundamentals
Bakken May Lack Flash, But Has Fundamentals
The economics of oil and gas production vary by region. Mercer Capital focuses on trends in the Eagle Ford, Permian, Bakken, and Appalachia plays. The cost of producing oil and gas depends on the geological makeup of the reserve, depth of reserve, and cost to transport the raw crude to market. We can observe different costs in different regions depending on these factors. In this post, we take a closer look at the Bakken Shale.Production and Activity LevelsBakken production grew approximately 10% year-over-year through September.  While this growth rate lags behind the Permian, it is in line with production growth in Appalachia and meaningfully bests the Eagle Ford. The rig count in the Bakken at the end of September was unchanged from the year prior at 53.  While not impressive at first glance, the total U.S. rig count declined nearly 20% over the same period.  Eagle Ford, Permian, and Appalachia rig counts declined 22%, 15%, and 17%, respectively. The Bakken has also seen the biggest gain in new-well production per rig relative to our other coverage basins.  While this metric doesn’t cover the full life cycle of a well, it is a signal of the increasing efficiency of operators in the area.  New well production per rig in the Bakken increased 29% on a year-over-year basis through September, compared to increases of 2%, 12%, and 7% in the Eagle Ford, Permian, and Appalachia, respectively. Financial PerformanceBakken E&P operator financial performance was a mixed bag over the past year.  Canada’s Crescent Point Energy (CPG) was the only positive performer of the Bakken-focused operators, up 23% year-over-year through September.   While down 16%, Hess outperformed the broader S&P Oil & Gas Exploration & Production Index (XOP).  However, this was likely attributable (at least in part) to positive developments out of Guyana, where Hess has a 30% interest in the massive Stabroek block.  The Stabroek block is one of the largest offshore oil discoveries in the past decade, with more than 6 billion boe of discovered, recoverable resource. Continental, Whiting, and Oasis all unperformed the broader E&P index during the past year, with Whiting down a notable 85%.  Oasis is funding its Permian development program with cash flows generated from its Bakken position, a strategy that has fallen out of favor with investors who now seek capital discipline and free cash flow generation.  Whiting is down largely on concerns regarding leverage and inventory life.  All three saw margin compression, with Whiting’s EBITDAX per boe down nearly 30% year-over-year. Despite this financial performance, the Bakken hasn’t been impacted by the recent batch of bankruptcies that have afflicted the Mid-Con (Alta Mesa, White Star), Eagle Ford (Sanchez, EP Energy), and even the Permian (Halcon).  However, Whiting did announce a major restructuring in which it will terminate 254 positions (around one-third of the company’s workforce).  As a result, the company anticipates approximately $50 million in annual savings. Commodity Prices Largely Unchanged in Aftermath of Saudi AttackOn September 14, a missile attack on Saudi Arabian oil production facilities took out 5.7 million barrels a day of production, amounting to about 5% of global production.  Both WTI and Brent crude prices surged more than 10% in the immediate aftermath of the attack. However, the price reaction was short-lived, as the Saudis were able to bring 2 million bbl/d of production back online within days, with the remainder expected to be back online within weeks.  WTI and Brent prices ended September lower than on the day prior to the attack. Realized pricing in the Bakken has improved markedly relative to last fall, when a combination of Midwest refinery turnarounds and a glut of Canadian production sent the Clearbrook Bakken / WTI differential to more than $20/bbl.  At the end of September, the differential stood at approximately $2.50/bbl.  While thinly traded, basis futures indicate expected differentials of $2.50 to $4.30/bbl over the next several years. Infrastructure IssuesThe Dakota Access Pipeline largely alleviated crude takeaway constraints out of the basin.  And with a proposed expansion of the pipeline, the announced Liberty Pipeline, and excess crude-by-rail capacity, E&P operators likely won’t have issues getting crude to end markets.However, both Whiting and Oasis indicated that issues with natural gas processing infrastructure adversely impacted performance during the quarter.In the Q2 earnings call, Whiting CEO Brad Holly stated,To minimize flaring, we are producing some wells at constrained oil rates, while we focus on increasing gas capture through the installation of mobile combustion units, building out gathering systems, and completing our ray gas processing plant. Constraints also impacted the pace of planned operating activity.Oasis CEO Tommy Nusz put a finer point on his commentary, specifically stating that downtime at the company’s Wild Basin gas complex reduced 2Q19 production by 3,000 boe/d.These constraints should moderate, though, as additional natural gas infrastructure comes online in late 2019 and early 2020.MLP Simplification Trend ContinuesThe recent trend of MLP simplifications, driven in part by tax reform, FERC policy changes, cost of capital considerations, and a desire to reach a broader investor base, continues.  Hess Midstream Partners (HESM) announced that it is acquiring Hess Infrastructure Partners (HIP) in a $6.2 billion transaction.  HIP owns HESM’s General Partner (GP) units and Incentive Distribution Rights (IDRs), as well as an 80% interest in HESM’s oil and gas midstream assets.  Unlike most simplifications that have occurred once GP/IDR distributions are “high in the splits” (with the GP/IDR holder typically taking 50% of incremental distributions above a certain threshold), HESM was only at the 25% split level.Fellow Bakken midstream operator Oasis Midstream Partners remains on a rapidly shortening list of MLPs that still have IDRs.ConclusionNow that the Bakken’s crude infrastructure issues have been (somewhat) resolved, the basin has seemed to take a backseat to other areas in terms of news coverage and investor attention.  While the Bakken hasn’t kept up with the Permian’s growth, its static (rather than declining) rig count, higher oil to gas ratio, and sufficient crude takeaway capacity bode well for the basin relative to its domestic counterparts.We have assisted many clients with various valuation needs in the upstream oil and gas space in both conventional and unconventional plays in North America, and around the world.  Contact a Mercer Capital professional to discuss your needs in confidence and learn more about how we can help you succeed.
The Fair Market Value of Oil & Gas Reserves
The Fair Market Value of Oil & Gas Reserves
Due to the historical popularity of this post, we revisit it this week. Originally published in 2017, this post helps you, the reader, understand how to determine the fair market value of oil and gas reserves. Oil and gas assets represent the majority of value of an E&P company. The Oil and Gas Financial Journal describes reserves as “a measurable value of a company's worth and a basic measure of its life span.”  Thus, understanding the fair market value of a company’s PDP, PDNP, and PUDs is key to understanding the fair market value of the Company.  As we discussed before, the FASB and SEC offer reporting guidelines regarding the disclosure of proved reserves, but none of these represent the actual market price.  It is especially important to understand the price one can receive for reserves as many companies have recently sold “non-core” assets to generate cash to pay off debt and fund operations. The American Society of Appraisers defines the Fair market value as:The price, expressed in terms of cash equivalents, at which property would change hands between a hypothetical willing and able buyer and a hypothetical willing and able seller, acting at arm’s length in an open and unrestricted market, when neither is under compulsion to buy or sell and when both have reasonable knowledge of the relevant facts.1The American Society of Appraisers recognizes three general approaches to valuation: (1) The Cost Approach, (2) The Income Approach, and (3) The Market Approach.  The IRS provides guidance in determining the fair market value of an oil and gas producing property.  Treasury Reg. 1.611–2(d) offers that if possible the cost approach or comparative sale approach should be used before a discounted cash flow analysis (DCF).  When valuing acreage rights comparable transactions do provide the best indication of value.  However, when valuing reserves, a DCF is often the best way to allocate value to different reserve categories because comparable transactions are very rare as the details needed to compare these specific characteristics of reserves are rarely disclosed.Cost ApproachThe cost approach determines a value indication of an asset by considering the cost to replicate the existing operations of an asset. The cost approach is used when reserves have not been proved up and there have been no historical transactions, yet a participant has spent significant time, talents, and investments into exploratory data on an oil and gas prospect project.Market ApproachThe market approach is a general way of determining a value indication of an asset by using one or more methods that compare the subject to similar assets that have been sold.Because reserve values vary between oil and gas plays and even within a single play, finding comparable transactions is difficult. A comparable sale must have occurred at a similar time due to the volatile nature of oil and gas prices.  A comparable sale should be for a property that is located within the same play and within a field of similar maturity.  Additionally, comparable transactions must be thoroughly analyzed to make sure that they were not transacted at a premium or discount due to external factors.  Thus, the market approach is often difficult to perform because true comparable transactions are rare. However, the transaction method generally provides the best indication of fair market value for acreage and lease rights.Income ApproachThe income approach estimates a value indication of an asset by converting anticipated economic benefits into a present single amount.  Treasury Reg 1.611 – 2(e)(4) provides a straightforward outline of how the approach should be used.In practice, this method requires that: The appraiser project income, expense, and net income on an annual basisEach year's net income is discounted for interest at the "going rate" to determine the present worth of the future income on an annual and total basisThe total present worth of future income is then discounted further, a percentage based on market conditions, to determine the fair market value. The costs of any expected additional equipment necessary to realize the profits are included in the annual expense, and the proceeds of any expected salvaged of equipment is included in the appropriate annual income. Although the income approach is the least preferred method of the IRS, these techniques are generally accepted and understood in oil and gas circles to provide reasonable and accurate appraisals of hydrocarbon reserves, and most closely resembles the financial statement reporting requirements discussed in our previous post.  This method is the best indication of value when a seismic survey has been performed and reliable reserve estimates are available.  In order to properly account for risk, we divide the reserves by PDP, PDNP, PUD, Probable, and Possible reserves.  We will review the key inputs in a DCF analysis of oil and gas reserves below.Cash InflowsIn order to estimate revenue generated by an oil and gas reserve, we must have an estimate of production volume and price.  Estimates of production are collected from Reserve reports which are produced by geological engineers.The forward price curve provides monthly price estimates for 84 months from the current date.  Generally, the price a producer receives varies with the price of benchmark crude such as WTI or Brent. Thus, it is important to carefully consider a producers contract with distributors. For example, a company may sell raw crude to the distributor at 65% of Brent.Cash OutflowsMany E&P companies do not own the land on which they produce. Instead, they pay royalty payments to the land owner as a form of a lease payment.  Royalty payments are generally negotiated as a percentage of the gross or net revenues derived from the use of the property.  Besides royalty payments and daily operating costs, it is important to have conversations with management to understand future infrastructure maintenance and capital expenditures.DiscountOil and gas reserves can be based on pre-tax or after-tax cash flows.  Pre-tax cash flows make reserve values more comparable as tax rates vary by location.  When using pre-tax cash flows, we use a pre-tax cost of debt and pre-tax cost of equity to develop a WACC.Risk Adjustment FactorsWhile DCF techniques are generally reliable for proven developed reserves (PDPs), they do not always capture the uncertainties and opportunities associated with the proven undeveloped reserves (PUDs) and particularly are not representative of the less certain upside of the Probable and Possible reserve categories.  A risk adjustment factor could be used to the discounted present value of cash flows according to the category of the reserves being valued to account for PUDs upside and uncertainty by reducing expected returns from an industry weighted average cost of capital (WACC).  You could also add a risk premium for each reserve category to adjust a baseline WACC, or keep the same WACC for all reserves but discount the present value of the cash flows accordingly with comparable discounts to those shown below. The low oil price environment forced many companies to sell acreage and proved reserves in order to generate cash to pay off debt.  In order to create a new business models in the face of low oil prices, it is critical for companies to understand the value of their assets.  The valuation implications of reserves and acreage rights can swing dramatically in resource plays. Utilizing an experienced oil and gas reserve appraiser can help to understand how location impacts valuation issues in this current environment. Contact Mercer Capital to discuss your needs and learn more about how we can help you succeed. End Notes1 American Society of Appraisers, ASA Business Valuation Standards© (Revision published November 2009), “Definitions,” p. 27.
EP Fourth Quarter 2019 Region Appalachia
E&P Fourth Quarter 2019

Region: Appalachia

Region Focus: Appalachia // Crude prices steadily increased from $54 per barrel at the beginning of October to $61 at the close of 2019.
Do Oil And Water Mix? The Biggest Energy IPO Of 2019 Might Answer That Question
Do Oil And Water Mix? The Biggest Energy IPO Of 2019 Might Answer That Question
The capital markets in the upstream sector are leaving companies and investors in the lurch right now. Compared to 2018, equity and debt issuances have declined markedly and IPO’s in the sector have been relatively quiet apart from Brigham Minerals’ successful offering.[caption id="attachment_28082" align="alignnone" width="717"]Source: Shale Experts[/caption] Saltwater disposal and integrated water logistics companies have attracted a higher proportion of the sparsely available capital flowing into the sector, highlighted by the largest energy IPO of this year: Rattler Midstream LP. The continuing austerity trend toward cash flow sustainability for shale oil companies has provided limited attractive options for investors. In the meantime, drilling activity (particularly in West Texas) continues to grow, and therefore efficiency and scale grow ever more important across the board for upstream companies to remain competitive. One of the challenges producers face is handling the enormous amounts of water that have become part and parcel to the Delaware and Midland Basins. This is where saltwater disposal enters the picture. A horizontal well in the Delaware Basin can average four barrels (sometimes even up to 10 barrels) of water for every barrel of oil produced. Once produced, all that water must go somewhere and that somewhere is a saltwater disposal well. This is no new phenomenon as produced water has been an element of production for over 70 years. What is different in the Permian Basin is the higher ratio of water to oil (often called a “water cut”) that’s produced due to the native geology and today’s production techniques. Today’s U.S. oilfield water production is already around a colossal 50 million barrels a day. This contrasts with the U.S. producing only 15 million barrels of petroleum liquids every day. Most of that water is produced in the Permian Basin and there’s only going to be more of it. Much more. That’s to say nothing of the amount of water needed to fracture the rock during the production process. In a recent Raymond James research report, the authors noted that each well completion uses thirty Olympic swimming pools worth of water. [caption id="attachment_28080" align="alignnone" width="640"]Source: EIA, Drilling Info, Baker Hughes, Raymond James Research [/caption] This water needs to be transported, sometimes long distances, and logistically managed. This function is trending towards consolidation whereby a single entity combines these assets and services. Until the past couple of years there was very little aquatic pipeline infrastructure. Most was handled by trucking, but that is changing as increasing volumes are raising scrutiny on the inefficiency of trucking. Growing demand in West Texas has opened up an estimated $12 billion-dollar market potential in the Permian Basin alone, according to Raymond James. Fees for transporting and disposing produced water typically range from $0.50 to $2.50 per barrel. In addition, there is skimmed oil that can be gathered as well. However, where long distances stand between a production site and disposal infrastructure it can creep up to $4.00 to $6.00 per barrel. In today’s commodity price environment and focus on break-even prices, every dollar per barrel counts. Thus, there is a real incentive to improve infrastructure and push service costs lower. The investment merits of this water infrastructure include the opportunity for more steady business; with long term contracts tied to dedicated acreage, and stable cash flows that can fetch higher valuations than even some of the shale producers themselves in the region. It has been noted that some producers cannot begin drilling in certain areas until the water infrastructure is in place. In addition, there are consolidation opportunities for more fragmented business models between saltwater disposal facilities, equipment rental companies and pipeline companies. More integrated firms that combine these services will function more like traditional midstream operators. The trend has already begun and is being seen in valuations already. Rattler’s $765 million IPO opened at over 18 times EBITDA and recent water driven asset sales have traded between five- and ten-times EBITDA. For example, private equity backed WaterBridge purchased $325 million of Delaware Basin assets (assuming earnouts are paid) from Halcon Resources at an implied 14.5x trailing EBITDA multiple. Firms like NGL Energy Partners and EVX Midstream are also active in the space. Additionally, the opportunity for yield (which energy investors are craving) in the future can be more demonstrable than many upstream opportunities in the oil patch. [caption id="attachment_28081" align="alignnone" width="640"]Source: Company Filings. WaterBridge transaction assumes earnouts. Rattler transaction assumes total units outstanding not just traded ones.[/caption] Amid this activity, landowners are also finding another source of income from royalties stemming from new pipeline and below ground storage rights as well, leading to more local income for ranchers and residents as well as another potential asset base for mineral aggregators and related investors to pursue. Oil and water do appear to mix, and energy bankers will be glad to know they do because it is filling gaps for an otherwise tight capital market space. Originally appeared on Forbes.com.
How to Perform a Purchase Price Allocation for an E&P Company
How to Perform a Purchase Price Allocation for an E&P Company
This guest post first appeared on Mercer Capital’s Financial Reporting Blog on January 18, 2016.  When performing a purchase price allocation for an Exploration and Production (E&P) company, careful attention must be paid to both the accounting rules and the specialty nuances of the oil and gas industry. E&P companies are unique entities compared to traditional businesses such as manufacturing, wholesale, services or retail. As unique entities, the accounting rules have both universal rules to adhere as well as industry specific. Our senior professionals bring significant experience in performing purchase price allocations in the E&P area where these two principles collide. For the most part, current assets, current liabilities are straight forward. The unique factors of an E&P are found in the fixed assets and intangibles: producing, probable and possible reserves, raw acreage rights, gathering systems, drill rigs, pipe, working interests, royalty interests, contracts, hedges, etc. Different accounting methods like the full cost method or the successful efforts method can create comparability issues between two E&P’s that utilize opposite methods. We will explore the unique factors in future entries. In this blog post, we discuss the guidelines for purchase price allocations that all companies must adhere.Reviewing a purchase price allocation report can be a daunting task if you don’t do it for a living – especially if you aren’t familiar with the rules and standards.Reviewing a purchase price allocation report can be a daunting task if you don’t do it for a living – especially if you aren’t familiar with the rules and standards governing the allocation process and the valuation methods used to determine the fair value of intangible assets. While it can be tempting as a financial manager to leave this job to your auditor and valuation specialist, it is important to stay on top of the allocation process. Too often, managers find themselves struggling to answer eleventh-hour questions from auditors or being surprised by the effect on earnings from intangible asset amortization. This guide is intended to make the report review process easier while helping to avoid these unnecessary hassles.Please note that a review of the valuation methods and fair value accounting standards is beyond the scope of this guide. Grappling with these issues is the responsibility of the valuation specialist, and a purchase price allocation report should explain the valuation issues relevant to your particular acquisition. Instead, this guide focuses on providing an overview of the structure and content of a properly prepared purchase price allocation report.General RulesWhile every acquisition will present different circumstances that will impact the purchase price allocation process, there are a few general rules common to all properly prepared reports. From a qualitative standpoint, a purchase price allocation report should satisfy three conditions:The report should be well-documented. As a general rule, the reviewer of the purchase price allocation should be able to follow the allocation process step-by-step. Supporting documentation used by the valuation specialist in the determination of value should be clearly listed and the report narrative should be sufficiently detailed so that the methods used in the allocation can be understood.The report should demonstrate that the valuation specialist is knowledgeable of all relevant facts and circumstances pertaining to the acquisition. If a valuation specialist is not aware of pertinent facts related to the company or transaction, he or she will be unable to provide a reasonable purchase price allocation. If the report does not demonstrate this knowledge, the reviewer of the report will be unable to rely on the allocation.The report should make sense. A purchase price allocation report will not make sense if it describes an unsound valuation process or if it describes a reasonable valuation process in an abbreviated, ambiguous, or dense manner. Rather, the report should be written in clear language and reflect the economic reality of the acquisition (within the bounds of fair value accounting rules).Assignment DefinitionA purchase price allocation report should include a clear definition of the valuation assignment. For a purchase price allocation, the assignment definition should include:Objective. The definition of the valuation objective should specify the client, the acquired business, and the intangible assets to be valued.Purpose. The purpose explains why the valuation specialist was retained. Typically, a purchase price allocation is completed to comply with GAAP financial reporting rules.Effective Date. The effective date of the purchase price allocation is typically the closing date of the acquisition.Standard of Value. The standard of value specifies the definition of value used in the purchase price allocation. If the valuation is being conducted for financial reporting purposes, the standard of value will generally be fair value as defined in ASC 820.Statement of Scope and Limitations. Most valuation standards of practice require such statements that clearly delineate the information relied upon and specify what the valuation does and does not purport to do.Background InformationThe purchase price allocation report should demonstrate that the valuation specialist has a thorough understanding of the acquired business, the intangible assets to be valued, the company’s historical financial performance, and the transaction giving rise to the purchase price allocation.Company OverviewDiscussion related to the acquired company should demonstrate that the valuation specialist is knowledgeable of the company and has conducted sufficient due diligence for the valuation. The overview should also discuss any characteristics of the company that play a material role in the valuation process. The description should almost always include discussion related to the history and structure of the company, the competitive environment, and key operational considerations.Intangible AssetsThe intangible assets discussion should both provide an overview of all relevant technical guidance related to the particular asset and detail the characteristics of the asset that are significant to the valuation. The overview of guidance demonstrates the specialist is aware of all the relevant standards and acceptable valuation methods for a given asset.After reading this section, the reviewer of the purchase price allocation report should have a clear understanding of how the existence of the various intangible assets contribute to the value of the enterprise (how they impact cash flow, risk, and growth).Historical Financial PerformanceThe historical financial performance of the acquired company provides important context to the story of what the purchasing company plans to do with its new acquisition. While prospective cash flows are most relevant to the actual valuation of intangible assets, the acquired company’s historical performance is a useful tool to substantiate the reasonableness of stated expectations for future financial performance.This does not mean that a company that has never historically made money cannot reasonably be expected to operate profitably in the future. It does mean that management must have a compelling growth or turn-around story (which the specialist would thoroughly explain in the company overview discussion in the report).Transaction OverviewTransaction structures can be complicated and specific deal terms often have a significant impact on value. Purchase agreements may specify various terms for initial purchase consideration, include or exclude specific assets and liabilities, specify various structures of earn-out consideration, contain embedded contractual obligations, or contain other unique terms. The valuation specialist must demonstrate a thorough understanding of the deal terms and discuss the specific terms that carry significant value implications.Fair Value DeterminationThe report should provide adequate description of the valuation approaches and methods relevant to the purchase price allocation. In general, the report should outline the three approaches to valuation (the cost approach, the market approach, and the income approach), regardless of the approaches selected for use in the valuation. This demonstrates that the valuation specialist is aware of and considered each of the approaches in the ultimate selection of valuation methods appropriate for the given circumstances.The report should outline the three approaches to valuation, regardless of the approaches selected for use in the valuation.Depending on the situation, any of a number of valuation methods could be appropriate for a given intangible asset. While selection of the appropriate method is the responsibility of the valuation specialist, the reasoning should be documented in the report in such a way that a report reviewer can assess the valuation specialist’s judgment.At the closing of the discussion related to the valuation process, the report should provide some explanation of the overall reasonableness of the allocation. This discussion should include both a qualitative assessment and quantitative analysis for support. While this support will differ depending on circumstances, the report should adequately present how the valuation “hangs together.”Something to RememberA purchase price allocation is not intended to be a black box that is fed numbers and spits out an allocation. The fair value accounting rules and valuation guidance require that it be a reliable and auditable process so that users of financial statements can have a clear understanding of the actual economics of a particular acquisition. As a result, the allocation process should be sufficiently transparent that you are able to understand it without excessive effort, and the narrative of the report is a necessary component of this transparency.
Themes from Q2 2019 Earnings Calls
Themes from Q2 2019 Earnings Calls

Will “Capital Efficiency” Prevent Bankruptcy and Maintain Production as E&P’s Reduce CapEx?

While large, rapid commodity price declines are certainly harmful for near-term profits and long-term planning, persistently low prices may be more ominous for industry operators and investors. Prices rebounded from a low of $45/bbl, but crude has been below $60 for nearly 3 months. Natural gas prices have similarly languished, remaining below $2.50/mmbtu in that time. Two Houston-based E&P companies (Halcon & Sanchez) recently filed for Chapter 11 bankruptcy within days of each other, raising questions about the state of the industry. Size and operational efficiency may enable some players to stave off issues, while others may be forced into difficult decisions between preserving capital and investing over budget to produce enough debt-servicing cash flow.Theme 1: Bankruptcies May Return if Prices Remain Low Over the last year, we have taken proactive steps to address the challenging oil and natural gas price environment, including stabilizing our production profile, improving our capital efficiency, and reducing our overall cost structure. Undergoing a financial restructuring through a voluntary process represents the next phase for Sanchez Energy, as we work with our creditors on a plan to right-size our balance sheet, further invest in our assets and generate long-term value for our stakeholders. - Tony Sanchez III, CEO, Sanchez EnergyRagan [incoming CFO] is joining Halcon at a critical time [bankruptcy restructuring] and will help lead our focus on capital discipline, cost control, and strategic plans for developing the Company’s assets to maximize shareholder return. - Rich Little, CEO, Halcon Resources We start with quotes from companies that didn’t actually host earnings calls. Sanchez Energy has been beleaguered for years now, unable to turn a profit since the drop in oil prices. Once the third most active driller in the Eagle Ford, Sanchez filed for Chapter 11 bankruptcy on August 11th. Sanchez’ CEO touches on capital efficiency like many executives in the industry, as we’ll address later. He also harps on generating long-term value for stakeholders, a slight twist on the predictable “providing long-term value to shareholders” due to their debt-laden predicament. Sanchez certainly isn’t alone. Halcon Resources filed for bankruptcy on August 7th. However, the company expects a 60-day turn around, during which it will continue to pay vendors, royalty owners, and others as part of ordinary business through the bankruptcy process, subject to approval from the courts. This is the second time since 2016 that the company has buckled under its debt load. The Sanchez quote came as part of its press release regarding the bankruptcy proceedings, and the Halcon quote addresses the hiring of a new CFO in the wake of its filing. Each CEO outlines a critical issue for industry operators. Large scale, multi-year projects employ debt financing to lower the cost of capital, but too much debt can raise the cost of capital due to the increased risk of making the required payments. Fluctuating commodity prices further hamper the ability of E&P companies to make these payments. When companies are forced to file for Chapter 11 bankruptcy, they are usually able to resume operations, though the shareholders essentially lose all, or a substantial portion, of their investment. Industry operators will hope that these low prices will not persist, or other companies may join Sanchez and Halcon.Theme 2: Size MattersWe have a very large footprint though that allows us to work within certain areas over a vein, within certain areas due to these [Bakken gas processing] constraints. So we are able to work around them. And we have led the industry up there with gas capture we still do. - Harold Hamm, CEO, Continental ResourcesCombining Oxy and Anadarko will create a diverse portfolio of high quality and complementary assets, well suited for our core competencies. As we apply our development approach to the combined portfolio, we expect this to be the low-cost producer in all of the areas we operate. For example, along with the expertise I've already mentioned, we will apply our proprietary drilling process, Oxy drilling dynamics across Anadarko acreage. To date, Oxy drilling dynamics has reduced costs by at least 30% in all of the areas that we've applied it, and we expect to achieve similar results in Anadarko’s onshore and offshore developments. - Vicki Hollub, CEO, Occidental PetroleumOne final point on our pending acquisition of Carrizo and one of the most important aspects of the transaction is the ability to optimize long-term development value of our combined inventory. By merging these two companies we are creating a vehicle that can effectively compete in a lower commodity price environment without the need to high-grade near-term target zones at the expense of other zones that are left behind for less efficient future development after the passage of time. - Joseph Gatto, CEO, Callon Petroleum Size allows companies to achieve scale in their operations, spread expenses over larger amounts of revenue, access capital markets, and even negotiate lower capital costs. Larger E&P companies are typically less at risk of bankruptcy than smaller players in the industry. Chevron began the quarter with its announcement of plans to acquire Anadarko Petroleum, but Occidental stepped up with a larger offer and eventually won the day. While this transaction has stolen the headlines, Callon’s smaller acquisition of Carrizo after quarter-end echoes the trend in the industry. Size allows these companies to achieve synergies, apply techniques to more acreage, and survive in low-price environments.Theme 3: Capital Efficiency to Bridge Gap Between Production Estimates and CapEx BudgetsWe have also achieved the efficiencies throughout the first-half of 2019 that will allow the reduction of drilling rigs from 19 rigs in SCOOP STACK to 12 rigs on early fourth quarter of 2019. […] I am proud that our teams can exceed production estimates with lower rig activity, that is operating and capital efficiency at its best. […] We're very committed to meeting our CapEx and other corporate guidance for the year, and have the flexibility to do so as we're demonstrating. - Harold Hamm, CEO, Continental ResourcesFor two quarters in a row we delivered more oil for less capital. With efficiency gains and new technology, we are achieving strong capital and operating cost reductions, while at the same time delivering excellent well performance. […] Looking ahead to the remainder of 2019, we modestly increased our full year U.S. oil production guidance as a result of better well performance. There is no change to our activity level in 2019. We will remain disciplined and still expect capital expenditures to be within the original range of $6.1 billion and $6.5 billion. - Bill Thomas, Chairman/CEO, EOG ResourcesTowards the end of the quarter, we shifted our focus to the completion of our first Delaware mega pad, which importantly utilized a simultaneous operation of two completion crews to increased efficiency and reduced cash cycle times. As we've emphasized previously, increased use of this model is made possible within a larger entity and is a clear strategic benefit of the Carrizo merger. - Joseph Gatto, CEO, Callon Petroleum Shale oil production has increased output, and U.S. E&P companies have provided much of the supply growth in global production. However, shale’s inherently higher declines rates require more drilling to replace more rapidly declining production, making investors wary to receive their share (dividends) of the returns on these investments. This, in combination with depressed commodity prices at year-end, led to lower capex budgets for 2019. Seeking to keep their promises after blowing through their budgets last year, E&P companies have preached capital efficiency. They tout the operational efficiencies that will allow them to decrease their capital spend to close 2019. These efficiencies are crucial because according to data compiled by Shale Experts (subscription required) in the below table, many E&P companies have already spent over half their budget. There are many factors at play in this number. Capex can and tends to be frontloaded due to seasonal factors. Still, executives will be hoping that their drilling efficiencies are achieved. Some companies may find issues hitting their production targets while decelerating drilling activities. They may be stuck between a rock and a hard place: failing to reach production targets or failing to remain within capex budgets. Theme 4: Parent-Child Problem Continues to Plague OperatorsIn the Delaware Basin, the 23 well Dominator project was designed to test logistical capabilities and well spacing that was approximately 50% tighter than our current resource assessment. While initial rates were solid, current performance data indicates that we developed the Upper Wolfcamp too densely. We're incorporating the data into our development model to adjust spacing on future projects including those projects set to spud in the second half of 2019. -Tim Leach, CEO, Concho ResourcesWe've always been conservative in our spacing assumptions, and we don't really have any plans right now, especially as commodity price continues to decline, to look at any reasons to increase well spacing. This is one of those things where we've been pretty steadfast in our strategic development objectives on spacing. And we would pay attention to other spacing results that go on in the Permian Basin. And we try to learn from those as well too without exposing our shareholders to down spacing risks. -Travis Stice, CEO, Diamondback Energy As we noted earlier, E&P companies are always looking to gain efficiencies. This can come from strategic M&A, contiguous acreage, repeatable drilling methods, and many other sources. However, there are limits. Specifically, well spacing has become increasingly important in the Permian as the parent-child problem continues to plague operators. Stated plainly, the first well drilled in a pad (the “parent”) tends to be the strongest well, getting the most bang for your buck in the reservoir. Subsequent wells drilled in the pad (the “children”) allow for more oil to be harvested quickly but at a decreasing rate per well. Trying to fit more wells onto pads may be more efficient from a drilling standpoint, but geological factors tend to lead to diminishing marginal returns from this approach. As Concho’s CEO admitted at the beginning of the earnings call, their Dominator project was not properly spaced. This news was not well received, as Concho’s stock dropped 22.2% on the day and has slid even further since. It appears Diamondback’s approach to conservative well spacing was well received as its stock increased 2.7% on its announcement and has continued its upward trajectory.ConclusionCommodity price will always be at the forefront of the oil and gas industry. Higher prices allow for more investment, higher profits, and lofty valuations. On the downside, operators must make it through lean times while avoiding bankruptcy. While keeping debtholders happy by making their required payments, they must also seek to please equity investors by achieving production growth on a tight capex budget. Size tends to help both of these as capital becomes cheaper and scale allows for successful drilling techniques from one basin to be applied to operations in other areas.At Mercer Capital, we have assisted many clients with various valuation needs in the upstream oil and gas industry in North America and around the world. We can help companies navigating the bankruptcy process, considering M&A in an acquisitive market, or maintaining their operations business as usual. Contact a Mercer Capital professional to discuss your needs in confidence.
An Overview of Saltwater Disposal
An Overview of Saltwater Disposal

Part 2 | Economics of the Industry

In a prior blog post, we provided an overview of the saltwater disposal (SWD) industry, detailing the source of demand for SWD services, the impact of the shale boom, geographic distribution, site selection, construction, and regulation.  We now take a look at the economics of the SWD industry and the trends that impact the economics.SWD EconomicsIn the past, SWD wells were typically drilled and operated by producers for the purpose of handling the producers’ own disposal needs.  However, the growing inefficiency of individual operators having in-sourced SWD operations has in recent years created an increased demand for specialized outsourced SWD services.  The expertise and economies of scale provided by these independent SWD service providers allow for reductions in the saltwater transportation and disposal expense to the producer.  As a result, the operation of SWD facilities as a stand-alone business has shown enormous growth in recent years.Revenue StreamsRevenues streams to SWD operators consist primarily of disposal fees – typically in the range of $0.50 to $2.50 per barrel – and skim oil sales.  Produced water contains significant amounts of suspended crude oil that the SWD facility “skims-off” (by various methods) and sells to increase revenues.  Where disposal services are abundant, the cost is typically in the lower third of the indicated range.  Locations with fewer available SWD facilities can see fees in the upper end of the range.  Skim oil volumes are typically quite small relative the volume of produced water received for disposal.  However, the sale of the skimmed oil can account for 10% to 30% of total SWD revenues.  The portion of revenues attributable to skim oil sales depends on the SWD facility’s skimming and impurity removal capabilities, in addition to the presence of a local market for alternative skim oil use.Revenues streams to SWD operators consist primarily of disposal fees – typically in the range of $0.50 to $2.50 per barrel – and skim oil sales.Additional revenues may be generated by providing trucking services for the purpose of transporting the produced water from the well site to the disposal facility.  Revenues from such services can vary widely.  Transport rates are typically near $1 per barrel per hour of transport time.  Where SWD facilities are readily available and the distance from the well site is minimal, the trucking cost may only add $0.50 per barrel.  However, the incremental revenue can reach $4 to $6 per barrel where facilities are lacking and the distance is significant.As with the in-sourcing of SWD operations by producers, the provision of trucking services by SWD facility operators is on the decline.  As the oilfield waste disposal industry has rapidly grown in recent years, the ability to provide specialized services at significant economies of scale has led to oilfield waste transportation services being provided as a stand-alone business.  As detailed below, the growing benefits of transporting produced water to SWDs via pipeline has also contributed to the decline in trucking services among SWD facility operators.Cost StructureThe structure of a SWD facility’s expenses is significantly skewed to fixed costs relative to variable costs.  Like other fixed asset-intensive businesses, a large portion of a SWD facility operator’s costs are incurred up-front in the construction of the facility, including the cost of drilling the primary disposal well and any back-up well.  While drilling costs can vary markedly based on the site geology, the target zone, and well depth, the total facility cost can easily reach $3 million to $4 million even if the facility offers no produced water transportation via pipeline.Ongoing expenses are fairly limited and are primarily comprised of power and maintenance/repair costs.  Incremental costs are typically quite low, often less than $1 per barrel.  Labor costs vary little whether disposal volumes are high or low.  Ticketing and invoicing processes are typically heavily automated, and therefore, related expenses do not vary significantly with volumes.The one area of expense that is to some degree within the control of the SWD operator is maintenance expenses.  The SWD operator is well advised to exercise diligence in the maintenance of the SWD well as any downtime, expected or unexpected, can be costly in terms of lost revenues.Focus on VolumeGiven the fixed-heavy cost structure, the SWD facility operator’s primary lever for improving operating results lies in increasing volumes.  However, for the well operator, the primary consideration in choosing a SWD facility is the transportation cost, which is largely a factor of the distance from the well site to the disposal facility.  So, once the SWD facility is sited, the primary SWD decision driver – distance – is fixed and can’t be altered.   To gain more disposal business, SWD facilities often provide transport services via truck.  However, as previously indicated, recent trends have moved SWD facility operators away from trucking services.Trends in Volume AcquisitionHistorically, the transportation of produced water to a commercial disposal facility has been heavily weighted toward trucking.  Due to the smaller volumes of water requiring disposal and the typical patchwork of acreage controlled by any single E&P company, the construction and use of pipeline systems for gathering and transporting produced water to a central disposal facility was cost-prohibitive.  However, with the vast increase in produced water volumes in recent years, and the recent trend among the E&Ps to aggregate more contiguous acreage, the feasibility of pipeline systems has grown.  With trucking costs now more than doubling pipeline transportation costs in many markets, the large up-front cost of constructing a pipeline network is often no longer an economic hindrance.Similarly, several producers have put in place longer-term programs for the systematic development of their large – and more contiguous - acreage holdings.  As part of these programs, the producers have found it economically viable to build out pipeline systems for gathering and transporting produced water to local SWD networks.  Although the trucking of produced water is still dominant in some areas - the Bakken and the Eagle Ford - SWD operators in the Delaware Basin have indicated that piped volumes are likely exceeding trucked volumes in that pipe-heavy area.  Data from NGL Energy shows the progression of piped versus trucked produced water in recent years. While many of the more extensive pipeline systems were originally operated by the E&Ps, much of the current systems are held by businesses that specialize in oilfield waste disposal via E&P asset drop-down and asset sale transactions. Produced Water ContractsAlong with the rise in the prevalence of produced water pipeline gathering and transport systems has come the need for the owners/operators of those systems to ensure the disposal volumes into their systems will be sufficient to service the debt taken on related to the pipeline construction or acquisition.  In pursuit of steadily produced water volumes, SWD operators and E&Ps have begun entering into contractual commitments that often include dedicated acreage and/or take-or-pay volumes.  These contractual relationships are often multi-year agreements, ensuring a steady stream of produced water.  The enhanced economies of scale result in a risk/return profile that is less like that of oilfield service providers and more like midstream companies.  This lowers the cost of capital for SWD operators.Produced Water RecyclingOne detrimental economic trend in the SWD industry is produced water recycling.One detrimental economic trend in the SWD industry is produced water recycling.  Hydraulic fracturing requires enormous amounts of water and therefore results in enormous amounts of produced water.  Traditionally, fracking operations only utilized freshwater.  However, in recent years operators have begun experimenting with mixes of fresh and produced water for fracking purposes with largely favorable results.  This brings the potential for significant quantities of produced water no longer heading to SWD facilities for disposal but instead being recycled and reused at the well site.  While reducing both freshwater supply and produced water disposal expenses would seem to be an obvious benefit to the operator, produced water recycling carries its own cost.Produced water recycling entails a multiple-step process with each step removing a certain part of the produced water mix.  Although the recycling process does not have to bring the produced water to a “drinking water” level of freshness, recycling to the level required for use in fracking can entail a significant expense.  The recycling economics often hinges on the availability – and therefore cost – of freshwater for fracking use.  In areas where freshwater is abundant and inexpensive, recycling economics are less beneficial.  In areas where freshwater is scarce and expensive, recycling often makes economic sense.  As recycling technology improves and greater efficiencies are realized, it’s likely that a greater percentage of produced water will be reused, rather than removed for disposal. However, research by Raymond James indicates that fracking-related water demand growth falls far short of estimates of produced water disposal demand growth, even with produced water recycling considerations.[caption id="attachment_27673" align="aligncenter" width="940"]Source: EIA, Drilling Info, Baker Huges, Raymond James Research[/caption] As of now, recycling of produced water is still in early development with estimates of disposal to recycle ratios at 20:1. SummaryAs detailed, the outlook of the SWD industry is quite favorable although the economics are, and will continue to be, in a state of flux as the industry grows and matures.  Despite some potential detrimental market dynamics along the way, the overall direction points to strong benefits to investors as the business of SWD continues to evolve away from a being cost center for operators, to a cash flow generating third-party service provider to operators.
Public Royalty Interests: Picking the Right Comparable
Public Royalty Interests: Picking the Right Comparable
In previous posts, we have discussed the relationship between public royalty interests and their market pricing implications to royalty owners.  Here, we will define our group of royalty interests which can be used to gain valuation insights.  Specifically, we will look at mineral aggregators, natural gas focused trusts, and crude oil focused trusts and the statutory differences between them. We also consider how dividend yields and other public data can be used to imply value for private mineral interests while being judicious in our application of such metrics.What is a Royalty Trust?Historically, the most common way mineral interests have been structured for public investment has been in the form of a trust. The trust’s sponsor (frequently though not always the operator) conveys a percentage interest in specified properties, and the trust is prohibited from acquiring more interests. In some cases, the trust has a defined termination date, but this can also be based on a certain threshold of production, or there may be no specified termination at all.The most common way mineral interests have been structured for public investment has been in the form of a trust.Distributions are paid on an established schedule (monthly is the most common), and these distributions are based on commodity prices and the level of production.  While the former depends on market forces, the latter tends to decline over time as the resources are drained from the specified properties. Thus, the stock prices of these trusts decline over time, and the return comes almost exclusively from the dividend yield, with minimal opportunity for capital appreciation.Because they are structured as a trust, these investment vehicles are required to distribute a substantial portion of their income. However, trusts can withhold a certain percentage of cash flows to pay trust administrative expenses or create a reserve for future distributions.  Because the interests in the specified properties are typically revenue interests, the trust is not required to pay for any expenses related to production, so expenses are relatively minimal.What is a Mineral Aggregator?The more popular investment vehicle for mineral interests recently has been the emerging sector of mineral aggregators. Aside from Dorchester Minerals, LP, which IPO’d back in 2003, the remaining five aggregators have gone public in the past five years, including Falcon Minerals and Brigham Minerals in the past twelve months.1 While aggregators also allow investors to gain exposure to the energy sector without investing directly in E&P companies or commodities, there are differences between aggregators and trusts, beginning with their structure.Dorchester, Viper Energy Partners, Blackstone Minerals, and Kimbell Royalty Partners are all structured as MLPs, while Falcon and Brigham are corporations.2 Eschewing the trust structure provides certain benefits to these entities. Aggregators are not restricted from acquiring more interests, and as their name implies, they seek to reinvest their earnings into the acquisition of new properties. The value of units in a public royalty trust tend to decline with production over time, but aggregators stem the tide of these losses with their reinvestment, and they do not have the statutory termination present in some trusts.They can also issue more common units, take on debt, and incur operating expenses in ways that royalty trusts cannot. While these make aggregators appear to be the better option, trusts by nature have beneficial tax treatment, and their yields tend to be higher and relatively more predictable given their distribution requirement, which mineral aggregators could decide to forego.A table summarizing the primary differences between a royalty trust and a mineral aggregator is included below:Market Data for Trusts and AggregatorsTo gain a better insight into how these factors play out in the public marketplace, we should analyze the data. The following tables gives some critical market data for valuation purposes: [caption id="attachment_27589" align="aligncenter" width="868"]Source: Capital IQ[/caption] While these trusts are predominantly focused on natural gas, many also have oil and NGL reserves. These natural gas trusts have the lowest market caps and relatively high dividend yields.  Compared to the crude oil trusts, these exhibit more diversity in product mix including notable amounts of NGLs. [caption id="attachment_27615" align="aligncenter" width="867"]Source: Capital IQ[/caption] [caption id="attachment_27609" align="aligncenter" width="860"]Source: Capital IQ[/caption] Compared to natural gas focused trusts, crude oil trusts tend to have relatively higher market caps with similar yield and pricing multiples, despite being based on a different commodity.  The levels of operating expenses are comparable as well. For this post, we have further delineated between perpetual and terminal crude oil trusts. The latter have a specified end date, while the former do not. However, both groups ultimately will receive distributions related to crude oil prices and declining production, regardless, whether there is a statutory termination or not. Going forward, we do not plan to group these separately.Mineral AggregatorsAs noted previously, mineral aggregators have been the apple of certain investors’ eyes lately.  They are not bound by distribution requirements, which allows aggregators to gobble up additional acreage.  This provides investors an element of growth in what has historically been a declining, yield-only return play. Despite no statutory requirements to distribute, the below aggregators have offered an attractive yield to investors. [caption id="attachment_27591" align="aligncenter" width="859"]Source: Capital IQ[/caption] When compared to the trusts, aggregators are significantly larger in terms of market cap and have notably more operating expenses and product diversity.  Also, they tend to trade at higher revenue multiples, with lower yields. While mineral aggregators may present an attractive option for investors, they are less functional as comparables for mineral interest owners. The lower yield, influenced by potential for return from future growth, and higher operating expenses render aggregators less comparable to traditional mineral interests.Other Valuation ConsiderationsNow that we have the data to back up the differences between trusts and aggregators, one must delve deeper into the subject characteristics of the individual trusts to determine how one might use these to value their own private royalty interest. While tempting, drawing valuation conclusions simply by selecting the appropriate commodity mix would be shortsighted. There are plenty of other considerations and judgments that need to be made such as:Timing quirks related to market pricing and dividendsIdiosyncratic issues with the operatorRegion/basin Dividends are a product of production and commodity pricing over the past year, whereas stock prices tend to be based on expected future commodity prices. WTI crude prices are expected to remain below $60/bbl for the rest of 2019, but dividends in the past year include those from back in late 2018, when some floated the possibility of crude oil returning to $100/bbl. Contrast this to a recent declaration that oil could conceivably drop to $30/bbl. With dividends paid out monthly, the numerator of the yield is impacted by stale prices that do not typically inform future expectations. These expectations, however, are a critical driver for the denominator, so bearish sentiment leads to higher yields. Higher yields inform current market sentiment about relative risk factors, however simply taking the prevailing dividend yield is not advisable.One must delve deeper into the subject characteristics of the individual trusts to determine how one might use these to value their own private royalty interest.Case in point(s): San Juan Basin Royalty Trust has not paid a dividend in the past year. That doesn’t mean there is no risk in their cash flows, it means there are no cash flows. On the opposite end of the spectrum, Whiting USA Trust II has a yield north of 77% as its quarterly dividends have nearly matched its prevailing market price. Again, this should not imply to a private mineral owner that their potential future revenue checks will carry this level of risk.Another important consideration for utilizing trusts as comparables is the operator of the subject interests. Take the three SandRidge trusts for example. Trust distributions are a function of both production and price, and SandRidge has struggled to maintain production given its various woes. Comparing the risk of a private mineral interest to one whose operator is hemorrhaging is not prudent.Finally, one must consider the region or basin. Geological factors distinguish the commodities produced in different plays and basins, and regional transportation dynamics also play a role.  As a result, investors may pay a premium to be in a basin such as the Permian. SandRidge Permian Trust bears many of the idiosyncratic issues as the SandRidge Mississippian Trusts, but it is in a more desirable location and therefore is expected to command a higher multiple. Again, production and price determine the distributions, and certain basins such as the Eagle Ford may provide the opportunity for premium prices while others like the Permian may be more attractive for other reasons.How These Factors Impact ValuationsTo value a currently producing royalty interest under the income approach, a valuation professional must determine some indication of projected future cash flows and discount these back to the present. Given the declining nature of the production, total return comes almost exclusively from the yield. Thus, we can use yields on public royalty trusts to discount the projected future cash flows of the subject interest back to the present. As noted above, judgment is required in determining the relative risk and return characteristics of the subject interest. As we noted in our last post, the SEC prices reserves based on a present value factor of 10%. While this is less applicable to PUDs and similarly more risky assets, private mineral interests that have been delivering consistent cash flows in the form of monthly royalty payments are more likely to be around this 10% discount rate, even if current yields indicate something higher.ConclusionWhen investing in a public royalty trust or using it as a pricing benchmark for private royalty interests, there are many items to consider that are unique to each royalty trust.  The commodity mix, operator/sponsor, region, termination (or lack thereof), and other key aspects make each of these investment vehicles unique. Further analysis is required to verify these provide meaningful valuation indications.We have assisted many clients with various valuation and cash flow questions regarding royalty interests.  Contact Mercer Capital to discuss your needs in confidence and learn more about how we can help you succeed.1      Actual IPO of entity holding Falcon Minerals occurred in 2017, but it discontinued its Special Purpose Acquisition Company (“SPAC”) in 2018.2     Viper and Kimbell have both elected to be taxed as C-corporations.
Comstock’s Acquisition of Covey Park
Comstock’s Acquisition of Covey Park

A Valuation Analysis of the Multibillion-Dollar Haynesville Deal

On July 16, 2019, Comstock Resources, Inc (NYSE: CRK) finalized its acquisition of Haynesville operator Covey Park Energy LLC. Announced on June 10, 2019, the companies entered into an agreement under which Comstock would acquire Covey Park in a cash and stock transaction valued at approximately $2.2 billion, including assumption of Covey Park’s outstanding debt and retirement of Covey Park’s existing preferred units (totaling approximately $1.1 billion). Covey Park is a natural gas operator with core operations located in the Haynesville Shale Basin and is backed by private equity firm Denham Capital. This acquisition is the latest addition to the continuing resurgence of the Haynesville Shale Basin.For the purposes of this post, we will be examining this deal from a few different vantage points and reviewing the fair value of the various components that make up total deal value. We’ll also look at how this transaction compares to industry valuation metrics and what kind of strategic advantages Comstock may have a result of the deal.Deal OverviewThe transaction is structured in multiple layers, including a substantial investment from Dallas Cowboys owner and Comstock majority stockholder, Jerry Jones. Details behind the total deal consideration are outlined below: As a result of the finalized deal, Comstock’s holdings in North Louisiana and East Texas comes out to a total of 374,000 net acres with over 1.1 bcfe/d of net production. The company also holds assets in North Dakota. The chart below maps the acreage of Comstock and Covey Park prior to the merger and where it fits into the Haynesville Shale: As the various components of the deal are considered, we then begin to analyze the assets actually purchased by Comstock. Analysts, accountants, and investors alike look at fair value of the parts that make up the total purchase, and allocating fair value among the components begins to paint a clearer picture of how we get to deal value. Allocation of Assets and Liabilities to Fair ValueThe table below outlines the allocation for both the assets acquired and the liabilities assumed. The calculation is management’s estimate from the Definitive Proxy Statement that Comstock had filed with the SEC on June 24, 2019. For an E&P company, most of its asset fair value naturally derives from its property and equipment. It’s no surprise that of the assets acquired an estimate of nearly $2.2 billion is in the property and equipment camp. We can then take a step further into understanding the value of these assets by diving into the proven resource reserves that are contained within these properties. The SEC has clear rules and regulations regarding oil and gas reserve reporting (more commonly known as PV-10), and while these summaries of reserves under SEC pricing may not be accurate for determining fair market value, they do provide a general ballpark figure. Below is the summary of proved reserves for Covey Park from the Definitive Proxy Statement: Under the standardized measure, the total value of the proved reserves (both developed and undeveloped), totals around $2.3 billion. What is interesting is this amount is north of the purchase price by Comstock and may have some investors wondering if this falls into the territory of a bargain purchase. As we mentioned above, SEC pricing may not be the best indicator of fair value. It’s not unusual for fair value to vary 10-20% from PV-10 value, and most of that generally comes from the developed and undeveloped (PUD) reserve mix. The valuation of PUDs can be tricky at times, and they generally have a fair value that trades at a haircut. Given the mix of the total proved reserves is fairly PUD heavy, it makes sense as to why the management estimated value of properties comes in under the SEC PV-10 amount. Other assets of note that typically are glossed over are the derivative financial instruments. E&P companies often hold futures and other derivative contracts for hedging purposes, and these contracts are marked to fair value for the purposes of the allocation.  These are relatively less important given the magnitude of the other assets, but they certainly merit consideration, particularly for companies that may have significant hedging practices. How Do Reported Valuation Multiples Compare to the Industry?Below is a list of comparable companies that Comstock identifies in their latest 10-K as competitors, excluding non-gas players, and common valuation multiples (such as EV to Production) used for relative industry analysis. In comparison to other operators, the acquired assets come in slightly above the median values for EBITDA multiples but are generally close to direct competitors such as Cabot and Antero. The lower acreage multiple observed in the deal compared to the industry group makes sense given our analysis above of the sizable amount of PUDs in the proved reserves. After analyzing the structure of the deal and how it compares to other valuation metrics, we will take a look at some of the competitive advantages available to Comstock as a result of the deal. Large Footprint, Established Infrastructure, and Low Gathering CostsWhile the company already owns over 500 miles of gas gathering infrastructure, it also enjoys many locational benefits: limited basis risk due to proximity to Henry Hub, lowest in-basin gathering, treating, and transport costs (approx. 26¢ per Mcfe), and even twelve approved LNG export terminals located in the Gulf Coast.The Houston Ship Channel and other gathering and transportation pipeline infrastructure already present in the Louisiana and East Texas regions mitigate the risks of capacity constraints and bottlenecking unlike those that historically, up until recently, plagued Northeast gas production in the Marcellus/Utica Shale.The Competitive Edge: Capital AdvantageBeing the largest operator in the Haynesville Shale provides Comstock with a strategic advantage due to sheer size of acreage owned. Just as importantly though, Comstock has another major advantage that competitors have been struggling with for some time: access to capital.E&P companies have been facing headwinds in the public markets for some time. The major uptick in U.S. production over the past several years has triggered the need for upstream companies to increase capital expenditures to keep up with demand. However, investors have been unwilling to participate in the upstream sector because free cash flow has been directed to these capital expenditures and additional acreage as opposed to returns in the form of payouts. Consequently, investors have shifted into the realm of mineral rights aggregators because of the immediate returns in the form of dividends and returns on capital.  As a result, access to capital markets (both equity and debt) has proved difficult for E&P companies in general.Comstock, however, appears to have bypassed this hurdle before having to cross it. Jerry Jones’ large stake (75% ownership) and his deep pockets can facilitate large capital raises should the need arise. However, Mr. Jones isn’t Comstock’s sole non-public capital raising option. The aforementioned Denham Capital owns 16% ownership interest, and Comstock just renewed its bank credit facility to $2.5 billion concurrent with the transaction. This gives the company the ability to raise any needed funds before having to jump into the public markets.ConclusionAs a result of the transaction, Comstock is now the largest operator in the Haynesville Shale. While it may seem that Comstock managed to acquire Covey Park’s large amount of acreage at a bargain, the examination of the components of the fair value allocation show that the heavy mix of PUDs in the reserves account for much of the estimated fair value by management, even though it came out lower than the calculated PV-10 valuation. This seemed to be confirmed in our comparisons to industry multiples. However, given the advantages Comstock now has as a result of the deal, the company has positioned itself to be a strong player in the Haynesville Shale Basin.Mercer Capital has significant experience valuing assets and companies in the energy industry, primarily oil and gas, bio fuels and other minerals.  Our oil and gas valuations have been reviewed and relied on by buyers and sellers and Big 4 Auditors. These oil and gas related valuations have been utilized to support valuations for IRS Estate and Gift Tax, GAAP accounting, and litigation purposes. We have performed oil and gas valuations and associated oil and gas reserves domestically throughout the United States and in foreign countries. Contact a Mercer Capital professional today to discuss your valuation needs in confidence.
Challenges in Appraising Refinery Businesses
Challenges in Appraising Refinery Businesses
The appraisal of businesses involved in the refining of crude oil entails a number of challenges.  Some are unique to the industry, and others are more common.  The challenges arise primarily in two areas – assessing the level of uncertainty inherent in the entity’s future cash flows and forecasting the entity’s future operating results.The greater the range of future cash flows, the greater the rate of return an investor will require to invest in the business.Assessing the level of uncertainty for a particular business’ future cash flows is a key part of any business valuation.  Basic economics tells us that the present value of an expected future cash flow is greater if the possible range of the cash flow is +/-10% from the expected level, compared to the possible range of the cash flow being +/-30% from the expected level.  Investors aren’t willing to pay as much for an expected future cash flow with a potentially high divergence from expectations than for an expected future cash flow with a potentially low divergence from expectations.  The greater the range of future cash flows (the degree of uncertainty of the future cash flows), the greater the rate of return an investor will require to invest in the business.In addition to the challenges posed in the risk (uncertainty) assessment, the appraisal of an oil refinery business also carries particular challenges in forecasting future operating results.  Oil refining entails not only a commodity input (feedstock), but also commodity products - gasoline, diesel, liquefied petroleum gases, jet fuel, residual fuel oils, still gases, lubricants, and waxes.  Complexity increases in these product markets since they are significantly influenced by international, domestic and local supply and demand, heavy regulation, domestic politics and international politics.  Add to those enormous capital requirements and high barriers to entry and you have an industry rife with forecasting complexity.Assessing UncertaintyAssessing the level of cash flow uncertainty for a particular crude oil refining business requires a thorough analysis of the subject company’s internal operations. This analysis includes its facilities, suppliers, customers, level of integration, and use of hedging.  Additionally, external factors, such as infrastructure availability and limitations, feedstock and product supply and demand, government and environmental policies, geopolitical matters, and currency exchange rates must be considered.  Some potentially key uncertainty assessment considerations are addressed as follows:ConfigurationConfiguration refers to a facility’s ability to accept a range of crude oils (light-sweet crude, or heavy crude) as feedstock.  Refineries with limited feedstock abilities lack the flexibility of shifting from one type feedstock oil to another, thereby exposing the business to uncertainties regarding particular feedstock supply and demand.  For example, refineries that were specifically designed (configured) to process heavy crude would be exposed to the negative economics of an unexpected decrease in heavy crude availability. On the contrary, refineries configured for greater feedstock flexibility would potentially avoid the negative impact of a reduced supply of heavy crude by shifting to a light crude feedstock.Secondary Processing SystemsSecondary processing capabilities refers to the ability to engage in processing crude oil beyond initial distillation to processes involving catalytic cracking and reforming.  These secondary processes allow a refinery to shift between maximizing distillate production in the winter months when heating oil is in higher demand and gasoline production during the summer months when automotive fuel is in demand.  Without secondary processing systems, a refinery is more vulnerable to the negative economics of seasonal product supply and demand shifts.Feedstock Source ConstraintsFeedstock source constraints refer to the refinery’s ability to economically choose between feedstock sources.  Facilities that are located along the U.S. coastline have the option of using either the WTI (inland U.S. produced) or the Brent (North Sea produced) varieties of crude oil.  As such, they have the ability to favorably respond to shifts in WTI versus Brent pricing (the Brent-WTI spread).  Refineries located in the U.S. interior have a much lower economic ability to utilize Brent and are therefore subject to the impacts (positive or negative) of pricing variations between the two varieties.Inventory ExposureRefineries typically hold significant levels of inventory (feedstock and product inventory) with these inventories comprising 13% to 17% of total assets.  Due to the potential for material swings in the market price for the feedstock inventories (crude oil) and end products, refiners face a significant level of uncertainty regarding their profits.   Market-driven increases/decreases in crude prices can raise/reduce the value of feedstock holdings, while market-driven increases/decreases in end product prices can raise/lower revenues and profit margins.  While protection against the negative impacts of such market changes is available through commodity price hedging, refining businesses vary in the degree to which they utilize hedging strategies.  In appraising a particular oil refining business, the appraiser must gain a clear understanding as to the commodity price risks that are hedged and those that remain unhedged.Ability to Pass-on CostsThe ability to pass-on the higher feedstock costs is often dependent on the current conditions in the local and international end product markets.When crude oil prices are rising, oil refinery businesses may be able to pass those higher feedstock prices on to customers in the form of higher-end product prices and thereby maintain margins.  The ability to pass-on the higher feedstock costs is often dependent on the current conditions in the local and international end product markets.  If the petroleum product market is experiencing particularly high supply, or low demand, the refiner’s ability to pass-on higher crude oil prices may be significantly limited.  However, in situations of lower supply, or higher demand, higher crude prices may more readily be passed through to customers.  As such, an appraiser must not only be aware of near-term expectations for crude prices, but also near-term expectations for the various end products of the particular refining business in order to correctly assess the level of uncertainty that should be factored into the appraisal analysis.  In performing this part of the analysis, the appraiser must take into consideration the degree to which the uncertainty would be expected to be avoided by the subject company’s use of hedging.IntegrationSome oil refiners are integrated in that they are also involved in the ownership/control of crude oil reserves, or as with many larger refineries, they also own the petrochemical plant customer of the refiner.  Such integrated refineries can allow for the shifting commodity price risks between the refinery and the entity that owns the crude reserves or the petrochemical producer.  As such, an important part of the refinery appraisal involves a careful assessment of how the commodity price risk is being handled between the entities involved, and how such handling of the risk should be incorporated into the appraiser’s assessment of future cash flow uncertainty.Infrastructure ChangesInfrastructure changes can have a significant impact on a refinery’s profitability. Changes in the availability of the necessary infrastructure for bringing crude oil “to market” (to local refineries, more distant refineries, or to a port for export) can have a significant impact on the refinery’s profitability.  For example, for years various market forces (high international demand for Brent, high WTI supply and interior U.S. pipeline capacity deficiencies) maintained a Brent-WTI spread that was advantageous to U.S. refineries.  However, more recently shifts in market forces, including improvement of U.S. pipeline capacity, has contributed to a significant narrowing of the Brent-WTI spread. These shifts have resulted in the loss of a considerable portion of the crude supply cost advantage for U.S. refineries.  A particular refinery’s exposure to potential changes in crude transportation infrastructure must be considered by an appraiser as part of the analysis in determining the relative uncertainty of the refinery’s cash flows.Facility EfficiencyThe efficiency of a particular refinery can be a material contributor to cash flow uncertainty.  The oil refining industry is subject to a large number of market forces that can have a material impact on profitability.  In considering the refinery’s ability to successfully adjust to changes in those many market forces, one must consider the facility’s efficiency.  In an environment where the number of facilities is expected to downsize and consolidate in the short-term, facilities with lower levels of efficiency are more subject to having their utilization trimmed back, or even being shut-down.Government RegulationThe oil refining industry is subject to an extensive array of both federal and state regulations, which can be changed, delayed, or accelerated, depending on the political climate. While some of these regulations are static, others have restrictions that are implemented over time.  For example, MarPol 2020 represents a significant, albeit long foreseen, change beginning January 1, 2020 where the allowable sulfur for fuel used in ocean-bound vessels is reduced from 3.5% to just 0.5%.  U.S. refiners with the ability to produce a higher proportion of lighter, low-sulfur fuels from each barrel of oil will stand to profit from the change in legislation, particularly if supply is low in the short term following the change.One must be aware of potential regulatory changes and the facility’s ability to conform.In the appraisal of a refining business, one must be aware of potential future regulatory changes and the particular facility’s ability to conform to such regulations.  In some cases, this flexibility may be tied to the configuration of the plant, and in others may be tied to technology-related efficiency.  Any factors that create a question as to the ability or willingness from a financial perspective to comply with potential regulatory changes must be considered in assessing the uncertainty of future cash flows.Forecasting Operating ResultsForecasting future operating results can present a challenge for many industries. With the number of market forces in play, several considerations in the forecasting process deserve special attention when appraising a business in the oil refining industry.  Some of the areas for particular attention include commodity pricing considerations on volumes and margins, and capital intensity considerations.Commodity Pricing ConsiderationsThe commodity nature of refinery feedstock (crude oil) makes the forecasting of future revenues worthy of particular attention.  International, domestic and local supply and demand, heavy regulation, domestic politics and international politics all come into play in the oil refining industry and the uncertainty as to the impact of these various factors is why hedging plays such a significant role within the industry.  While careful analysis can identify pertinent short-term and long-term trends, the future direction of feedstock prices always remains uncertain to some degree.  As such, the appraiser of a refinery business must be familiar with the mix of factors that can impact future feedstock prices and accurately factor the “knowns” and “unknowns” into projections of future revenue levels.The factors that come into play in forecasting future refinery revenues can also impact future operating margins, but not necessarily.  As previously mentioned, the ability to pass-on changes in feedstock prices can vary over time based on supply and demand dynamics regarding the refinery’s products.  Similar to the refinery’s crude oil feedstock, the end products are also commodities and are therefore subject to pricing changes that are well beyond the control of the refinery operator.  In some cases, those dynamics may allow for changes in crude oil prices to be passed on to the refinery’s customers, thereby maintaining operating margins.  However, end product market dynamics may create an environment where increases in crude oil prices can’t be passed-on such that future operating margins would be expected to be trimmed.Capital IntensityCapital expenditures in the oil refining business can be much more significant and much less steady in magnitude than in other industries.Petroleum refining is a capital intensive process requiring large investments in property, plant, and equipment (PP&E).  While machinery and equipment maintenance expenses are often somewhat steady over time, certain aspects of such expenses can be much more irregular.  In contrast, capital expenditures in the oil refining business can be much more significant and much less steady in magnitude than in other industries.  Short-term capital expenditures expectations can vary widely depending on past maintenance expenditures and the facility’s past acceleration, or delaying, of major expenditures.  Longer-term capital expenditures, or periodic expenditures, are typically significant and quite large.  A detailed discussion with facility management is often necessary in order to gain a clear understanding as to both timing and cost expectations for such expenditures.  With the high level of industry regulation, often environmentally focused, the timing and magnitude of some capital expenditures may well be outside of facility management control.In addition to the more direct impact of oil refinery capital intensity on maintenance and capital expenditures is the impact on tax expenditures from the depreciation of the machinery and equipment.    With PP&E assets totaling hundreds of millions, or even billions of dollars, tax depreciation of those assets can have a significant impact on expected cash flows.  The difference of results between a simplified straight-line depreciation modeling and a more detailed accelerated (MACRS) tax depreciation modeling can be significant even before incorporating potential bonus depreciation and Section 179 immediate expensing of qualifying property.While appraisers may be provided with detailed tax depreciation schedules for existing machinery and equipment, it may be within the appraiser’s scope of service to develop the expected tax depreciation scheduling for machinery and equipment that will be put in place during the forecast period.  The detailed tax depreciation forecasting may not be particularly pertinent in less asset-intensive industries, but it can have a material impact in the appraisal of more asset-intensive businesses such as oil refining.Mercer Capital has a breadth and depth of experience in the appraisal of businesses in the oil and gas industry that is rare among independent business appraisal firms.  Our Energy Team is led by professionals with 20 to 30+ years of experience involving upstream businesses (E&Ps, oilfield product manufacturers and oilfield service providers), midstream (gathering systems, pipeline MLPs, pipeline processing facilities), and downstream (refining, processing, and distribution).   Feel free to contact us to discuss your valuation needs in confidence.
Natural Gas Takeaway Constraints
Natural Gas Takeaway Constraints

A Tale of Two Basins

Appalachia and the Permian are responsible for much of the United States’ surging natural gas production, resulting in relatively low benchmark prices. However, difficulties capturing, storing, and transporting natural gas mean that large regional price differentials can occur. While Appalachia price differentials have narrowed significantly, Permian pricing differentials have widened, often resulting in $0 or sometimes negative realized prices.[1]  Going forward, futures prices imply a modest widening of the Appalachia basis over time, while the Permian basis will not stabilize until 2021. Appalachia Takeaway Constraints Easing – Northeast Supply Constraints, Not so MuchAppalachia natural gas takeaway capacity constraints have eased significantly over the past several years as new pipelines have come into service.  RBN Energy estimates the total excess takeaway capacity out of Appalachia at approximately 4 bcf/d.  However, the new pipelines are largely moving volumes to the Gulf Coast and Midwest rather than nearby population centers in the Northeast. Proposed pipelines that would connect the gas-rich Marcellus and Utica plays to East Coast cities have faced intense pushback.  The PennEast Pipeline would transport natural gas from northeast Pennsylvania to New Jersey, but has been targeted by multiple environmental and community groups and still awaits approval from various regulatory bodies, including the New Jersey Department of Environmental Protection.  A federal appeals court vacated permits issued by the U.S. Forest Service for the Atlantic Coast Pipeline, slated to cross two national forests and the Appalachian Trail in order to transport up to 1.5 bcf/d of natural gas from West Virginia to Virginia and North Carolina.  The pipeline’s primary backer, Dominion Energy, has appealed the ruling to the Supreme Court.   And The Williams Cos. has battled with the state government of New York for years over water quality certifications needed to move forward with the 125-mile Constitution Pipeline, which would transport gas from northern Pennsylvania. These various hurdles mean that cities are struggling with supply during winter and some natural gas utilities are not accepting new customers, as recently reported by the Wall Street Journal.  Without the ability to hook into natural gas lines, certain new real estate developments are on hold or being shelved.  And those customers with access to natural gas sometimes pay dearly, with Transco Zone 6 (servicing New York and New Jersey) prices exceeding $140/mmbtu in January 2018. The recent infrastructure build-out has helped Appalachian E&Ps, but Northeast end-users will likely continue to be subject to significant seasonal spikes until connectivity to Marcellus and Utica production is improved. Permian Natural Gas Takeaway Capacity to Remain Constrained in the Near TermWhile Appalachia takeaway constraints have largely been alleviated, the same cannot be said for the Permian.  Much of the infrastructure build-out designed to service surging hydrocarbon production in the Permian Basin was focused on higher-value crude, with a significant amount of associated natural gas production simply flared.  However, with increasing scrutiny on flaring and Waha natural gas prices falling as low as negative $8.50/mmbtu, midstream companies are finally starting to build meaningful takeaway capacity out of the basin. And while the political and regulatory environment in Texas is much more amenable to pipeline construction, new pipelines have not been unchallenged.  A group of landowners sued Kinder Morgan over the route of the company’s Permian Highway Pipeline.  However, the lawsuit, filed in April 2019, was thrown out by a Texas court only two months later. The new takeaway capacity should help with pricing, as indicated by Waha basis futures, but differentials will remain elevated until 2021. ConclusionAppalachian takeaway constraints have largely been alleviated, though incremental capacity largely takes volumes to the Gulf Coast and Midwest.  As such, Northeast cities will likely still face supply issues despite being located just a few hundred miles from prolific natural gas production.  Permian natural gas takeaway constraints remain, and will likely continue until 2021.We have assisted many clients with various valuation needs in the upstream oil and gas space in both conventional and unconventional plays in North America and around the world. Contact a Mercer Capital professional to discuss your needs.[1] Appalachia basis reflects Dominion South pricing.  Permian basis reflects Waha pricing.
Valuations In The Permian
Valuations In The Permian

Gearing Up For The Long Haul Or Running In Place?

When it comes to the oil patch, the word “growth” can be a vague term. It’s a word that can be masqueraded around to suit the perspective of whomever utters it. What does it mean in an industry whose principle resources are constantly in a state of decline? When it comes to the Permian Basin these days, growth applies to resources, drilling locations and production. Unfortunately, the same can’t be said for profits, free cash flow or new IPOs. Don’t misunderstand, the Permian is the king of U.S. oil plays and by some measures could be taking the crown as the biggest oil field in the world. However, various economic forces are keeping profits and valuations in check.Permian Reserves: A Behemoth and Getting BiggerFrom a macro perspective, the Permian Basin is, and will continue to be, a record setting engine of hydrocarbon extraction. The Permian has been and will continue to make new production records in the U.S. and globally. In 2018, the U.S. accounted for 98% of global production growth (there’s that word again). Despite alternative energy sources and climate change policies being in vogue, global oil demand has increased for nine straight years, and the Permian has led the way to fill this demand gap. In May 2019, with a mix of productivity gains and drilled but uncompleted (DUC) well drawdowns, Texas’ crude oil production topped 5 million barrels per day for the first time. Shale output, the leading force for this production continues to rise. This will not stop for decades to come. In fact, a USGS survey covering the Wolfcamp and Bone Spring formations estimates an additional 46 billion barrels of oil (enough to supply the world for half a year) and 280 trillion cubic feet of gas (enough to supply the world for two years) are technically recoverable. For context, total U.S. proved oil reserves (which must be technically and economically recoverable) totaled 39.2 billion barrels at year-end 2017, according to the EIA. It’s an amazing growth story.Pipeline Capacity (Finally) ArrivingOne of the biggest constraints for the Permian over the past 15 months has been a lack of pipeline capacity. For months on end, local prices in the Permian suffered huge differentials to NYMEX prices due to the bottleneck issues that plagued the area. Transportation came at a premium and so did costs; however, that's in the process of changing. According to the American Petroleum Institute, the Permian Basin is expected to get 1.5 million barrels a day of new crude capacity. This includes expansions of the Grey Oak, Cactus II and Seminole Red pipelines, taking crude to the Gulf of Mexico for refining or export. Natural gas, which has been flared in many cases, is also getting a reprieve. Almost 5.0 bcf per day of new gas capacity additions are expected to go live by the end of 2019. See the map below made by RBN Energy.[caption id="attachment_27170" align="aligncenter" width="468"]Source: RBN Energy[/caption] These capacity additions should cut transportation costs for many producers, and none too soon because every dollar and penny count when it comes to profitability in the Permian these days. Tight Breakeven Spreads and Negative Cash FlowAmid these positive big picture developments in the Permian, most shale producers are struggling to keep up cash balances. According to one analysis for Q1 2019, only 10% of shale companies had a positive cash flow from operating activities, and other studies have shown similar results. Shale producers are spending more than they are making. How can this be with such a plethora of resources and the means to transport it? The answer lies in two conundrums: (i) expensive fracking and completion costs; and (ii) steep production decline curves. Getting to the oil is expensive, and once a producer finds it, the tight well formations drain quickly. The only way to get more production and associated revenues is to drill more. Investing skeptics describe this as a treadmill effect.This wouldn’t be too much of a problem in a $65 or $70 oil environment, but when oil is in the mid $50s, there’s not much profitability cushion and it shows. The April issue of Oil & Gas Investor includes a table showing median breakeven prices in the Permian. In the Delaware Basin median breakevens range between $42.50 and $45. In the Midland Basin median breakevens range between $44.30 and $53.00. Keep in mind – these are medians. Half of producers can produce it cheaper, but half are more expensive too.[caption id="attachment_27171" align="aligncenter" width="600"]Source: Oil & Gas Investor[/caption] This kind of narrow profit cushion has soured many investors and made financing new drilling more expensive for producers. Investors have demanded austerity and are either charging bigger financing premiums or are cutting off financing altogether. IPOs for producers have been anemic in the past several quarters. Cost control and economies of scale are becoming increasingly important, and thus, the answer has been in the form of consolidation. Valuation Winners: Low Cost Producers & Royalty HoldersM&A in the Permian has been consistently healthy amid the aforementioned challenges. Values from an acreage and production perspective are generally the highest of any major U.S. basin. With Oxy’s acquisition of Anadarko as the most recent flagship example, producers are scrambling to amass contiguous acreage and drilling synergies, coupled with reduced overhead to create more consistent profitability. This kind of rationale is driving mergers, acquisitions and dispositions. It is also attracting the majors such as Exxon and Chevron to the region. See the table below.[caption id="attachment_27172" align="aligncenter" width="800"]Source: Shale Experts[/caption] However, this is easier said than done, and not everyone is a believer. Carl Icahn isn’t as he recently opened a shareholder lawsuit in relation to Oxy’s acquisition. Oxy’s price has slid since the announcement. Perhaps the best investment strategy is not to take operating cost risks at all. Enter the mineral and royalty sub-sector, which has been among the most successful areas of energy in the past several years. While producers can’t get access to public equity, royalty companies have had numerous IPOs in the past couple of years. Getting access to the production boom, without exposure to fracking costs, has been the attraction and it appears to be gaining momentum. Lower costs are the key to creating value in the Permian. Whoever can master this kind of fiscal discipline will move to the top of the heap and finally growth in profits will follow. Originally appeared on Forbes.com.
EP Third Quarter 2019 Region Focus Bakken
E&P Third Quarter 2019

Region Focus: Bakken

Region Focus: Bakken // WTI crude prices edged above $60 per barrel to begin the quarter but only crossed that threshold once more in the first trading day after the attack on Saudi Aramco oil processing facilities.
Q2 2019 Macro Overview
Q2 2019 Macro Overview

Uncertainties Engulf Global Oil Amid Political Tensions

Brent crude prices began the quarter around $69 per barrel and peaked at nearly $75 in late-April before declining to just below $60 on June 12, 2019. Prices have since increased to $65, with WTI continuing to trail by about $8 per barrel. In this post, we will assess global supply and demand factors that have caused these price fluctuations.Global SupplyOriginally founded by Iran, Iraq, Kuwait, Saudi Arabia, and Venezuela in 1960, OPEC now stands at 14 members, after Qatar terminated its membership at the beginning of the year. OPEC is still a significant organization when assessing global supply, but it has undergone considerable changes. While OPEC only has 14 statutory members, an alliance known as OPEC+ has added 10 non-OPEC member countries headlined by Russia and including Mexico and Kazakhstan. This group agreed in December 2018 to a production decline with the goal of balancing global inventories and stabilizing the oil market (read: raising prices). With churn in its members and inclusion of allies in its production cuts, people may not know exactly who OPEC+ is, but the oil cartel’s mission remains clear (even if oil and cartel are not the O or C in the group’s amorphous acronym).OPEC+ has thus far been successful in reducing output, though for countries like Iran and Venezuela, decreased output hasn’t necessarily been intentional. In May, OPEC members produced 29.9 million barrels per day (b/d), the lowest for any month since July 2014. It remains to be seen if these production cuts set to expire this month will remain intact, and if so, for how long. Saudi Arabia’s energy minister Khalid al-Falih expressed absolute confidence that an agreement would be reached to extend the oil production cuts after “very constructive discussions” with Russian energy minister Alexander Novak. Falih also said,Our intent is to make sure that we continue to work together closely, not just bilaterally, but with all other members of the OPEC+ coalition – and that the good work we have done over the last two and a half years continues to the second half of 2019, maintaining supply constraints to bring balance to the global inventories of oil.The bilateral comment is telling. In April, the planned meeting was cancelled to reportedly have more time to analyze market data. However, the second delay, though only for a week, has shown heightened tensions, as decisions have increasingly been driven by Saudi Arabia and Russia, who combine for over 40% of OPEC+ oil production. Falih said all but one OPEC member nation has agreed to delay the group’s meeting until after the G20 summit, and the holdup figures to be Iran, who has been increasingly perturbed by its diminishing influence. Production cuts rely on all members to stick to their word, as each individual country would be economically incentivized to increase production to reap the benefits sown by those who withhold production.IranAlongside voluntary declines from Saudi Arabia and Russia, Iran has been one of the key reasons for lower production recently.  In April, the U.S. reinstated its sanctions on importers of Iranian oil. The sanctions were initially implemented to ramp up “maximum pressure” on Iran as oil is a significant revenue source for the Iranian government. The U.S. is pressuring Iran to curtail its nuclear program and return to the negotiating table on a nuclear deal.Waivers were granted last November to allow countries time to find other sources of supply and three of these countries (Greece, Italy, and Taiwan) have done so as they no longer import any oil from Iran. China and India are the largest importers of Iranian oil whose waivers have been rescinded, which should ramp up pressure on Iran and could have spill-over effects on trade discussions as China expressed displeasure with the U.S.’s decision to reinstate sanctions.Alongside voluntary declines from Saudi Arabia and Russia, Iran has been one of the key reasons for lower production recently.These sanctions are not the only concerns related to Iran. The recent crude price rebound following its 5-month low is due in part to Iran shooting down a U.S. drone, raising already heightened tensions. This comes after attacks in May on two tankers near the Strait of Hormuz, which the U.S. blames on Iran. The Strait of Hormuz, described by the EIA as the world’s most important oil choke point, separates UAE, Oman, and Iran and a significant amount of world oil supply passes through this relatively narrow shipping route.The White House has put out two statements in the past few days, seeking to set the record straight and with Saudi Arabia, UAE, and the UK jointly condemn these attacks. The situation remains fluid and volatile and continues to threaten the flow of oil, as President Trump began the week by announcing new sanctions on Iran.Rising U.S. ProductionProduction cuts from OPEC+ (intentional or not) have been able to raise prices since the lows seen at the end of 2018, and the U.S. has been one of the prime benefactors. The U.S. has been able to increase its global market share, increasing production to fill the void left by OPEC+ production. Additionally, any elevated prices caused by these production cuts have also increased top line revenues for American producers, a fact not lost on OPEC.According to the EIA’s latest Short Term Energy Outlook (“STEO”), U.S crude oil production increased 17% in 2018, peaking at an all-time rate of 10.96 million b/d.  This was capped by a December that saw 11.96 million b/d, the highest monthly level on record, despite crude prices sliding considerably in the fourth quarter. The EIA expects this growth to continue with production reaching 13.3 million b/d on average by 2020.Slowing Global DemandAccording to the STEO, the EIA is projecting lower crude prices for 2019 due to uncertainty about global oil demand growth. In late May, President Trump announced the potential for tariffs on Mexico, which would have particularly negative impacts on the energy industry as the U.S. exports more fuels to Mexico than any other country. Easing continental trade concerns, Mexico became the first country to ratify the USMCA (new NAFTA), though approval has yet to come from Canada or the U.S., and there is no timetable for its passage.Concerns about the U.S.-China trade relations picked up in the second quarter as increased tariffs have been threatened by both sides.Concerns about the U.S.-China trade relations have also picked up in the second quarter as increased tariffs have been threatened by both sides.  Expected industrial activity, as measured by the manufacturing Purchasing Managers’ Index (PMI) declined across several countries in May, and the U.S. PMI fell to its lowest level since 2009.  These contribute to concerns that future economic growth could be lower than expected, which would, in turn, curb oil demand. However, there was optimism on June 20, related in part to hopes that U.S.-Chinese relations would improve when President Trump meets with President Xi at the G20 Summit.Interest RatesOptimism on June 20 wasn’t restricted to trade with China as the Federal Reserve also met the prior day.  The Fed Funds rate has been increased 9 times since December 2015 to a target range of 2.25%-2.50%.  However, it has become increasingly clear that the next change is more likely to be up than down. For the first time in Jerome Powell’s tenure as Fed Chairman, a dissent was cast, which advocated for a rate cut. James Bullard, President of the Federal Reserve Bank of St. Louis, said cutting rates now “would provide insurance against further declines in expected inflation and a slowing economy subject to elevated downside risks. Even if a sharper-than-expected slowdown does not materialize, a rate cut would help promote a more rapid return of inflation and inflation expectations to target."In theory, interest rate hikes tend to be negative for risk assets such as equities and commodities such as energy. Conversely, a rate decrease should make holding these products more attractive and raise the price. More important, however, is the overall message it sends to the economy. If the Fed were to cut rates, even if it cited its inflation target as the reason (and not a global economic slowdown), this would be viewed by the market as a bearish signal, likely sending equities and crude oil prices downward.ConclusionWith the G20 Summit occurring June 28 and 29, we’ll close the quarter with a more informed outlook on global demand going forward. OPEC and OPEC+ meetings are expected to occur July 1 and 2, so we’ll have to wait until the beginning of the third quarter for a decision on increased, steady, or reduced production cuts on the supply side. Even with an announcement at the beginning of the quarter, it will take more time to determine how this production will be further impacted by individual country circumstances, particularly from Iran. In the meantime, the U.S. will likely continue its production to capitalize on the shortfall, even if global demand slows or is already slowing. While interest rate hikes or cuts will likely continue to play a role in market sentiment, it is unlikely we see a change on this front in the near-term.At Mercer Capital, we stay current with our analysis of the energy industry both on a region-by-region basis within the U.S. as well as around the globe. This is crucial in a global commodity environment where supply, demand, and geopolitical factors have various impacts on prices. We have assisted many clients with various valuation needs in the upstream oil and gas industry in North America and internationally. Contact a Mercer Capital professional to discuss your needs in confidence.
M&A in the Permian
M&A in the Permian

Big Deals and Bigger Opportunities

The Permian Basin is one of most prolific oil basins in the world and is the engine driving the resurgence of U.S. energy output. According to the latest EIA Drilling Productivity Report, anticipated oil production for June 2019 in the U.S. is almost 8.5 million barrels per day with the Permian alone accounting for nearly 4.2 million. The importance and impact of this basin to U.S. energy cannot be overstated.Operators in the play have had to pay a premium to access the black gold mine, and companies are still lining up for a chance to get in on the action. While the industry as a whole has been moving into a period of rapid consolidation, a substantial portion of this acquisitive activity has been in the Permian, far more than any of the other major basins.Targets with highly contiguous holdings and acreage have been of particular note to acquirers in the Permian. While acreage continuity has not always been the most important aspect of a potential deal, it has certainly become more of a focal point recently.Recent Transactions in the Permian BasinDetails of recent transactions in the Permian Basin, including some comparative valuation metrics are shown below.Oxy to Acquire Anadarko in $38 Billion DealOn May 10, 2019, Anadarko Petroleum signed a deal to be acquired by Occidental Petroleum (“Oxy”) in a cash/stock deal worth $38 billion. This deal was by far the largest and most newsworthy to come out of the Permian Basin, or any other region, for the year.The transaction creates a $100+ billion “global energy leader” with 1.3 million barrels of oil equivalent per day of production.The agreement concludes one of the most closely-watched bidding wars in recent history with Oxy battling with Chevron to acquire the Permian assets of Anadarko.  A month earlier, Chevron announced an agreement to purchase Anadarko for $33 billion in a cash/stock deal.  Oxy soon joined the fray with a deal that was more accretive to Anadarko shareholders.  The price ultimately became too much for Chevron, who received a $1 billion termination fee as part of the initial deal struck with Anadarko.  Some lauded Chevron for not raising their offer and potentially overpay for the assets, but as it stands, Oxy is the big winner of the prized Permian assets which present plenty of synergies with its existing acreage portfolio.According to Occidental, the transaction creates a $100+ billion “global energy leader” with 1.3 million barrels of oil equivalent per day of production. The company also said the deal provides “compelling strategic and financial rationale for all stakeholders.”Oxy is expected to fund the cash portion of the consideration through a combination of cash and fully committed debt and equity financing, which also includes a $10 billion equity investment by Berkshire Hathaway, Inc in the form of 100,000 shares of cumulative perpetual preferred stock at $100,000 per share. The investment from Berkshire comes at a steep cost though with a warrant to purchase up to 80 million common shares at $62.50 per share as well as a preferred stock dividend of 8% annually.Potential for TakeoverAlthough the Permian is far and away the most covered oil patch in the U.S. by analysts and journalists alike, the Occidental and Anadarko deal has brought some increased scrutiny to the basin particularly in assessing what other potential big deals could be out there. And the analysis seems to point to quite a few.DrillingInfo produced the map below (as of April 30, 2019) of acreage by major operators within the Permian. An interesting observation here is that several of these operators have assets and land that is largely connected. Concentrated assets and contiguous acreage make several of these companies very attractive targets for takeover. Pioneer Natural Resources, for example, has been hard at work becoming a pure-play Permian Basin operator. With the April 26 announcement that it is to sell off the remaining assets in the Eagle Ford, the company has made itself a more attractive takeover target because of its concentrated asset base in the Delaware Basin within the Permian. Contiguous acreage allows operators to drill longer lateral lengths, which are more productive and cost-effective given recent advancements in drilling technology.There are several benefits in owning such contiguous acreage. First, operators can take advantage of economies of scale, as contiguous acreage provides access to subsurface minerals with fewer well pads required, reducing costs.  Logistically, mineral rights considerations are also simplified by consolidation. Contiguous acreage also potentially allows operators to drill longer lateral lengths, which are more productive and cost-effective given recent advancements in drilling technology.Costs are further streamlined as the oilfields are less encumbered by multiple operators each bringing in their own drilling crews. Additionally, armies of tanker trucks for hauling away wastewater for various operators in a crowded field are replaced with efficient networks of surface pipes for wastewater disposal. Companies such as those with adjoining acreage to Pioneer could consider the advantages and synergies of such networks and efficiencies, especially if the infrastructure is already in place.EOG Resources, one of the largest independent operators, owns acreage that borders against Chevron and Occidental in multiple areas. Given the recent loss in the bidding war with Occidental for Anadarko’s assets, Chevron has additional cash (set aside for the prior merger attempt as well as the break-up fee) that could be used for another takeover attempt, and EOG would be an attractive target for the reasons described above.Other pure-play companies such as Diamondback or Concho Resources also have highly contiguous acreage adjacent to large companies who could take advantage of these economies of scale and efficiencies. These companies have been active consolidators in the basin, with Diamondback’s 2018 acquisition of Energen and Concho’s takeover of RSP Permian earlier in that year.ConclusionThe trends for the Permian are apparent. Companies have been working to establish firm footholds in this basin and are willing to pay premiums to get in and stay in. The basin is also in an interesting position that due to the layout of operator acreage and assets, large takeovers of neighboring operators with contiguous acreage and established efficiencies create the opportunity for higher return on investment.We have assisted many clients with various valuation needs in the upstream oil and gas industry in North America and around the world.  In addition to our corporate valuation services, Mercer Capital provides investment banking and transaction advisory services to a broad range of public and private companies and financial institutions.  We have relevant experience working with companies in the oil and gas space and can leverage our historical valuation and investment banking experience to help you navigate a critical transaction, providing timely, accurate and reliable results.  Contact a Mercer Capital professional to discuss your needs in confidence.
Forecasting Future Operating Results for an Oilfield Services Company
Forecasting Future Operating Results for an Oilfield Services Company
In our prior two Energy Valuation Insights blog posts, we detailed the specifics of “what is” and “what are the characteristics of” an oilfield equipment/services company (“OFS”), and detailed the typical approaches and methodologies utilized in valuing OFS companies.  This week, we’ll address some of the special considerations that must be given attention in the appraisal of OFS companies.  Specifically, the challenges in forecasting the future operating results for an OFS company.In the appraisal of an OFS company, the application of the income approach often includes the application of a discount cash flow (“DCF”) methodology.  Actually, one might make the argument that the application of the income approach in appraising an OFS company should nearly always include the application of a DCF methodology, as opposed to relying solely on a capitalization of earnings methodology (“capitalization method”).  While application of a capitalization method can provide a reasonable indication of value for companies in many industries, doing so for an OFS company can be problematic due to the inherent cyclicality of the OFS industry.  One can attempt adjustments to a capitalization method indication of value to account for future deviations in cash flow growth rates (such as those caused by OFS industry cyclicality), but doing so can involve unnecessary subjectivity, resulting in an indication of value that may lack reliability.  Typically, the better, and often more reliable, option is to utilize a DCF method using a forecast of future operating results rather than a capitalization method with imprecise adjustments.Understanding Industry Cyclicality is an Important Factor in Valuing an OFS CompanyIn applying the DCF method, the starting point is, of course, the development of a forecast of future cash flow for the subject company, which typically begins with a forecast of future revenues.  Here we run into the first of several challenges in the appraisal of OFS companies.  The OFS industry is of the most cyclical of industries that analysts can cover.  Not just cyclical with the general economy of the region, nation or world, but cyclical in a way that is much more difficult to predict fluctuations in the price of oil (or natural gas) tied to a whole host of factors including technological, political, and even geopolitical factors can make forecasting complicated very quickly.Several varying forces can make predicting the future demand for oil from a particular region, and therefore, the demand for OFS products/services, quite difficult.Demand for oil and gas, and therefore demand for OFS products/services, can be as simple as the fact that in a robust economy more goods are being bought by end users and consumers.  More purchases of goods, means more goods have to be transported to the end user/consumer, which requires more fuel to facilitate that transportation.  Technology can impact the supply side of the equation as oilfield technology advances can lower the cost of oil production, thereby encouraging greater production even when oil prices are stable, or possibly even in decline, all else being equal.  Local and national politics can impact demand as well.  In the U.S., recent differences in positions on the use of coal as a power source have inserted a new dynamic into the economic demand for oil.  In the geopolitical realm, bans on the importation of oil from certain countries (Iran or Venezuela, for example) have created shifts in demand for oil from other oil-producing countries.These varying forces can make predicting the future demand for oil from a particular region, and therefore, the demand for OFS products/services in that region, quite difficult.  As indicated in the chart below, the timing and magnitude of cycles in the OFS industry can vary significantly.[caption id="attachment_26698" align="alignnone" width="812"]Note: Median year-over-year revenue change among the smaller publicly-traded OFS industry participants.[/caption] Forecasting OFS Company RevenuesIn forecasting OFS company revenues, one must distinguish between the short-term forecast and the long-term forecast.   The short-term forecast will be primarily focused on the current direction of industry revenues, the typical length of industry cycles in estimating the timing of a current down-cycle bottom (or current up-cycle peak), and expectations for the subject company’s revenue cycle relative to that of the OFS industry as a whole (lagging or leading).  The long-term forecast for the subject company will be more focused on the expected timing of a return to the mid-cycle level of revenues and the subject company’s particular expected mid-cycle level of revenue, with a potential adjustment for possible changes in the subject company’s market share.In performing the company level analysis, it’s always important to be aware of past transaction activity, changes in product/service, mix, or changes in markets served.In support of both the short-term and long-term forecasting considerations, an analysis of past OFS industry cycles and of the subject company’s past revenue cycles is warranted.  With access to certain specialized databases, a detailed analysis of industry cycles (or industry participant cycles) can be readily performed.  The same cycle analysis regarding the subject company is possible if the company has a long-enough operating history.  In performing the company level analysis, it’s always important to be aware of past transaction activity (acquisitions, or divestitures), changes in product/service, mix, or changes in markets served, that might influence the results.Based on these analyses, the appraiser must determine reasonable estimates for the following:The time until the then current up-cycle will peak, or current down-cycle will bottomThe revenue level at the current up-cycle peak, or current down-cycle bottomThe time to reaching the next mid-cycle point, or mid-cycle level of revenue Estimates based on a sound analysis of historical industry and subject company data will result in a reasonable revenue forecast.Forecasting ConsiderationsBeyond the industry-wide considerations necessary in developing the OFS company forecast, one must also consider a number of more specific, non-industry-wide factors.  These may include the target market (geographic), the subject company’s specific product/service offerings, the mix of product/service offerings, and the subject company’s ability to weather a current industry down-cycle.Geographic Target MarketUnlike participants in many other industries, OFS industry participants expect that future operating results can be significantly impacted by the geography of their target market, or, more specifically, the geology of their target market.  The cost of extracting oil/gas can vary significantly depending on the basin being served.  Similarly, the cost of processing (refining) oil from different basins can vary significantly, based on the quality of the oil being produced.  For example, according to a 2016 EIA study, lower production costs were more prevalent in the Delaware Basin and Appalachian Basins while higher production costs were more standard in the Eagle Ford and Midland Basins1.The differences in production costs were partially a factor of the geology of the basins, which impacts the specific processes necessary in order to extract the reserves.  In the Marcellus Basin, shallow formations and pad drilling techniques allow for lower cost production, while in the Eagle Ford Basin, deeper and more technically challenging formations tended to result in higher production costs.  This changes over time with experience and technology accelerators, as the Eagle Ford’s costs have come down for several producers in the past year.Cost differentials can result in potentially significant differentials in drilling and production activities across the various basins, depending on prevailing oil prices.These cost differentials can result in potentially significant differentials in drilling and production activities across the various basins, depending on prevailing oil prices.  Proximity to refiners also plays a role as transportation costs can add up.  Prices at $60/bbl, for example, may spur activity in one basin while another basin remains at markedly lower activity levels, often captured in “break-even” prices.  As such, in estimating future operating activity levels of an OFS company, one must be aware of the expected oil prices and the level of activity that would be expected in conjunction with those prices in the basins served by the subject company.OFS companies can mitigate some of the cyclicality by diversifying across basins. Operating in multiple markets can spread costs over more operations as well. OFS companies concentrated in one particular basin, on the other hand, would likely experience more volatile swings, particularly if they operate in a high-cost basin.Specific Product/Service OfferingsThe specific products and services offered by the subject OFS company must also be considered, as some services will only experience increased demand at higher oil price points, that justify the operator incurring the additional expense.  For example, even in a period of rising production, a provider of services related to more expense stimulation techniques may not see a significant increase in the demand for its services until a certain price point is achieved.  On the other hand, providers of services that are necessary for more general production activities would be expected to experience cyclical demand for its services more in-line with the general OFS industry.  Some may even be insulated from price declines as E&P companies will continue to demand certain services regardless of price.Mix of Product/Service OfferingsSimilar to the impact of diversification of basins served, diversification across products and services offered can potentially contribute to reduced cycle extremes.  An OFS company might see greater cycle extremes for certain exploration and production services. However, offering multiple services not tied to those same exploration and production activities can provide needed diversification which may mute cycle highs and lows.Financial Condition of the Subject CompanyThe subject company’s financial condition is often given inadequate consideration in forecasting future operating results; however, it can be critical when appraising companies in industries that commonly experience more significant cycle highs and lows, such as the OFS industry.  This is particularly important when the subject industry is facing a material downturn in activity in the early portion of the forecast period.Consideration of a company's financial condition can be critical when appraising companies in industries that experience significant cycle highs and lows, such as the OFS industry.During an industry downturn, certain expenses can’t be avoided, and the subject company may generate negative cash flows until demand returns.  As such, an analysis of the company’s financial condition is important in determining its ability to weather the downturn and participate in the expected improved conditions as the industry cycle swings back to more favorable conditions.Companies that have ample cash reserves, low levels of debt, or a significant ability to reduce fixed costs will be more likely to overcome the impact of the down cycle. Companies that have little cash reserves, substantial leverage, or are less able to cut costs may have to take more significant actions to weather the downturn.  Such actions may impact the degree to which they’re able to participate in the industry’s next upswing in demand.  In forecasting future operating results, one must include an analysis of the subject company’s financial condition and consider what actions may be necessary in order for the company to deal with the short-term cash outflows.  Those actions may, if more extreme, result in the subject company participating to a lesser degree in the eventual industry recovery.Forecasting OFS Company Cash FlowNext, is the task of deriving a cash flow forecast from the revenue forecast, through the forecasting of cost of sales and operating expenses.  In both cases, a greater level of analysis is warranted for OFS industry participants than for participants in industries less subject to large cycles.  The reason being that depending on the relative level of fixed and variable expenses in cost of sales and operating expenses, those expenses, as a percentage of revenues may fluctuate significantly over the course of the industry’s cycle.  As demand for labor, materials, and products will be high near the peak of the industry cycle, their cost will potentially increase relative to revenues, resulting in higher cost of sales relative to revenue and lower gross margins.  The opposite would be expected for time periods near the bottom of the cycle, with demand at a low point and cost of sales lower relative to revenues, resulting in higher gross margins.  Operating expenses can be tied to these peaks and valleys in the industry cycle as well, but the impact may not be as severe, since they have a larger ratio of fixed versus variable components relative to the cost of sales expense.Unlike companies participating in less cyclical industries where it may be reasonable to forecast cost of sales and/or operating expenses as a static, or near static, percentage of revenues, forecasting OFS company expenses (cost of sales and operating) typically requires an analysis of past operating results in order to identify cycles and ranges of company expenses relative to revenue.  The question to be addressed is essentially, what will my cost of sales percentage (of revenues) be at the level of revenue forecasted for each discreet period in the forecast and what will my operating expense percentage be at the level of revenue forecasted for each period in the forecast?  Note that due to the likely presence of a greater fixed/variable expense ratio in operating expenses (than cost of sales), the change in operating expenses as a percentage of revenues over the forecast period will likely be more pronounced than for cost of sales.Extreme Industry Condition ImplicationsRare indeed is the industry that is subject to the potential cyclical extremes of the OFS industry.  As indicated in the chart below, in 2008 oil prices surged to unprecedented levels for several months (that haven’t been seen since) resulting in a significant spike in OFS product/service demand.  Shortly thereafter, in 2009, oil prices dropped sharply to levels that hadn’t been seen since 2003, only to be followed by a sharp increase to a level generally in-line with the price trend that had been established during the 2004 to 2007 period.[caption id="attachment_26700" align="alignnone" width="740"]Source: EIA[/caption] Due to these fluctuations in commodity prices, and therefore OFS activity levels, one must be cautious in applying the DCF method.  While typical cycle highs and lows can be dealt with through an analysis of historical industry cycles, periods of extreme highs, or extreme lows, create unusual challenges for OFS forecasting.  No matter the level of industry experience, extreme industry activity (high or low), can easily lead to forecasts that result in unreliable indications of value.  In such instances, while application of an income approach DCF methodology may be warranted and appropriate, it may be the case that reliance on the indication of value derived from this methodology should be afforded less weight relative to the weight afforded indications of value from other valuation methods - likely a market approach guideline company methodology. ConclusionAs indicated, the unpredictable cyclicality of the OFS industry requires careful consideration of many industry-wide and company-specific factors in developing a reasonable forecast of future operating results.  While consideration of such factors should be part of the analysis in the appraisal of businesses in all industries, the impact of these considerations is magnified in highly cyclical industries such as that served by OFS businesses.Mercer Capital has a breadth and depth of experience in the appraisal of businesses in the oil and gas industry that is rare among independent business appraisal firms.  Our Energy Team is led by professionals with 20 to 30+ years of experience involving upstream businesses (E&Ps, oilfield product manufacturers and oilfield service providers), midstream (gathering systems, pipeline MLPs, pipeline processing facilities), and downstream (refining, processing, and distribution).   Feel free to contact us to discuss your valuation needs in confidence. 1 EIA: Trends in U.S. Oil and Natural Gas Upstream Costs – March 2016
How to Value an Oilfield Services Company
How to Value an Oilfield Services Company
When valuing a business, it is critical to understand the subject company’s position in the market, its operations, and its financial condition. A thorough understanding of the oil and gas industry and the role of oilfield service (“OFS”) companies is important in establishing a credible value for a business operating in the space. Our blog strives to strike a balance between current happenings in the oil and gas industry and the valuation impacts these events have on companies operating in the industry. After setting the scene for what an OFS company does and their role in the energy sector, this post gives a peek under the hood at considerations used in valuing an OFS company.Oil and Gas Supply ChainThe oil and gas industry is divided into three main sectors:Upstream (Exploration and Production)Midstream (Pipelines and Other Transportation)Downstream (Refineries) [caption id="attachment_26635" align="alignnone" width="790"]Source: Energy Education[/caption] Exploration and production (E&P) companies search for reserves of hydrocarbons where they can drill wells in order to retrieve crude oil, natural gas, and natural gas liquids. To do this, E&P companies utilize oilfield service (OFS) companies to help with various aspects of the process including pumping and fracking, land contract drilling, and equipment manufacturers. E&P companies then sell the commodities to midstream companies who use gathering pipelines to transport the oil and gas to refineries. Finally, refiners convert raw crude and natural gas into products of value. Oilfield Services OperationsE&P companies may own the rights to the hydrocarbons below the surface, but they can’t move them down the supply chain without the help from OFS companies in the extraction process. We can think of various OFS companies being subcontractors in the upstream process much like a general home builder might bring in people specially trained to set the foundation or wire electrical or plumbing. Because the services provided often require sophisticated technology or extensive technical experience, it stands to reason OFS companies would be able to charge a premium price. Thus, OFS would appear to be insulated from the commodity pricing that is inherent in the industry. However, E&P companies are the ones contracting these companies, and if oil prices decline enough, they are pressured to decrease production (and capex budgets), reigning in activity for OFS companies. This is where the specific service provided matters.Regardless of service provided, or industry for that matter, there are certain aspects of a business that should always be considered.As we discussed last week, there are a variety of different services provided by OFS companies. Companies that fall into the category of OFS can be very different from one another as the industry is fragmented with many niche operators. For example, companies servicing existing production are less impacted by changes in commodity prices than OFS companies that service drilling, as these activities are the first to decrease. Regardless of service provided, or industry for that matter, there are certain aspects of a business that should always be considered.Oilfield Equipment and Service Financial AnalysisA financial analyst has certain diagnostic markers that tell much about the condition of a business both at a given point of time (balance sheet) and periodically (income statement).Balance Sheet. The balance sheet of an OFS company is considerably different from others in the energy sector. E&P companies have substantial assets attributed to their reserves. Refiners predominantly have high inventory and fixed assets. OFS companies will depend on the type of product or service, but generally, they tend to have a working capital balance that consists more of accounts receivable than inventory, like other service-oriented businesses. According to RMA’s annual statement studies, A/R made up 22.3% of assets while inventory was 9.3% for Drilling Oil and Gas Wells (NAICS #213111).[1] These figures were 26.6% and 10.8%, respectively for Support Activities for O&G Operations (#213112). Notably, drilling operations had a higher concentration of fixed assets (46.8%) compared to other support services which comprised 35.7% of assets. Broadly speaking, this illustrates the different considerations within the OFS sector as far as the asset mix is concerned.Income Statement. The development of ongoing earning power is one of the most critical steps in the valuation process, especially for businesses operating in a volatile industry environment.  Cost of goods sold is a significant consideration for other subsectors in the energy space, particularly as the product moves down the supply chain towards the consumer. This is not the case for OFS companies. RMA does not even break out a figure for gross profit, but instead combines everything under operating expenses. Still, OFS companies deal with significant operating leverage. If expenses are less tied to commodity prices that means costs may be more fixed in nature. That means when activity decreases and revenues decline, expenses don’t decline in lock-step resulting in margin compression and profitability concerns. While the balance sheet does not directly look at income, it can help determine sources of return. Fixed-asset heavy companies like drillers tend to be more concerned with utilization rates as the more their assets are deployed, the more money they will earn. On the other hand, predominantly service-based companies that rely on their technology and expertise tend to be more concerned with the market-determined prices they are able to charge and terms they are able to negotiate. Additionally, OFS companies may have significant intangible value that may not be reflected on the balance sheet. Intangible assets developed internally are accounted for differently than those that are acquired, and a diligent analyst should be cognizant of assets recorded or not recorded in developing an indication of value.How to Value OFS?There are fundamentally three commonly accepted approaches to value: asset-based, market, and income.  Each approach incorporates procedures that may enhance awareness about specific business attributes that may be relevant to determining an indication of value. Ultimately, the concluded valuation will reflect consideration of one or more of these approaches (and perhaps several underlying methods) as being most indicative of value.The Asset-Based ApproachThe asset-based approach generally represents the market value of a company’s assets minus the market value of its liabilities.The asset-based approach can be applied in different ways, but in general, it represents the market value of a company’s assets minus the market value of its liabilities. Investors make investments based on perceived required rates of return, so the asset-based approach is not instructive for all businesses. However, the capital intensive nature of certain OFS companies does lend some credence to this method, generally setting a floor on value. If companies have paid off significant portions of their debt load incurred financing its equipment, the valuation equation (assets = liabilities + equity) tilts towards more equity and higher asset approach indications of value. Crucially, as time goes on and debt is serviced, the holding value of the assets must be reassessed.  Price paid, net of accumulated depreciation may appear on the balance sheet, but if the equipment or technology begins to suffer from obsolescence, it will have less value in the marketplace. For example, due to the shale revolution in the United States and the increased demand for horizontal drilling, equipment and services that facilitate vertical drilling have less market value than it did less than a decade ago. Ultimately, the asset-based approach is typically not the sole (or even primary) indicator of value, but it is certainly informative.The Income ApproachThe income approach can be applied in several different ways. Generally, analysts develop a measure of ongoing earnings or cash flow, then apply a multiple to those earnings based on market risk and returns. An estimate of ongoing earnings can be capitalized in order to calculate the net present value of an enterprise.  The income approach allows for the consideration of characteristics specific to the subject business, such as its level of risk and its growth prospects relative to the market through the use of a capitalization rate. Stated plainly, there are three factors that impact value in this method: cash flows, growth, and risk. Increasing the first two are accretive to value, while higher risk lowers a company’s value.The income approach allows for the consideration of characteristics specific to the subject business.To determine an ongoing level of earnings, scrutiny must be applied to historical earnings. First, analysts must consider the concentration of revenues by customers.  A widely diversified customer base is typically worth more than a concentrated one.  Additionally, an analyst should adjust for non-recurring and non-normal income and expenses which will not affect future earnings. For example, disposing of assets utilized in the business is not considered an ongoing source of return and should be removed from the company’s reported income for the period when the disposition occurred. The time period must also be considered. Assuming cash flows from last year will continue into the future may be short-sighted in the energy sector. Instead of using a single period, a multi-period approach is preferable due to the industry’s inherent volatility, both in observing historical performance and projecting into the future. Discounted cash flow (DCF) analyses are an important tool, but factors such as seasonality, cyclicality, and volatility all call for a longer projection period.After developing the earnings to be capitalized, attention is given to the multiple to be applied.  The multiple is derived in consideration of both risk and growth, which varies across different companies, industries, and investors. When valuing an OFS company, customer concentration is of particular concern to both risk and growth. Developing a discount rate entails more than applying an industry beta and attaching some generic company risk premium. Analysts must look deeper into the financial metrics addressed earlier and consider their market position. Are they financially stable or over-levered by either fixed costs or debt? Are they a sole provider or one of many? If more players are entering the market, prices charged may be lower than those historically observed. If a company stops investing in its equipment and technology, demand for the company’s products and services declines. Again, metrics such as utilization and day rates are important to analyze when developing a discount rate.Income is the main driver of value of a business as the goal is to generate a reasonable return (income) on its assets. People don’t hang a sign above their door and go into business if they don’t think they will eventually turn a profit. Still, differences of opinion on risk and growth can occur, and analysts can employ a market approach as another way to consider value.The Market ApproachAs the name implies, the market approach utilizes market data from comparable public companies or transactions of similar companies in developing an indication of value. In many ways, this approach goes straight to the heart of value: a company is worth what someone is willing to pay for it. The OFS subsector is a fragmented industry with many niche, specialty operators. This type of market lends itself to significant acquisition activity.However, transactions must be considered with caution. First, motivation plays a role, where a financially weak company may not be able to command a high price, but one that provides synergies to an acquirer might sell for a premium. Transactions must also be made with comparable companies. With many different types of companies falling under the OFS umbrella, analysts must be wary of comparing apples to oranges. While they work in the same subsector, there are clearly important differences between equipment manufacturers and pumpers and frackers. Untangling the underlying earnings sources of these businesses is important when looking at guideline transactions as well as directly comparing to guideline companies.In many ways, the market approach goes straight to the heart of value: a company is worth what someone is willing to pay for it.Larger diversified players, such as Schlumberger and Halliburton, are more likely to provide similar services to companies an analyst might value, but their size, sophistication, and diversification of services likely renders them incomparable to smaller players. Given the relative considerations and nuances, taking their multiples and applying a large fundamental adjustment on it is crude at best and may miss the mark when determining a proper conclusion of value.Analysts using a market-based approach should also be judicious in utilizing the appropriate multiple and ensuring it can be properly applied. Industries focus on different metrics and it is important to consider the underlying business model. For E&P companies, EV/EBITDAX may be more insightful as capital expenditure costs are significant and can be throttled down in times of declining crude prices. For OFS companies, potentially relevant multiples include EV/Revenue and EV/Book Value of Invested Capital, but there is no magic number, and these useful metrics cannot be used in isolation. Ultimately, analysts must evaluate the level of risk and growth that is implied by these multiples, which tends to be more important than the multiples used.The market approach must also consider trajectory and location. There’s a difference between servicing vertical wells that have been producing for decades as opposed to the hydraulic fracturing and long horizontal wells in the Delaware Basin. Distinctions must also be drawn between onshore and offshore as breakeven economics are similar (don’t produce if you can’t earn a profit), but costs related to production vary significantly.Ultimately, the market-based approach is not a perfect method by any means, but it is certainly insightful. Clearly, the more comparable the companies and the transactions are, the more meaningful the indication of value will be.  When comparable companies are available, the market approach should be considered in determining the value of an OFS company.Synthesis of Valuation ApproachesA proper valuation will factor, to varying degrees, the indications of value developed utilizing the three approaches outlined. A valuation, however, is much more than the calculations that result in the final answer. It is the underlying analysis of a business and its unique characteristics that provide relevance and credibility to these calculations. This is why industry “rules of thumb” or back of the napkin calculations are dangerous to rely on in any meaningful transaction. Such calculation shortcuts fail to consider the specific characteristics of the business and, as such, often fail to deliver insightful indications of value.A thorough approach utilizing the valuation approaches described above can provide significant benefits. The framework provided here can facilitate a meaningful indication of value that can be further refined after taking into account special considerations of the OFS industry that make it unique from other subsectors of the oil and gas industry. In our next post, we plan to delve deeper into these special valuation considerations beyond the framework established in this post. Stay tuned…[1] 2018-2019 RMA Statement Studies. NAICS #213111 and 213112. Companies with greater than $25 million in sales.
What is an Oilfield Service Company?
What is an Oilfield Service Company?
The oilfield equipment and services (or OFS) industry refers to all products and services associated with the oil and gas exploration and production process, i.e. the upstream sector of the energy industry.  In general these companies are engaged in the manufacturing, repair, and maintenance of equipment used in oil extraction and transportation.Products such as seismic testing, transport services, and directional services for horizontal drillers in addition to well construction, and production and completion services are generally what most would typically think when an oilfield services company comes to mind.However, the range of products and services under the OFS umbrella is wide and include many technology-based services that are vital for successful field operations. Such services include locating energy sources, energy data management, drilling and formation evaluation, geological sciences, and many others. Technological innovation over time has led to increased efficiencies in resource extraction and management, and larger OFS companies such as Schlumberger and Halliburton have capitalized on technology-based services to meet the increasing demand in this subsector. Other OFS companies such as Helmerich & Payne continue to specialize in legacy services, including rigs and equipment manufacturing, drilling services, and products. How Do Oilfield Services Companies Fit in the Industry?OFS providers in their modern form arose through a combination of factors dating back to the oil price slump in the late nineties and the mega-mergers of BP-Amoco in 1998 and Exxon-Mobil in 1999.  Mergers of this size allowed for synergies of logistics and allowed for restructuring and optimization of assets.While the advantages of these mergers were clear in the downstream segment, the impact for upstream was not so apparent. In fact, the in-house ownership of these various types of services created inefficiencies and redundant cost centers that made it expensive to provide necessary upstream services without impacting the bottom line.These factors and segment trimmings enabled the development of a specialized oilfield service industry, which today provides the majority of the technology (primarily assets and people) and innovation essential across the life cycle of an oil and gas development.The rationale for the outsourcing of service capability can be summarized in three key points:Economies of scale – Specialization of companies in the service chain allows for intense competition among suppliers while also facilitating technical innovation. In-house ownership of services might not have provided the rapid rise of such competition and technology advances that the industry has seen over the last couple of decades.Capital efficiency – A service company able to supply a wide range of clients (large/small public, government-owned, independents, etc.) would expect to be able to achieve higher rates of utilization for their assets and therefore better return on capital employed than could an E&P company limited by their own inventory.Accountability – Third-party service providers arguably allow for increased accountability and efficient creation of reward structures between operator/contractor. However outsourcing may lead to greater operator risk, execution delays, and even contract mispricing.Key Drivers and Indicators of the Oilfield Services IndustryAt its core, the revenue of the OFS companies is a function of the capital and operating expenditure of the E&P companies, which is in turn governed by current and future expectations of the price of oil & natural gas.There are of course several other factors that come into play (advances in technology, climate, seasonality of spending, availability of financing, political factors, etc.), but ultimately it is the supply and demand balance and market fundamentals which determine incentives for investment by these companies. Below is a non-exclusive list of leading indicators that are used to gauge the outlook and demand across the OFS sector:E&P Capital Expenditure Budgets – Size of capex budgets will ultimately determine how the OFS industry will perform as whole. E&P companies will typically begin drafting capex budgets for the next year in the final quarter of the current year. Many will then announce their forward spending plans, strategy, and quarterly/annual results to the market through quarterly earnings calls and press releases. These calls and news releases tend to be closely watched as a leading indicator of future demand. However, historical trends before the oil collapse in 2014 showed that large companies tended to overspend whereas companies at year end 2018 have been tight on capex budgets, even in rising oil price environments. Lean budgets will push the use of third party services down the priority list resulting in hard hits to an OFS company’s revenue stream.Rig and Well Counts – Historically, one of the most closely followed measures of the level of demand for the OFS industry is the active rotary rig count. Baker Hughes began publishing the North American active rig count on a weekly basis since 1944 and initiated the monthly international rig count in 1975. Rig counts have historically been treated as a business barometer for the drilling industry and its suppliers. The thought is when drilling rigs are active, they consume products & services produced by the OFS industry; however, well counts have been trending towards being the primary leading indicator of profits. The reason is in part due to “pad drilling”, in which multiple wells are drilled from one site. Combined with technological advances and logistical efficiencies, having multiple wells per pad in a shale play has a greater effect on performance in a given area. In essence, fluctuating well counts on a seemingly stagnant overall rig count provide a different picture of the health of the sector. Therefore tracking well counts in the last decade has improved predictive power than indications provided solely by rig counts.Day-rates - Day rate refers to all in daily costs of renting a drilling rig, and roughly makes up half of the cost of an oil well. The operator of a drilling project pays a day rate to the drilling contractor who provides the rig, the drilling personnel and other incidentals. The oil companies and the drilling contractors usually agree on a flat fee per contract, so the day rate is determined by dividing the total value of the contract by the number of days in the contract. Although less easily observable, it is also possible to track trends through day rate announcements for other less ‘liquid’ marine sectors, such as seismic vessels, supply boats, support vessels and installation/heavy-lift vessels. Analyzing day rates in combination with metrics like rig utilization allows investors to gain insight into the overall supply and demand picture of the OFS industry at large. When day rates increase, this implies decreased supply of OFS providers or increased demand for their services.Equipment orders – A steady stream of new orders is critical of any manufacturing company, and it is no different with OFS sector. It is customary for OFS companies to announce major equipment orders, i.e. rig orders, floating production storage and offloading (FPSO) orders, underwater equipment orders, drilling packages, etc. and these announcements provide useful insights as to the level of demand across various parts of the service lifecycle.Backlogs – Similar to engineering and construction companies, many OFS companies announce backlogs as a snapshot of the health of their businesses. Since backlog is not an audited measure and its definition can vary from company to company, it is not a hard and fast figure that should be taken at face value. While a sufficient backlog typically means the company is busy, there is give and take for backlogs that extend too far out. Unless specified by management, the timing of backlogged projects can be fairly unpredictable with durations as short as a few months to as long as a few years. But the general thought in analyzing company backlog is to provide an indication of value of revenue not yet recognized and demand for services to be rendered in the future. In our next post, we'll explore valuation issues relevant to oilfield service companies. Stay tuned.
Royalty and Mineral Value Proposition Highlights Otherwise Underperforming Energy Sector
Royalty and Mineral Value Proposition Highlights Otherwise Underperforming Energy Sector
The burgeoning mineral market is leading the way for an energy sector that has lagged in returns for several years now.  This was one of the themes from the DUG Permian Basin Conference in Fort Worth last month.  Among the discussion, presenters including Scott Noble, CEO of Noble Royalties and Rusty Shepherd of RBC Capital Markets highlighted the ascension of the estimated $400 to $600 billion onshore mineral market in the U.S., depending on who’s doing the estimating.The interest in the segment has been undergirded by the attractive cash returns coupled with fewer risks and burdens.The interest in the segment has been undergirded by the attractive cash returns coupled with fewer liability risks, operating risks, and expense burdens.  In addition, royalty owners retain ownership rights to perpetuity.  These characteristics of royalty and mineral plays have drawn investors in as compared to the market’s negative response to upstream management teams merely seeking to beef up the size of their reserve reports.Overall, the energy market’s returns have been subpar.  As a sector, energy has lagged all other major sectors over the past several years. In 2018, the returns were again at the bottom of the heap. [caption id="attachment_26449" align="aligncenter" width="940"]Source: Company filings and FactSet[/caption] However, there is an energy sub-sector that has been an emerging bright spot: public mineral aggregators. Brigham Minerals (MNRL) is the latest mineral acquisition company to go public following a trend of other large mineral rights and royalty companies to IPO in recent years. Brigham began trading on April 18 at $18.00 per share on the New York Stock Exchange.  Brigham became the fifth mineral company to go public since 2014, far outpacing the energy sector in general. [caption id="attachment_26456" align="aligncenter" width="885"]Source: Company filings and Brigham S-1[/caption] The attraction and growing appetite for mineral aggregators lies in its asset level economics.  Several presenters at the conference touched on various factors that are driving returns and valuations.  While current producing wells bring in monthly cash flow, they also demand the lowest returns.  According to B.J. Brandenberger of Ten Oaks Energy Advisors, producing minerals are commonly purchased on expected returns of 8% to 10%, whereby DUC wells and permitted wells currently have expected returns around 12% and 15%.  Undeveloped properties are often valued at over 20% expected return profiles depending on various factors such as the hydrocarbon producing layers in the ground (or “benches” as the industry sometimes calls them).  Most of the uncertainty and intrigue has to do with undeveloped properties.  The reasons that expected returns are so much higher than producing properties lies in unknowns such as drilling timing, operator quality and expertise, production assumptions, and pricing differentials to name a few.The mineral segment is representing an economic bright spot in a sector that, while improving, has resided in the dark from a stock return perspective.This kind of uncertainty comes with the opportunity for outsized returns resulting in market attraction.  According to Oil and Gas Investor’s reckoning, there were 12 companies listed in their mineral company directory in 2015.  In 2019, this has ballooned to 140.Public momentum has grown as demand for these investment vehicles is high. Given most new entrants in the market are private equity funded with exit expectations in upcoming years, the chances are high that we see an increase in the number of IPOs from mineral aggregators in the future compared to upstream and E&P companies.  Time will tell.  In the meantime, the mineral segment is representing an economic bright spot in a sector that, while improving, has resided in the dark from a stock return perspective.
Brigham Minerals IPO Brings Spotlight to Oil & Gas Market
Brigham Minerals IPO Brings Spotlight to Oil & Gas Market

Mineral Aggregators are Leading the Forefront in an Underwhelming Energy Sector

Initial public offerings in the upstream and midstream sectors of the oil and gas market have been lackluster at best for quite some time, and the trend has continued through the first quarter of 2019. Despite the rebounds in the energy sector and broader market to start the year, there has been a scarcity of energy equity capital markets activity, thus resulting in fewer IPOs in the E&P and upstream and is exacerbated by the fact that companies in this space have been underperforming relative to the broader market. This continued lack of activity has made this market fundamentally “underweight” due to the disproportionally small size of available public equities relative to the immense use and value of oil and gas in the national economy. However, in the midst of an underperforming energy market, there is a sector that has been an emerging bright spot: public mineral aggregators. Brigham Minerals (MNRL) is the latest mineral acquisition company to go public following a trend of other large mineral rights and royalty companies to IPO in recent years. Brigham began trading on April 18 at $18.00 per share on the New York Stock Exchange. While we have addressed trends in the mineral aggregators and royalty MLPs, we are taking a closer look into what these companies have to offer the investing public and why they have been so popular in recent years. We continue to see an uptick in IPO activity in this sector as the value of these companies addresses the current wants and needs of energy investors, i.e. high yield cash returns with low-risk characteristics. The timeline below shows how some of the major players in this space have appeared only within the last five years. [caption id="attachment_26224" align="aligncenter" width="680"]Source: Company filings and Brigham S-1[/caption] In this post, we will review the continued IPOs and valuation implications for the mineral aggregators market as well as examine Brigham’s operations and placement in this sector.Energy IPOs Slide While Minerals ShineIn the wake of the oil crash in 2014, there have been a total of 33 IPOs in the U.S. oil and gas market from 2015 through Q1 2019, excluding mineral aggregators. This contrasts sharply with the average of approximately 23 IPOs per year from 2011 – 2014.  This decline is illustrated in the chart below, which tracks deal volume by year in various subsectors of the energy market.[caption id="attachment_26223" align="aligncenter" width="892"]Source: Gibson Dunn Presentation "IPOs and Capital Markets Developments in the Oil and Gas Industry," February 26, 2019[/caption] The declines of IPO activity in recent years has been consistent with overall investor sentiment in the upstream and E&P space in that investors have been eager for current yield, not the future growth that these companies have been pedaling. These companies have been reinvesting into additional acreage and capital expenditures, leaving next to no free cash flow and little in the form of dividends to investors. While E&P and upstream IPOs have been trending downwards overall in the past five years, IPOs for mineral aggregators have been increasing.Since many of these newer companies are typically in the high growth and investment phases, they have achieved the capital necessary for growth through private funding rather than through public channels. So why have mineral aggregators been so popular in the public capital markets in a sector that has been so unimpressive from an IPO standpoint?Mineral aggregators have the ingredients investors have been craving for some time. They are cash flow positive, high margin, and have dividend yields that provide healthy returns straight to the investor’s pocket. They also do not carry the typical risk profile of traditional E&P and upstream companies as mineral aggregators provide opportunities to be exposed to mineral plays and benefit from technological advances without taking operator risk.While E&P and upstream IPOs have been trending downwards overall in the past five years, IPOs for mineral aggregators have been increasing, currently averaging around four per year and are continuing at an increasing rate going into 2019.Valuation ConsiderationsBased in Austin, Texas, Brigham Minerals had initially set out to raise $100 million in their IPO, but then increased the amount to be raised to $261 million at $18 per share in an updated S-1 filed on April 9 due to higher than expected demand. Current holdings for Brigham are shown below:[caption id="attachment_26211" align="aligncenter" width="755"]Source: Company filings and Brigham S-1[/caption] [caption id="attachment_26212" align="aligncenter" width="1000"]Source: Company filings and Brigham S-1[/caption] Brigham is averaging approximately 4,579 boe/d of production on approximately 68,800 net royalty acres as of 12/31/2018, pro forma, with a little more than half of the production being oil. Net income attributable to common shareholders was $0.66 per share, and adjusted EBITDA per share came out to approximately $1.11 per share attributable to common. The large gap here is due to depreciation and depletion rates nearly doubling in 2018 due to higher depletion because of the significant increase in production volumes in the current year and a revised depletion rate after evaluation of current reserve reports. By investing directly in the cash flows, mineral aggregators are able to bypass some of the riskier and more costly upfront aspects of the process, turning their investment into a return more quickly.After going public, Brigham will have an influx of cash which it can use to acquire more mineral interests, leading to increased production and free cash flow. At first glance, this might appear to be similar to the reinvestment cycle for E&P companies, but there are important differences. The mineral interests acquired are a revenue stream that can almost immediately be paid out as dividends to investors because the investment is in properties that are already producing and the mineral aggregators receive a portion of the proceeds. Contrast this to an E&P company that reinvests its cash flows into new projects where it must purchase property, equipment, infrastructure, etc. There are large upfront costs that eat into this capital and frequently require taking on debt as well. Before their investors start to realize a return, E&P companies aim to recoup their expenses first, not to mention servicing the debt. By investing directly in the cash flows, mineral aggregators are able to bypass some of the riskier and more costly upfront aspects of the process, turning their investment into a return more quickly.Market cap at the time of the IPO launch was approximately $377 million, and accounting for cash and debt on the books as of the 12/31/2018 financials, we arrive at an estimated enterprise value of approximately $514 million.Below is a table of selected multiples using these calculated metrics as well as other comparable mineral aggregators: Compared to other competitors in the mix, it would make sense for multiples for Brigham to come in under the peer group given the lower production figures. However, utilizing proceeds from the IPO to continue to acquire additional royalty acreage could push the Brigham into a position that is comparable in size and value to those like Falcon and Kimbell, so as long as it can produce free cash flow to pay out high dividends that investors have become accustomed to receiving from these other companies. Location and Production MixBrigham’s operations and focus are semi-diversified compared to other publicly traded mineral aggregators and has the most in common with Kimbell in this respect.  What do we mean by this?  While Brigham is not as concentrated in a single basin like Viper (Permian focus) and Falcon (Eagle Ford focus), it’s more focused than Black Stone which is by far the most diversified in its class with approximately 89% of holdings falling into the “other” category due to being scattered across multiple, non-traditional plays.  There are benefits and drawbacks to both concentrated versus non-concentrated strategies.  Consider the table below: Brigham sets itself apart by its presence in the DJ and Williston basins.  No other mineral aggregator has a concentrated or material focus there.  As well activity picks up in this area, Brigham will benefit.  However, it also misses out on activity in the Eagle Ford as well as gas driven plays such as the Haynesville and Appalachia. ConclusionAs we’ve noted before, this market has been frequently discussed among industry professionals for some time and has been featured regularly at oil and gas conferences. The vast market of the public royalty aggregators has been gaining momentum as investor demand for these investment vehicles is high. Given these factors, the chances are high that we see an increase in the number of IPOs from mineral aggregators in the future compared to upstream and E&P companies.In an industry that has seen a decline in public market activity that coincided with the steep drop in oil prices, mineral aggregators like Brigham have emerged as an attractive opportunity for investors looking to gain exposure to the industry with an opportunity to participate in the benefits sooner rather than later.At Mercer Capital, we have valued mineral and royalty rights located across the country.  We understand how the location of your assets affects value and work to monitor transactions in each region to understand the state of the current market.   Contact a Mercer Capital professional today to discuss your valuation and transaction advisory needs in confidence.
2019 Eagle Ford Shale Economics
2019 Eagle Ford Shale Economics

Challenging For Valuation Title Belt

Investors and boxing fans have some things in common. First, they both prefer champions. Second, there tends to be attention on heavyweights, when the best fighters may be in a different class.Several attributes put the Eagle Ford among the most profitable shale basins in the U.S.In the oil patch’s proverbial basin battle of economics and relative value, the Eagle Ford Shale is coming on strong. Granted, the Eagle Ford Shale may not reside in the same heavyweight class as the Permian Basin. Indeed, the Permian is in a class of its own and even may be winning over Saudi Arabia’s behemoth Ghawar field in a battle for the title of the largest oil field in the world. However, from a pound for pound well economics standpoint, the Eagle Ford Shale is currently a formidable challenger to the Permian due to several advantages in key areas: breakeven prices, well costs, certain productivity metrics and proximity. These attributes put it among the most profitable shale basins in the U.S. Some well-known operators such as BP and Chesapeake have noticed and are putting big money behind this play.Ranked Contender Or Forgotten Champion?Although the Eagle Ford is a relatively mature basin compared to some other U.S. shale plays, the area has experienced a valuation resurgence over the past twelve months, and it’s not being driven by just the uptick in oil prices. Consider the transaction activity in the table below:[caption id="attachment_26150" align="aligncenter" width="1000"]Source: Shale Experts, Company Reports, EIA [/caption] Activity, dollars and commitment have all swelled. This activity was anchored by two deals: (i) BP’s purchase of BHP Billiton and (ii) Chesapeake’s Wildhorse acquisition. WildHorse and Chesapeake were the fourth and fifth largest drillers in the region, respectively in 2018. Chesapeake appeared to pay a little more attention to current production, while BP’s acquisition appeared more geared towards future acreage. It’s also worth noting that although BP bought assets in other areas such as the San Juan Basin, Wamsutter area and Anadarko Basin, it’s shedding those assets to focus, in part, on the Eagle Ford. Regardless, the relative Eagle Ford acreage prices more than doubled while production values increased generally in lockstep with commodity prices. In a time where oil and liquid production (as opposed to reserve accumulation) is the energy industry’s focus, the Eagle Ford Region is, according to the EIA, the second most prolific oil region in the United States from a myriad of standpoints: (i) overall oil production, (ii) per rig production and even (iii) DUC well count. Additionally, it is home to some of the lowest breakeven prices in the country, certainly from the standpoint of shale plays. Why are costs low? The answer lies in shallower wells, lower cost drilling, higher cuts (meaning there’s more oil and less water produced) and resultant premium commodity pricing near the Gulf Coast. In a time where Permian differentials were particularly wide in 2018, this pricing advantage was helpful to Eagle Ford shale producers. Why are costs low? The answer lies in shallower wells, lower cost drilling, higher cuts and resultant premium commodity pricing near the Gulf Coast.Producers are encouraged by this. At an industry conference last fall, Conoco Phillips’ Greg Leville said that there were certain areas where breakevens were as low as between $20 and $30 per barrel. EOG has noted that they can make money at $30 per barrel on some of their leases. This enthusiasm was characterized according to Marathon’s CEO Lee Tillman at another recent industry conference: “I would compare the returns in the Eagle Ford to anything,” he said, given its $4-5 million/well completion costs, oiliness and Louisiana light sweet pricing. “There's really nothing today on a zone-by-zone basis that can touch the Eagle Ford.” Costs can be particularly lower for operators in 2019 that will be focused on producing from existing DUC wells such as Murphy Oil.Other less choice areas of the Eagle Ford do have higher breakevens, but overall the play, particularly its oil window, boasts among the lowest costs in the country challenging the Permian in this respect. A picture of the generalized spread of breakeven prices in the play can be seen in the chart below.[caption id="attachment_26151" align="alignnone" width="1000"]Source: Company Reports & Investor Presentations[/caption] Fighting For Capital EfficiencyThe trends show that key producers (EOG, BPX and Chesapeake) are working towards consolidating their acreage. More money is going into the basin overall, but operators, wary of overspending, are being more strategic about their capex use. The trend is towards the fewest dollars and the most wells. Note particularly the well count below. It’s becoming a more relevant leading metric than rig counts these days. Rig counts can be somewhat misleading when it comes to well count and productivity as the ratios have changed with technology. The key takeaway is that these producers are all growing well counts significantly.[caption id="attachment_26152" align="aligncenter" width="1000"]Source: Company Reports & shaleexperts.com[/caption] In addition to this group, SM Energy’s capital plan is overall down from last year, but it is increasing its Eagle Ford spending. The hope is that with more experience than other basins, being longer in the tooth will pay off in the near and intermediate term. It also helps that gas produced in the basin will be very competitive in the oncoming LNG market growth on the Texas coast. Get Stronger Or Get Out Of The RingThe prognosis for the Eagle Ford is not all positive. The play struggles (as do other basins) with steep decline curves and production replacement, thus impacting rates of return. Economic critics of the shale plays warn of the “treadmill” effect of replacing production and the costs to do so. There is validity to this. Follow on wells in pad drilling have had productivity problems known as parent-child well interference. Carrizo and Equinor have changed their frac designs to attempt to counter this, and the downside risk to BP’s Eagle Ford bet is that they will be able to flatten their declines enough to keep Eagle Ford wells economical for longer periods of time. Many companies have questioned where Eagle Ford assets fit in their long-term plans. Encana, a reputable Canadian producer, has recently characterized their Eagle Ford acreage as “non-core.” Pioneer Resources has been selling their Eagle Ford positions over the past year, and Earthstone Energy is leaving the play. A long time region producer, Sanchez Energy, was recently delisted from the NYSE.Pound For Pound – A Strong Challenger For The Valuation TitleThese issues can be warnings to investors to be sure, but they can also be interpreted as a natural part of the consolidation cycle in the play as top producers commit and smaller or less successful operators step out of the proverbial ring. The good news for these exiting producers is that they are getting better prices as they leave. Where they cashed out around $8,000 per acre a year or more ago, many are getting closer to $18,000 per acre now. Even gas-heavy producers are more optimistic as the Eagle Ford is the single most proximate play to many oncoming LNG facilities in South Texas.Will the Eagle Ford win the profitability fight with other basins? It may not have the scale or heft of the Permian, but its profitability punches are as strong as anyone's.Originally appeared on Forbes.com.
An Overview of Salt Water Disposal
An Overview of Salt Water Disposal
Over the last 12 years the oilfield waste water disposal industry has grown exponentially, both on an absolute basis, and by rank of its importance/size among the oilfield services. This growth has been largely driven by the increased volumes of waste water generated in the production of oil from shale plays. This post discusses the basics of salt water disposal which has become so important given the rise of hydraulic fracturing.The Impact of the Shale BoomThe shale revolution, starting in the Bakken formation in 2007 and ramping-up in the Eagle Ford and Permian basins beginning in 2011, was largely propelled by the combination of horizontal drilling and hydraulic fracturing (commonly, “fracking”).Over the last 12 years the oilfield waste water disposal industry has grown exponentiallyBecause shale hydrocarbon deposits are located in tight-rock formations, the naturally occurring produced water (water that is naturally present in oil and gas formations, referred to as “formation water”) to oil ratio is lower than in conventional reservoirs that have increased pore space and connectivity. To economically produce oil/gas from unconventional reservoirs composed of shale or tight (low permeability) rock, the reservoir must be stimulated by a process such as fracking.Fracking increases the hydrocarbon flow capacity by creating cracks (fractures) that are then filled with a permeable media (proppant) that allows oil/gas to move out of the rock formation and into the wellbore. Fracking requires very large volumes of water to be pumped into the reservoir to carry proppant and other fluids into the fractures. That water flows back after the frack is complete. When added to naturally occurring produced water, and produced water resulting from other stimulation operations (water flooding and/or steam flooding), fracking results in water/oil production ratios that can exceed 10:1. This results in enormous volumes of produced water (tens of billions of gallons each year), some of which is utilized in additional stimulation activities, but much of which must be disposed of.The Need for Disposal and MeansProduced water (also referred to as “brine”) contains a number of contaminants, both naturally occurring (salt, oils/grease, and organic/inorganic chemicals) and chemical additives utilized in the drilling and operation of the well. Even after treatment to extract some of the impurities, the resulting water (referred to as “salt water”) contains significant contaminants and must be handled carefully and disposed of properly.The method of salt water disposal depends on a number of factors: geology, technology, area infrastructure, and the prevailing climate in the areaThe method of salt water disposal depends on a number of factors, notably the geology of the formation from which the water is produced, as well as the technology and infrastructure available in the area and the prevailing climate in the area. While some particularly arid regions allow for disposal via evaporation from large holding pits, most salt water is disposed of at specialty disposal sites where the salt water is injected by way of a disposal well (salt water disposal, or SWD wells) into natural underground formations.Geographic DistributionA large portion of the U.S. SWD facilities are located in Texas due to the disproportionate amount of shale acreage in the state and the SWD conducive geology in Texas. Far fewer SWD facilities are located in other shale areas, such as the Marcellus and the Bakken, due to less favorable geological formations in those areas. The Marcellus in particular lacks favorable formations for disposal purposes with the number of recent operating SWD wells in Pennsylvania at less than 100, compared to more than 12,000 SWD wells in Texas.Location SelectionWhen siting a SWD facility, a number of factors come into play, including demand, proximity, and geology.DemandDemand might seem to be an easy consideration – just locate the facility in an area where oil and gas operators are generating large volumes of waste water. However, oil production and, therefore, waste water production, in particular areas can vary widely over both short and long periods of time.When siting a salt water disposal facility, a number of factors come into play, including demand, proximity, and geologyProduction in a particular field naturally declines over time as reserves are depleted, but can increase again with technology advances. Oil prices dictate if it’s economically viable for continued production in a particular field, with oil prices being notoriously unstable compared to many commodities due to supply and demand, country-specific political forces and even geopolitical forces.ProximityProximity to the area of waste water disposal demand is important. Proximity can be viewed both as distance and as the availability of the appropriate infrastructure (roads) to efficiently transport the waste water from the production site to the disposal site. Transporting oilfield waste water is a significant expense and for obvious reasons is tied directly to the transport distance. Many oil and gas wells are located in remote areas where the existence of roads, or lack thereof, plays into the SWD location decision.GeologySurface location isn’t the only consideration when choosing a SWD facility site. The location’s geology is just as important.A porous and permeable, non-hydrocarbon bearing zone that is not considered an aquifer under the UIC program is one possible geological formation appropriate for salt water disposal. A second possibility would be a previously depleted oil and gas zone, that is both porous and permeable.For either option, a clear barrier must exist between the target zone and all underground sources of drinking water ("USDWs"), and the drill area needs to be generally clear of any significant geologic faults.ConstructionSalt water disposal wells have very specific construction requirements in order to ensure that there will be no contamination of the area USDW or the environment in general. For example, in Texas, salt water disposal wells are constructed with three layers of casing to ensure that groundwaters are not impacted. The surface casing (the first layer) is a cement encased steel pipe that extends from ground level to a specific minimum distance below the deepest USDW level. The production casing, a pipe that is permanently cemented in the wellbore, is the second casing layer and runs the length of the well. The third protection layer contains the injection tubing string that guides the injected water to the bottom of the well for discharge into the target formation. This construction provides the most secure means of disposing of salt water developed to date in that all three pipes would have to fail at the same time for surrounding groundwater to be contaminated.RegulationRegulation of SWD facilities is significant and thorough. The 1974 Safe Drinking Water Act required the U.S. Environmental Protection Agency ("EPA") to set minimum requirements for salt water injection wells, along with many other wells utilized in disposing of various hazardous and nonhazardous wastes. These EPA established requirements are generally referred to as the Underground Injection Control ("UIC") program. Since the inception of the UIC program, wells classified for injection of oilfield waste liquids have been used to inject over 30 trillion gallons of oilfield salt water without endangering USDWs.Regulation of salt water disposal facilities is significant and thoroughThe UIC program established the necessary requirements for a state to enforce the program within their jurisdiction. In order to assume primacy, the states must demonstrate that their program for UIC enforcement meets the minimum requirements established by the UIC program. At the current time, 33 states and three U.S. territories have primacy for the UIC wells in their jurisdiction. Seven states share primacy with the EPA with the state typically handling one or more classifications of wells and the EPA overseeing the remaining classifications. The EPA maintains primary enforcement of the UIC programs in the remaining ten states and three U.S. Territories.EconomicsA commercial SWD well operator will typically charge between $0.50 and $2.50 per barrel of salt water. The wide range is a simple result of supply and demand. In areas where disposal demand is low, where SWD wells are abundant and have significant capacity availability, the per barrel rate trends towards the lower end of the range. That contrasted with areas where demand for salt water disposal is strong, but the disposal infrastructure, or capacity, is lacking, or the geology places limits on the injection of oilfield waste water, the commercial SWD operators are able to charge fees in the upper end of the range.A commercial salt water disposal well operator will typically charge between $0.50 and $2.50 per barrel of salt waterAnother consideration associated with disposal of oilfield waste water is the cost of transporting the salt water from the well site to the disposal site. Typically the transportation of waste liquids will cost the operator $1.00 per barrel per hour of transport time. In an area of SWD facility abundance, such as the Barnett shale, transport expense might only add $0.50 per barrel to salt water disposal expenses. However, in areas with few SWD facilities, such as some Pennsylvania locations, oilfield waste fluids have to be trucked to disposal facilities in Ohio or West Virginia, with the cost adding $4.00 to $6.00 per barrel.ConclusionWatch this space for future blog posts addressing the valuation issues faced by companies operating in this space.Mercer Capital has significant experience valuing assets and companies in the oil and gas industry. Because drilling economics vary by region, as touched on above, it is imperative that your valuation specialist understand the local economics impacting your company.  Our oil and gas valuations have been reviewed and relied on by buyers and sellers and Big 4 auditors. These oil and gas related valuations have been used to support valuations for IRS Estate and Gift Tax, GAAP accounting, and litigation purposes. Contact a Mercer Capital professional today to discuss your valuation needs in confidence.Sourceshttp://www.oilandgas360.com/water-handling-in-oilfield-operationshttp://www.tech-flo.net/salt-water-disposal.htmlhttp://www.producedwatersociety.com/produced-water-101http://aqwatec.mines.edu/produced_water/intro/pw/http://www.epa.gov/sites/production/files/documents/21_McCurdy_-_UIC_Disposal_508.pdf
Considerations for Endowments Divesting Fossil Fuels
Considerations for Endowments Divesting Fossil Fuels
Due to the historical popularity of this post, we revisit it this week. Originally published in 2018, the purpose of this post is to educate and advise those who have decided to divest their fossil fuel assets and are unsure of how to proceed.The American Council on Education reported in 2014 that college and university endowments are heavily invested in commodities, natural resources, private equity, and other illiquid assets.  In the 1990s, endowments invested over 95% of their assets in traditional stocks and bonds. By 2013, less than 50% of endowment assets were invested in traditional equities. Currently, endowments have approximately 5% of their assets, $22 billion, invested in energy and natural resources. Over the last few years, many university students and church congregations have urged their trustees to consider divesting their endowments from fossil fuels. The Guardian in January 2018 explained “The divestment movement, primarily consisting of climate activists, is urging private and public institutions to rid their portfolios of all oil, gas, and coal stocks to send a financial and ethical message that fossil fuels are harmful and shouldn't be tolerated. So far, it's estimated that funds totaling $6 trillion have committed to divesting from fossil fuels.” Due to the favorable tax benefits of gifting assets to endowments upon death, your endowment may hold illiquid fossil fuel assets, such as mineral and royalty rights.  You have received an annuity-like stream of payments every month but are now considering divesting.  However, the shortage of a well-organized market for illiquid fossil fuel assets can cause a dilemma for trustees of endowments.  How do you sell your royalty and mineral rights and what are they worth? The purpose of an endowment is to provide a permanent source of funding that maintains the operations of colleges, universities, churches, etc.  To best serve its fiduciaries, an endowment should achieve the highest return possible.  Congruently, when divesting, the endowment must ensure it achieved a fair price for its investments. This post does not weigh in on the discussion of whether endowments should or should not liquidate fossil fuels.  Rather, we hope to educate and advise those who have decided to divest their fossil fuel assets and are unsure of how to proceed.The Growth of Illiquid AssetsThe growth of illiquid assets in endowments investment portfolios is not a surprising trend.   While illiquid assets garner more downside risk, they also offer the potential for higher returns than those realized in the traditional equity marketplace.  A proper fiduciary who weighs the risks and reward of illiquid assets over time will likely like include these assets in their portfolios. However, when it comes time to liquidate these assets, a trustee must act carefully. Selling illiquid assets requires a thorough understanding, and as trustee, it is your fiduciary duty to understand these transactions or seek the advice of someone who does.Divesting publicly traded fossil fuel stocks and bonds is relatively simple.  While it can be beneficial to consider the timing of your sale with movements in the market, generally you can contact your portfolio manager or log onto your trading account directly and liquidate these stocks or ETFs within minutes.Unlike public equity investments, mineral interests and royalty rights investments cannot be liquidated at known market prices instantaneously.  Rather, the price and the terms of the deal must be agreed to by both the buyer and the seller.What Are Your Mineral and Royalty Rights Worth?One of the most common methods used to value mineral and royalty rights is a discounted cash flow analysis.  The holders of royalty rights receive a monthly payment similar to that of a bond holder or commercial real estate lessor.  Thus, future payments can be predicted and then discounted back to the present.  However, the payments to a royalty holder can drastically increase or cease entirely without the say of the royalty holder.  This makes the prediction of future cash flows used to value the asset much more difficult.  Future cash flows must consider the current and future oil price environment, future levels of production, decline curves, the financial strength of current operators, and many other factors.  As we explain in our whitepaper, How to Value an Oil and Gas Royalty Interest, “To perform a royalty’s DCF analysis, production levels must be projected over the well’s useful life. Given that well production decreases at a decreasing rate, these projections can be calculated through deriving a decline rate from historical production. Revenue is a function of both production and price; as such, after developing a legitimate prediction of production volumes, analysts must predict future price.  The stream of income (revenue less taxes and deductions) is then discounted back to present value using a discount rate that accounts for risk in the industry.”The guideline transaction approach can also provide a helpful indication of value. To develop an indication of mineral royalty interest value using the market approach, you can utilize data from market transactions of mineral interests in similar plays. Acquisition data can be utilized to calculate valuation multiples that take into account industry factors (or at least the market participants’ perception of these factors) far more directly than the asset-based approach or income-based approach.  In many ways, this approach goes straight to the heart of value: mineral interests and royalty rights are worth what someone is willing to pay for them.Offer LettersAdding to the uncertainty surrounding the value of royalty rights, the majority of mineral interest and royalty right owners with whom we work receive a couple, if not dozens, of offer letters every year. While offer letters, like transactions, do provide an indication of what someone is willing to pay for the asset, the definition of fair market value includes both a willing buyer and a willing seller.  Since these offers are only half of the equation, they should not be used in isolation as an indication of value.  As shown in the excerpt from the offer letter below, the distinction between fair market value and offer prices is critical in order to protect yourself from brokers attempting to profit at your expense.Offer letters generally offer a multiple of average monthly cash flow on your revenue checks.  These multiples can range widely, often from less than 60x to more than 200x monthly cash flow.  Unfortunately, there is not one benchmark that can be applied to monthly cash flows across the nation, or even within one basin, so there is not an easy way to determine if you are receiving a fair price.Especially after the fall in oil prices in mid-2014, we saw many offers that used scare tactics to try to persuade royalty owners to sell their interests at absurdly low prices.  Since the crash in oil prices, many royalty owners stopped receiving royalty checks; however, this does not mean their royalty interests are worthless.  Even now that oil prices have recovered and production is at an all-time high, some offer letters seek to take advantage of inexperienced royalty owners by suggesting that recent acquisitions, drilling activity, or changes in production have increased the risk, and therefore, decreased the value of their investment.  An understanding of royalty and mineral prices is not common to the average and even advanced investor and information about royalty and mineral rights is scare and difficult to find.  This, unfortunately, means that these scare tactics often work.A recent offer letter to one of our clients read,“As you may know, Hess Corporation has sold their interest in this unit. But there is another risk factor, as well. While it's hard to see on your revenue checks, from 2015 to 2016 the production declined by 10.1%. The decline over the past 30 years has been 1.7%. While the decline has improved this year, it makes one wonder what the decline will be in the future. As a mineral owner in this unit, it certainly has my attention. I'm making this aggressive offer in the belief it will go back to historical declines.”This offer of 90x monthly cash flow was received in August, following the announcement of the acquisition.  By October when the details of the acquisition had been further explained to the investor community, our client had received another offer for approximately 140x monthly cash flow.While there are legitimate online brokers who will buy your royalty interest for a fair price, the best solution is to know and understand the value of your asset before you start searching for a credible buyer.The Value of Mineral Interests and Royalty RightsAs explained in our post "Before Selling Your Oil and Gas Royalty Interest Read This," we believe there are three points you need to understand before selling your mineral interest and royalty rights.Understand what you are sellingRecognize production and price as value driversUnderstand the location’s impact The responsibility of divesting fossil fuels assets, especially for churches, often falls to a volunteer board that is tasked with much more than overseeing the divestiture of their fossil fuel portfolio.  It is the board’s fiduciary duty to ensure that the endowment is operating in the best interest of its beneficiaries which means, they need to ensure they receive a fair price for their assets. At Mercer Capital we have valued mineral and royalty rights in located across the country.  We understand how the location of your assets affects value and work to monitor transactions in each region to understand the state of the current market.   Contact a Mercer Capital professional today to discuss your valuation and transaction advisory needs in confidence.
From Enduro to Permianville
From Enduro to Permianville

A Closer Look at Permianville Royalty Trust

In previous posts, we have discussed the relationship between public royalty trusts and their market pricing implications to royalty owners. Many publicly traded trusts are restricted from acquiring other interests, so they have relatively fixed resources, and the value of these trusts comes from generally declining distributions. In many cases, the royalty comes from a related operator, though this is neither required nor characteristic of all trusts. There are also other MLPs such as Kimbell Royalty Partners, Viper Energy Partners, Dorchester Minerals, and Black Stone Minerals that are aggregators consistently gobbling up new acreage. In this post, we explore the subject characteristics of Permianville Royalty Trust, formerly known as Enduro Royalty Trust.Market ObservationsIt’s been a while since we’ve looked at this group, and Permianville Royalty Trust isn’t the only change. Hugoton Royalty Trust voluntarily delisted from the NYSE last August after not being able to sustain a sufficient stock price. Over the previous two years, the performance of the remaining 20 publicly traded royalty trusts and partnerships has varied widely.  The table below shows the performance and other key metrics of the 20 main oil and gas-focused entities that are publicly traded, as of March 28, 2019. [caption id="attachment_25737" align="alignnone" width="940"]Source: Capital IQ [/caption] Returns are pretty evenly split, with 9 positive and 11 negative. With oil prices rising 23% in the past two years and natural gas declining 8%, it’s not too difficult to pick out which trusts receive royalties from which commodity, though other factors such as timing and operator certainly play a role.For comparison, the chart below shows the two-year returns from Permianville Royalty Trust (PVL), crude oil, natural gas, the O&G150 Index, and a publicly traded E&P ETF called “SPDR S&P Oil & Gas Explore & Prod. (XOP)”. Interestingly, PVL has had little correlation with either crude (+25.9%) or natural gas (-37.0%) prices over the past two years, likely due to its exposure to both commodities and other notable activity specific to the Trust as discussed later.[caption id="attachment_25764" align="alignnone" width="940"]Source: Capital IQ [/caption] Permianville Royalty Trust Origination and SaleEnduro Royalty Trust was formed in May 2011 to acquire and hold a net profits interest (NPI) representing the right to receive 80% of the net proceeds from interests in certain oil and natural gas producing properties located in Texas, Louisiana, and New Mexico. These underlying properties were held by Enduro Resource Partners and are in both conventional and unconventional plays.  The initial IPO occurred in November 2011 issuing 13.2 million units at $22.  A second offering occurred in October 2013 issuing 11.2 million additional units at a reduced price of $13.85.  No further offerings or redemptions have occurred, leaving the number of Trust Units outstanding at 33 million, including the 8.6 million units originally retained by Enduro.Seeking to rebrand from its former operator, the Trust opted to capitalize on the hype on opposite ends of Texas to reflect its holdings in the Permian and Haynesville Shale.On May 15, 2018, Enduro Resource Partners buckled under its debt load and filed for Chapter 11 bankruptcy.  This significantly impacted the royalty trust, similarly to how SandRidge’s issues have plagued its royalty trusts. Three days later, the Trust declared a dividend of $1.13 million, down 42.5% from the prior month, further exacerbating the decline.  The Trust’s share price declined 12.8% from May 10th to May 17th and fell to almost $3 per share a month after the announcement when it was trading closer to $4. On August 31, Enduro finalized a sale of the underlying properties and its outstanding Trust Units to COERT Holdings 1 LLC. This helped stabilize the stock price of the royalty trust as it increased from $3.4 on August 30th to $3.7 by September 6th. According to footnotes of an SEC filing, COERT Holdings paid an aggregate gross consideration of $35.75 million for the 8.6 million Trust Units held by Enduro.  This implies a unit price of about $4.16, significantly higher than the price seen around this time.In connection with the sale, COERT assumed all of Enduro’s obligations (became the “Sponsor” of the Trust) with minimal disruption to unitholders anticipated. Notably, the portfolio consisted primarily of non-operated interests, easing any transition concerns. Seeking to rebrand from its former operator, the Trust opted to capitalize on the hype on opposite ends of Texas, changing its name to Permianville Royalty Trust to reflect its holdings in the Permian and Haynesville Shale. It should be noted, however, that not all of its holdings in East Texas are in the Haynesville.Permian + Haynesville = PermianvilleUnderlying PropertiesThe Permian has dominated shale production in the U.S. over the past year, but Haynesville Shale has made a push of its own recently. It surpassed the Bakken with 58 rigs in the first week of March, which it has only done for a brief period at the beginning of 2018 and before then in 2011 when it also had more rigs than Appalachia and the Eagle Ford. According to the EIA March Drilling Productivity Report, Haynesville only trailed Appalachia in new-well gas production per rig while legacy gas production has declined slower than both Appalachia and the nearby Eagle Ford. Despite these gains, the Permian still dominates in terms of production and the majority of Permianville Royalty Trust’s acreage is in the Permian basin with 88% of net acreage and 92% of net wells.[caption id="attachment_25756" align="aligncenter" width="500"]Source: Permianville Royalty Trust 10-K[/caption] As seen in the chart below, the majority of the Trust’s proved reserves are developed, oil reserves at 59%.  Natural gas makes up approximately 38% of reserves, split between producing and undeveloped. This makes sense as the Permian is the main focus of the Trust, with Haynesville adding a bit of upside in terms of reserves with potential that have yet to begin producing. [caption id="attachment_25757" align="aligncenter" width="500"]Source: Permianville Royalty Trust 10-K[/caption] Operators and CustomersAs noted earlier, Permianville Royalty Trust is operated predominantly by operators other than COERT.  Only 17 of 3,748 gross wells (0.5%) are operated by the Sponsor, and these wells are in the East Texas/North Louisiana region. Other operators include Aethon Energy Operating, BHP Billiton, EXCO Resources, and Indigo Resources. The primary operators in the Permian Basin are Apache Corporation, XTO Energy, and Occidental Petroleum.  Most drilling activity for the underlying properties in 2018 was focused on the Permian Basin with six gross (0.5 net) wells drilled in 2018. In 2017, roles were reversed as six gross (0.5 net) wells were drilled in the Haynesville Shale. While capex budgets are determined by each individual operator and subject to change (as we saw many operators do in 2018) the Sponsor anticipates capex for 2019 to range between $5 million to $7 million prior to consideration of the 80% NPI.The top purchasers of the oil and gas produced from the underlying properties are displayed in the chart below. The realized prices are also included. Notably, the realized price on natural gas increased in 2018 despite declines on the NYMEX, likely because most of the gas harvested is near the Henry Hub.[caption id="attachment_25758" align="aligncenter" width="500"]Source: Permianville Royalty Trust 10-K*Applicable NPI Period per 10-K[/caption] Termination of the TrustA traditional royalty interest typically continues into perpetuity. In contrast, many public royalty trusts have a set termination based on a specific date and/or production level. Permianville Royalty Trust differentiates itself as it is not subject to any pre-set termination provision such as time or production.  The Trust will dissolve upon the earliest of the following:The Trust sells the NPI (subject to approval from at least 75% of unitholders);The annual cash proceeds received by the Trust attributable to the NPI are less than $2 million for two consecutive years;75% of unitholders vote in favor of dissolution; orThe Trust is judicially dissolved. Upon dissolution, the trustee would then sell all of the Trust’s assets and distribute the net proceeds of the sale to the trust unitholders. Net profits allocable to NPI have been $15.2 million, $7.5 million, and $9.3 million in the past three years, mitigating concern the Trust would be dissolved in the near-term.Disposal of Interests Related to Permianville Royalty TrustNPI received by unitholders exclude the sale of underlying properties, but this does not prevent the sale of assets; however, unitholders will be compensated if a sale occurs.  Without a vote of approval, the Trust is only able to release the net profits interest associated with a lease that accounts for up to 0.25% of total production for the past 12 months without consent of unitholders.  The sale also cannot exceed a fair market value of $500,000, and both limits are common features of royalty trusts. COERT sold a couple of producing wells and corresponding acreage in Glasscock County for approximately $62 thousand in January 2019.With the large capital outlays required, companies must be conscious of their cost of capital, frequently increasing debt to fund new projects.To make a larger sale, approval originally required consent from 75% of unitholders. However, at a special meeting in August 2017, unitholders approved amendments to the Trust Agreement decreasing this figure to a simple 50% majority. The next month, the Trust under Enduro’s stewardship divested $49.1 million worth of its underlying properties. Net of transaction expenses, the 80% NPI, and an indemnity holdback, the Trust distributed nearly $38 million to unitholders, a special dividend amounting to about $1.15 per share. By comparison, the Trust has only distributed about 90 cents per share in regular monthly dividends over the past three years. As expected, shares of the Trust spiked upon announcement of the special dividend, then decreased by approximately the amount of the dividend once paid a month later.Divestitures are much more common in the oil and gas industry than the general market as companies seek to develop expertise in core regions. With the large capital outlays required, companies must be conscious of their cost of capital, frequently increasing debt to fund new projects. The need to service this debt sometimes causes E&P companies to divest certain holdings. This is why industry participants frequently refer to transactions as A&D (acquisitions and divestitures) as opposed to M&A (mergers and acquisitions) in other industries.Such disposals, like the divestiture made by Permianville Royalty Trust, can have either positive or negative impacts on unit/shareholders. Ultimately, it depends on the sale price achieved. For royalty trusts, large divestitures lead to special dividends that represent an expedited yield. This could be a positive as such investments are typically seeking a return of their capital with declining distributions. According to the principles of time value of money, it is better to receive cash sooner rather than later. However, such divestitures could lead to different tax treatment and alter the expected return profile for investors. Also, if prices or production turn out to be higher than expected, the upfront sale can have a negative impact in the long-run. This is particularly interesting for Permianville Royalty Trust as it does not have a defined termination date.ConclusionThe performance of Permianville Royalty Trust has varied over the past two years, as it divested assets, changed its name and sponsor, and experienced commodity price volatility. Those who initially sold their units after Enduro filed for bankruptcy may wish they had held on longer. This is certainly true for people who couldn’t wait for oil prices to rebound following the crash in 2014 and likely anyone who sold prior to the announcement of the special dividend in 2017. After the Q4 dip in prices, the Trust also announced its largest monthly dividend since July 2014 concurrent with its 2018 10-K filing, boosting share price further.[caption id="attachment_25763" align="alignnone" width="940"]Source: Capital IQ [/caption] When investing in a public royalty trust or using it as a pricing benchmark for private royalty interests, there are many items to consider that are unique to each royalty trust.  The source of income, region, operator, sponsor, termination (or lack thereof), and other key aspects make each trust unique. We have assisted many clients with various valuation and cash flow questions regarding royalty interests.  Contact Mercer Capital to discuss your needs in confidence and learn more about how we can help you succeed.
EP Second Quarter 2019 Region Focus Permian Basin
E&P Second Quarter 2019

Region Focus: Permian Basin

Region Focus: Permian Basin // WTI crude prices began and ended the second quarter around $60 per barrel, while natural gas prices continued to slide as the calendar turns to summer.
O(i)l Faithful
O(i)l Faithful

Eagle Ford Region Overview

Nearly a quarter of the way through 2019, prices have rebounded somewhat after a tumultuous end to 2018.  First quarter energy prices again moved in opposite directions, with crude prices increasing steadily over the period while natural gas prices decreased from $2.94 to $2.80 per Mcf by mid-March despite peaking at over $3.50 in mid-January.Location, Location, LocationBorrowing the mantra of many real estate agents, sometimes it’s all about location, location, location.  This is quite clear for oil and gas plays, particularly when looking at the acreage multiples paid across various regions. Eagle Ford Shale has quietly delivered solid results, overshadowed by some of the other shale plays, particularly the Permian to the west.  The Eagle Ford’s location provides a distinct advantage, however, as it is closer to higher Brent-related pricing seen on the Gulf Coast. Its higher cut of oil also opens it up to Louisiana Light Sweet pricing. Even though the attention on the Permian has increased both acreage multiples and congestion due to transportation issues, it has been less of a concern in the Eagle Ford because the product has a shorter distance to travel to get to market.While proximity to better pricing is clearly a boon, location within the region also plays a large role.While proximity to better pricing is clearly a boon, location within the region also plays a large role. The Eagle Ford has areas where the cost of supply is as low as $20 to $30 per barrel according to Greg Leveille, Chief Technology Officer of ConocoPhillips. EOG Resources, the largest operator in the region, has noted similar supply costs as well. According to Thomas Tunstall, senior researcher with UTSA’s Institute of Economic Development, “EOG has some of the choicest leases in the Eagle Ford. They have indicated publicly that they can make money at $30 per barrel.” This has a considerable impact particularly with WTI prices currently trading around double that figure.According to Bloomberg, breakeven prices tell a similar story. While the West Eagle Ford has the highest breakeven of these regions, the East Eagle Ford has the lowest. Though it can be difficult to isolate reasons for these differences, Bloomberg’s breakeven prices in the table below do seem to corroborate the assertion that location plays a role as the eastern portion of the Eagle Ford is closest to the Gulf Coast with the Brent and LLS pricing.Free Cash Flow vs Potential — Safe vs SexyAs we noted last week, operators in the Eagle Ford have enjoyed the reliable production inherent in a later life-stage play. Along with the pricing benefits noted above, companies that have operated in the region for a while have been able to benefit from experience.  Todd Abbott, Marathon Oil’s VP of Resource Plays South, attributed the company’s success in the region to drilling innovation and efficiency and repeatability of a stable drilling program.  He further noted, “We are completing wells in a quarter of the time it took us to complete them in 2012.” This notion was furthered by ConocoPhillips’ CTO Leveille who touted innovations in well-spacing and stacking have allowed the company to achieve a 20% field-level recovery factor in the Eagle Ford Shale. Technical innovations and experience have led to free cash flow for operators, which is something investors have been seeking. It also allows for diligence in capital spending, where investors have also begun to prioritize capital efficiency over capital expenditure. In fact, according to Marathon’s Abbott, the Eagle Ford has been able to effectively subsidize its efforts in regions such as the Permian and Oklahoma Stack as it is generating the free cash flow that the others are consuming. Still, the Eagle Ford lacks some of the luster of other plays.Valuation ImplicationsTo further understand the current production profile of the Eagle Ford and oil and gas plays in general, we can compare them to a typical company. In the early stages, companies retain earnings to fund growth opportunities as the return on investment can be quite high. As the company matures, however, there are fewer high return investments to be made, and companies tend to pay more dividends. Returns shift from capital appreciation from retained earnings to a yield in the form of dividends paid as a reward for years of investment. The Eagle Ford is in the stage of paying dividends.As has been the case for some time now, operators in the Permian continue to lead the other regions in terms of EV/production multiples, also known as price per flowing barrel.  The Bakken was about on par with the Permian at the end of 2018, but it slid back towards the Eagle Ford, which edged up over the past three months.  Multiples continue to trail levels seen in the past as enterprise values have been somewhat lower and production figures have increased.Rig Counts and ProductionAccording to calculations based on data from Baker Hughes, rig counts in North America decreased 4.2% in the last three months, but increased 3.6% over the last twelve months. Eagle Ford Shale had the highest annual increase at 15.5%, but its 82 rigs only represent 8.0% of total rigs in North America.  Despite a 4.5% decline in the past three months, the Permian Basin continues to lead the way with 464 rigs, representing about 45% of the total.  By comparison, the Eagle Ford has the second most rigs, just outpacing Appalachia at 79 and the Bakken with 56.Despite the increase in rig counts, production increases over the past year for both oil (14.4%) and gas (8.3%) have trailed production gains seen in other regions.  This is likely due to the older nature of the play, and its stage in the production cycle.  The lack of production growth does not mean there is low production, however.  It continues to provide solid production, with crude oil production on par with the Bakken, and significantly above Appalachia, known for its natural gas.  The Eagle Ford also leads the Bakken in terms of natural gas production. Much of the attention, particularly in Texas, has been on crude as opposed to natural gas.  Despite this, the graph above shows natural gas production in the Permian has increased significantly in the past year.  As noted earlier, the Eagle Ford’s location, specifically its proximity to the Henry Hub in Louisiana, may be a reason why the chasm between the amounts of natural gas produced in the two regions hasn’t increased further than it has. Much like crude, operators focused on natural gas in the Eagle Ford have benefitted from higher pricing as well as lower costs. According to Michael J. Wieland, President and CEO of Laredo Energy VI LP, the economics of dry gas in the Eagle Ford are particularly strong. Wieland further estimated finding and development costs at 50 cents per thousand cubic feet (Mcf) and netbacks of about $2/Mcf.  SilverBow Resources’ EVP and CFO, Gleeson Van Riet, said the company has drilled 20 of the top 50 Eagle Ford gas wells and that the play is the best place to be in the U.S. for natural gas because it has best prices, good infrastructure and is located in the demand growth area. SilverBow (formerly Swift Energy) is the Eagle Ford’s only public pure-play in dry gas. Whether an operator focuses on crude oil, natural gas, or both, neither seems to be in short supply in the region. End of an Era?While there is plenty of current production in addition to cash flow, there are concerns about the longevity of the region. Even regional giant EOG is looking to diversify. On a recent earnings call, EVP of Exploration & Production Ezra Yacob noted expanding exploration in those areas will “help increase the quality of our inventory” and “should hopefully shallow the decline that these unconventional plays are kind of known for.” The company still plans to drill about the same number of wells in the region in 2019, after posting a 9% crude oil production increase. The Eagle Ford represented 43% of EOG’s crude production last year, so diversifying to other regions doesn’t necessarily indicate a bearish view. Instead, it seems to be in line with the strategy alluded by Marathon, using the cash flow generated in the Eagle Ford to pay for growth in other plays.Despite the older nature of the play, many people around the industry believe there is plenty of value still under the subsurface in south Texas.Despite the older nature of the play, many people around the industry believe there is plenty of value still under the subsurface in south Texas. Director at BMO Capital Markets Max van Adrichem called the Eagle Ford a good alternative to “some of the more mature basins which may not have enough running room to get you through 5 to 10 years.”  Martin Thalken, Chairman and CEO of pure-play Eagle Ford operator Protégé Energy III, supports this line of thinking. He commented the Eagle Ford “is still in the early innings” on applications like primary EOR and refracturing. John Thaeler, CEO of Vitruvian Exploration IV also employed a baseball analogy, saying “the dry gas Eagle Ford is just in the second inning.” Marathon’s Abbott agrees, “We believe there is a lot of running room left in the Eagle Ford for Marathon and the rest of the industry.”ConclusionCrude prices have rebounded since the turn of the year, while natural gas prices have remained steady. Pricing will always be dynamic in a global commodity environment, but the economics of certain plays tend to be less fluid.  While it may not offer the potential of the Permian, the Eagle Ford is poised to leverage its experience and location to deliver solid returns.We have assisted many clients with various valuation needs in the upstream oil and gas space in both conventional and unconventional plays in North America, and around the world.  Contact a Mercer Capital professional to discuss your needs in confidence and learn more about how we can help you succeed.
M&A in the Eagle Ford Shale
M&A in the Eagle Ford Shale
Over the last twelve months, the Eagle Ford Shale region has experienced steady growth and healthy transaction activity.According to the Society of Petroleum Engineers, crude production from the south Texas play climbed steadily throughout the year and continued to achieve its highest marks ever. New, upstart independents came back to the region, including one led by the former head of Occidental Petroleum, as investors looked beyond the neighboring Permian Basin with its crowded top-tier acreage and pipelines. And operators began joining forces to increase the scale of their operations, headlined by Chesapeake Energy’s merger with Wildhorse Resource Development.The region’s strengths, such as its low cycle times, high oil cuts and Louisiana Light Sweet crude and Brent oil pricing, has facilitated free cash flow and made the area attractive to both investors and operators.As long as entry costs and well costs remain reasonable, the Eagle Ford Shale has strong potential for continued economic growth.Recent Transactions in the Eagle Ford RegionDetails of recent transactions in the Eagle Ford Shale, including some comparative valuation metrics are shown below.Chesapeake Closes Acquisition of WildHorse for Nearly $4 BillionChesapeake has made several major transactions over the last nine months. In the middle of 2018, the company sold its entire stake in the Utica Shale, and experts speculated that the company would put the sales proceeds towards an acquisition in the Eagle Ford or Powder Basin area.Following the deal, Chesapeake is now the top acreage holder in the Eagle Ford with approximately 655,000 nets acres, pro forma.Chesapeake closed a deal with Houston-based WildHorse Resource Development with a transaction value of $3.977 billion. The consideration for the transaction consisted of either 5.989 shares of Chesapeake common stock or a combination of 5.336 shares of Chesapeake common stock and $3 cash, in exchange for each share of WildHorse common stock. Chesapeake intended to finance the cash portion of the WildHorse acquisition, which was expected to be between $275 million and $400 million, through its revolving credit facility.In a statement, Chesapeake’s CEO, Doug Lawler said: “In 2018, Chesapeake Energy continued to build upon our track record of consistent business delivery and transformational progress through both financial and operating improvements. The addition of the WildHorse assets to our high-quality, diverse portfolio, combined with our operating expertise and experience, provides another oil growth engine with significant oil inventory for years to come and gives us tremendous flexibility and optionality to help achieve our strategic goals.”Following the deal, Chesapeake is now the top acreage holder in the Eagle Ford with approximately 655,000 nets acres, pro forma.Trends and OutlookInvestor Returns and Free Cash FlowOne of the most attractive features of the Eagle Ford region for the last year has been the returns. The Eagle Ford generates solid economics and cash flow, which operators use to fund exploration projects both nearby and elsewhere. Portions of the Eagle Ford generate some of the best economics in shale, and the region is forecasted to generate stable production into the 2020s.Coupled with the fact that the Eagle Ford is one of the lowest costing basins in the U.S., reliable production and capital efficiency in a mid-life stage play has been translating to free cash flow, something investors have been vocal about trying to obtain from the oil and gas industry as a whole for quite some time.Portions of the Eagle Ford generate some of the best economics in shale, and the region is forecasted to generate stable production into the 2020s.Todd Abbott, VP of Resource Plays South for Marathon Oil Corp., recently said at the DUG Eagle Ford conference in San Antonio that Marathon is seeing “fantastic” returns with reliable production, capital efficiency, and free cash flow.At the same conference, Stephen Chazen, chairman, president and CEO of Magnolia Oil & Gas, noted “General investors want reasonable growth, earnings per share, and free cash flow.” The recently formed small independent company generated free cash flow in excess of capital on acquisition spending and ended 2018 with $136 million of cash on the balance sheet, an increase of approximately $100 million compared to the end of the third quarter.These kinds of results show that the region has been a cash flow generator for the year and has been a main driver for most of the recent and anticipated transaction activity, especially companies under $1 billion in market capitalization.Anticipated Large Operator Divestitures in 2019In recent reports from Shale Experts, several larger operators in the Eagle Ford area are potential candidates for divestiture. Following Q4 2018 earnings calls, five operators have indicated that they are open to selling all or parts of their Eagle Ford assets in 2019. Collectively, the net acreage under consideration totals to over 100,000 net acres. Below are four of the company responses to Shale Experts’ questions regarding where Eagle Ford assets fit into their portfolios:Encana Corp. - After purchasing Newfield, Encana now considers the Eagle Ford as non-core.Pioneer Natural Resources - They have been actively selling pieces of their Eagle Ford asset since 2018.Matador Resources - Matador will outspend cash flow this year, and therefore an Eagle Ford asset sale might help plug that gap.Earthstone Energy - Earthstone is trying to convert itself into a Permian-only player. Reports from Shale Experts expect they will be looking to offload their Eagle Ford assets in the near-term. In addition to the reports above, Norway’s Equinor announced plans to explore the sale of its Eagle Ford assets as well. Equinor has an ownership interest in the Eagle Ford Shale formation located in south Texas through a joint venture with Repsol. Through transactions in 2013 and 2015, Equinor obtained full operatorship in the joint venture and increased its working interest to 63%. The company’s net acreage position in Eagle Ford at the end of 2018 was approximately 71,000 net acres and production of 43,000 boe/d. In a recent interview, Al Cook, the company’s head of strategy, said that Equinor is looking to add to its large position in Appalachia in an attempt to chase natural gas-rich acreage. This move is consistent with trends we identified last quarter in our transaction analysis of the Marcellus-Utica region. Any divestiture of assets by these operators would pose an interesting opportunity, especially for aforementioned smaller operators to acquire acreage and capitalize on the cash flow generating ability of the region to facilitate growth and increase returns. We have assisted many clients with various valuation needs in the upstream oil and gas industry in North America and around the world.  In addition to our corporate valuation services, Mercer Capital provides investment banking and transaction advisory services to a broad range of public and private companies and financial institutions.  We have relevant experience working with companies in the oil and gas space and can leverage our historical valuation and investment banking experience to help you navigate a critical transaction, providing timely, accurate and reliable results.  Contact a Mercer Capital professional to discuss your needs in confidence.
How to Value Your E&P Company
How to Value Your E&P Company
Our whitepaper "How to Value Your Exploration and Production Company" provides an informative overview of the valuation of exploration and production (E&P) companies. Because of the historical popularity of this post, we revisit it this week.There are numerous scenarios under which some form of an ownership transition occurs, and in all scenarios, a business owner must invariably address the question of value.  A lack of knowledge regarding the value of a business can be very costly. Opportunities for successful liquidity may be missed or estate planning could be incorrectly implemented based on misunderstandings about value. In addition, understanding how exploration and production companies are valued may help to understand how to grow the value of a business and maximize returns when it comes time to sell.Download the full whitepaper or read a brief summary below.WHITEPAPERHow to Value Your Exploration and Production CompanyDownload WhitepaperImportant Industry FactorsA review of the oil and gas industry is important in establishing a credible value for any business operating in this space. Such a review should consider a wide range of issues (far too many to list in full here), with primary considerations as outlined below.Price Volatility. The oil and gas industry is characterized by high price volatility. The size and global nature of the oil and gas market means that these prices are influenced by countless economic – and sometimes political – factors affecting individual producers, consumers, and other entities that comprise the global market.Technology. Technology in the oil and gas industry changes rapidly and has the potential to materially impact the market. Adoption of innovative drilling techniques, such as horizontal drilling and hydraulic fracturing, has made oil and gas production quicker, easier, and relatively cheaper.Regulation. The oil and gas industry is heavily regulated by various entities, and regulations on operations can have a costly impact on the industry. The regulatory environment is constantly changing and regulations vary across regions and countries.Variation by Oil and Gas Play. Drilling economics vary by region. There are geological differences between oilfields and reserves that make it harder (thus more costly) to drill in some places than others. Accordingly, the value of any E&P company is strongly influenced by its location, and it is important to consider geological differences when valuing E&P companies.Financial ConsiderationsWhen valuing a business, it is critical to understand the subject company’s financial condition.  E&P companies rely on their oil and gas reserves to produce revenue. Understanding the drilling economics is crucial in understanding a company’s value.A break-even analysis is a helpful tool used to analyze drilling economics.  A break-even analysis can be used to compare how much it costs to produce one barrel of oil versus the revenue generated per barrel.  This can reveal whether a company is losing money through the production process and determine at what price a company can be profitable.An analysis of a company’s working capital, leverage, and interest coverage ratio can help paint a better picture of a company’s financial position.To properly consider a company’s current financial position, it is important to understand management’s plan for future development of wells. Since oil is a depleting asset, in order to continue at current levels of production, oil companies must continuously explore for reserves and develop new wells. Thus, when valuing an E&P company in today’s market, it is important to consider the company’s ability to meet its capital needs.   An analysis of a company’s working capital, leverage, and interest coverage ratio can help paint a better picture of a company’s financial position.E&P companies have extremely high operating costs, in large part due to the magnitude of exploration expenses. Exploration endeavors, although not always successful, are extremely costly. For this reason, many in the oil and gas industry prefer to look at EBITDAX multiples rather than EBITDA multiples. EBITDAX represents EBITDA before exploration expenses and tends to be a better metric to compare E&P companies because it negates the effect of a company’s selected accounting policy.What Does the Valuation Process Entail?There are three commonly accepted approaches to value: asset-based, market, and income. In the realm of business valuation, each approach incorporates procedures that may enhance awareness about specific economic attributes that may be relevant to determining the final value.Mineral reserves are an E&P company’s main generator of value, but because they are depleting assets and are often owned through working interests, their value can be tricky to understand. Reserves are typically divided into two groups: proved and unproved reserves. Proved reserves are further classified as proved developed producing reserves (PDP), proved developed non-producing reserves (PDNP), and proved undeveloped reserves (PUDs); unproved reserves are further classified as probable and possible. The valuation methodology used depends on the type of reserve. Generally, the income approach is the most supportable approach for valuing proved reserves and the market approach is generally used to value PUDs and unproved reserves.The Income ApproachThe income approach can be applied in several different ways. For companies operating in the oil and gas industry a discounted cash flow analysis is most common because reserves produce unequal annual cash flows that can be projected by a petroleum engineer in a reserve report. This approach allows for the consideration of characteristics specific to the subject company and their reserves.These future production estimates from reserve reports can be used to project revenue throughout the remaining life of a well.  Estimates of future cash flow can be discounted back to the present using an appropriate discount rate (rather than the 10% industry standard used to calculate PV-10).While the income approach is typically a reliable estimate of value for proved reserves, it is not always helpful in determining the value of PUDs and unproved reserves because the production of unproved reserves is ambiguous.  Rather, we generally use the market approach.The Market ApproachThe market approach utilizes pricing multiples from guideline transaction data or valuation multiples from a group of publicly traded companies to develop an indication of a subject company’s value. In many ways, this approach goes straight to the heart of value: a company is worth what someone is willing to pay for it.In many ways, the market approach goes straight to the heart of value: a company is worth what someone is willing to pay for it.While geography may not factor into the selection of guideline public companies in many industries, the location of an E&P company is one of the most important factors to consider when selecting similar companies in the oil and gas industry.  Drilling economics vary across play; thus, it would be inaccurate to select a company operating in the Permian Basin as a comparable company to one operating in the Bakken Shale in North Dakota.Acquisition data from industry acquisitions can be utilized as a multiple on the subject company’s performance measure(s). For unproved reserves in particular, because production is uncertain, the market approach provides the most meaningful indication of value. Using an EV/acreage multiple derived from transactions of similar companies, analysts can gauge the value of a company’s unproved reserves.Synthesis of Valuation ApproachesA proper valuation will factor, to varying degrees, the indications of value developed utilizing the three approaches outlined. A valuation, however, is much more than the calculations that result in the final answer. It is the underlying analysis of a business and its unique characteristics that provide relevance and credibility to these calculations. This is why industry “rules-of-thumb” are dangerous to rely on in any meaningful transaction. Such “rules-of-thumb” fail to consider the specific characteristics of the business and, as such, often fail to deliver insightful indications of value.Mercer Capital has long promoted the concept of managing your business as if it were going to market. In this fashion, you promote the efficiencies, goals, and disciplines that will maximize your value. Despite attempts to homogenize value through the use of simplistic rules of thumb, our experience is that each valuation is truly unique given the purpose for the valuation and the circumstances of the business.Mercer Capital has experience valuing businesses in the oil and gas industry.  We encourage you to extend your business planning dialogue to include valuation.  For more information or to discuss a valuation or transaction issue in confidence, do not hesitate to contact us.
Four Themes from Q4 2018 Earnings Calls
Four Themes from Q4 2018 Earnings Calls

We Read the Earnings Calls so You Don’t Have to

Commodity prices exhibited significant volatility to end 2018 with steep declines in crude prices and a spike in natural gas prices that subsequently fell back.  The general market also declined over the period, making it difficult to parse reasons for various stock price gyrations.  While lower prices aren’t ideal for industry operators, earnings calls remind wary investors that there’s more to price than what trades on the NYMEX. Executives this quarter also note a shift in focus when it comes to capital outlays.We take a look at some of the earnings commentary of large players in the oil and gas space to gain further insight into the challenges and opportunities developing in the industry.Theme 1:  Hedging Protects Operators from Lower Crude Prices Our 2019 crude oil hedge positions remain unchanged. We have 95,000 barrels of oil per day hedged for calendar 2019 with $60 WTI put option contracts. We expect option premium amortization will be approximately $29 million per quarter in 2019. –John Rielly, CFO, Hess CorporationIt is notable that we remain the only publicly traded U.S. producer that is 100% hedged on expected natural gas production in 2019. –Glen Warren, President and CFO, Antero Resources CorporationIn order for operators to mitigate risk and volatility in commodities such as crude oil and natural gas, many companies will engage in hedging, mostly by use of derivative instruments. This ability to effectively pay a fixed price over future periods of time, commonly in the form of commodity futures and various option contracts, allows for more certainty and stability in cash flows particularly when prices exhibit volatility. This is particularly important for an industry that requires significant capital outlays and long term budgeting plans. While hedging is certainly beneficial when markets behave as they did in Q4, it is important to realize these contracts come at a cost as noted in the Hess quotation above. In response to analyst questions, Hess Corp’s CEO noted future hedging would be of a similar structure where they “protect the downside but we don’t cap the upside.”Hedging protects E&P companies from adverse price realization, effectively propping up operations when commodity prices fall.  These instruments tend to smooth results, so revenue does not drop too severely in bad times, though its costs do lower profits in times of rising prices.  When valuing E&P companies, the increased cost would be a calculated reduction in value; however, hedging lowers volatility and risk. If companies sought to save this cost and expose themselves to commodity risk, it could be subject to a higher discount rate to account for these risks. Ultimately, hedging is a form of insurance and is a cost of doing business.Theme 2:  Local Pricing and Transportation Issues Also Obscure Prices Achieved by Operators2018 was a volatile year for oil prices, especially in the Permian. As you can see on Slide 4, we successfully navigated a challenging midstream takeaway situation throughout the year and delivered a realized oil price that comfortably outpaced both, our peers and local Midland prices. Even more importantly, our proactive marketing strategy delivered ample flow assurance without burdening our long-term pricing structure. So we would expect to stay near the top of the class on this measure in coming years. –Matt Gallagher, President and CEO, Parsley Energy, Inc. [caption id="attachment_25161" align="aligncenter" width="459"]Source: Parsley Energy Earnings Presentation, Slide 4[/caption] Our strategy is to have multiple export markets here to provide us flexibility to move our oil into the highest value market. So, we can get about 70% of our oil to the coast to get the Brent influenced pricing. –John Rielly, CFO, Hess CorporationThe ability to sell this oil at Brent-related pricing has had a very positive impact on both margins and returns in 2018. For instance during the fourth quarter, we moved about 90% of our oil to the Gulf Coast which had the effect of increasing our oil margins by over $9 per barrel. –Rich Dealy, Executive Vice President & CFO, Pioneer Natural Resources Company [caption id="attachment_25167" align="aligncenter" width="527"]Source: Bloomberg[/caption] A recurring theme throughout 2018 was the pricing differentials between localized prices and those seen on different exchanges such as the standardized Cushing, Oklahoma. The Brent-WTI spread was also pronounced throughout the year, with an average spread of $6.79 per barrel, peaking at $11.37 in June. Capacity constraints from a lack of infrastructure in place to bring the product to market played a role in this, and operators in all regions dealt with localized pricing differentials. As we see from these quotes, many operators are seeking markets where they can achieve higher pricing, particularly those related to Brent in the Gulf Coast.Higher prices received for a given level of production increases profit for E&P companies, but transporting the product to these markets incurs increased costs too. Ultimately, companies must balance the increased revenue with the incrementally increased costs to make sure returns are realized from this strategy.Theme 3:  Lower Prices Reign in CapEx BudgetsLast month we discussed various capital budgets through three different pricing scenarios, but we've decided to limit our full capital spend in 2019 to $4.5 billion. This represents a $500 million or a full 10% reduction from 2018. By maximizing efficiencies, we are reducing spending to adjust to a lower oil price environment. –Vicki Hollub, President and CEO, Occidental Petroleum CorporationIf we get extended in an extended low-price environment and really would have to go really more into 2020, the tail-end of 2019 into 2020, in that  case an extended low-price environment we have the flexibility as we mentioned to reduce our annual CapEx by as much as $1 billion and that’s principally by reducing rigs in the Bakken. –John Hess, CEO, Hess CorporationIn an effort to align spending with cash flow projections both Appalachia and Permian producers are reducing 2019 capital budgets, which results in lower supply growth in 2019 with an even more meaningful supply impact in 2020. –Glen Warren, President and CFO, Antero Resources CorporationAntero will remain flexible depending on the commodity price outlook. We will remain disciplined, spending within cash flow in a low case but have the ability to prudently grow production to maximize free cash flow if commodity prices improve ultimately delivering an appropriate mix of return of capital to shareholders and further deleveraging. –Paul Rady, Chairman & CEO, Antero Resources CorporationMany CapEx budgets for 2019 and beyond were revised downward after the steep drop in oil price as it makes less sense for operators to ramp up production under these conditions. As is noted above, CapEx budgets will remain flexible as an increase in prices would induce operators to produce more in the short-term.Higher CapEx spending in the near term increases revenue for E&P companies, though this will ultimately decrease overall return if the operator does not scale back production until prices rise again.Theme 4: Market Not Paying for Growth Without ReturnCapital discipline has been the buzzword in the E&P industry throughout most of 2018, and certainly as we enter 2019. At Marathon, we have a very clear working definition of capital discipline […] It means prioritizing sustainable free cash flow generation at conservative prices over growth for growth sake. We've been very clear that production growth is simply an outcome of our disciplined capital allocation process, and given our commitment to returns and cash flow, we emphasize high-value oil growth to drive both high margins and capital efficiency. And with sustainable free cash flow, capital discipline for us is also a commitment to return capital back to shareholders, through both our peer competitive dividend and thoughtful share repurchases. –Lee Tillman, Chairman, President, and CEO, Marathon Oil CorporationThe steps we took in 2018 will be really important when it comes to 2019 in the sense that we in our 2019 plan can point to a significant CapEx decrease about 11% compared to 2018, while at the same time delivering a strong 15% increase in production. So, we're very excited about what 2019 holds when we can show that kind of capital efficiency gains. –Tim Dove, President & CEO, Pioneer Natural ResourcesWell, I think, first of all, we are slowing down growth, if you look at this year compared to the prior two years, we've been well into the 20s in terms of growth percentages. We have moved this down. We have a range now which centers on 15%. Obviously, we can ratchet within that range at a moment's notice. It's based on how much activity we want to execute on. But fundamentally, we've taken significant steps to increase basically return of capital to shareholders and we wouldn't have a $2 billion share repurchase plan if that wasn't the case. But I think we have to go further. –Tim Dove, President & CEO, Pioneer Natural ResourcesParsley expects to see an 8% to 10% plus year-over-year improvement on capital efficiency during 2019. We expect both productivity gains and CapEx savings to drive this improvement as detailed down the right hand side of the slide. –Matt Gallagher, President and CEO, Parsley Energy, Inc. [caption id="attachment_25160" align="aligncenter" width="519"]Source: Parsley Energy Earnings Presentation[/caption] As a consequence to reductions in capital budgets, companies are emphasizing capital efficiency over capital expenditures. The market has indicated that a perpetual cycle of growth not sharing the returns with investors is becoming less appealing. Doug Leggate, a Merrill Lynch analyst and frequent participant on industry earnings call Q&A sessions, posed this question directly to Pioneer, specifically noting the share price had not increased since March 2016 despite production doubling in that time frame. The CEO’s response is our third quotation above. Companies will need to strike a balance between funding their growth operations, paying down debt, and returning capital to investors in the form of dividends and share repurchases.Capital efficiency, that does not negatively impact long-term growth prospects, would increase the value of E&P companies as it focuses on increasing returns. In the typical Gordon Growth model for determining intrinsic value of a stock, it gives investors a return in the form of dividends as opposed to capital appreciation, which is only rewarded if the market is willing to pay for it.
David Smith Joins Mercer Capital and Opens Houston Office
David Smith Joins Mercer Capital and Opens Houston Office
Mercer Capital is pleased to announce that David Smith, ASA, CFA has joined the firm and leads the firm’s Houston office.Smith, formerly the leader of the Houston valuation practice of HSSK, has over 20 years of business valuation experience. He values businesses, business interests, and intangible assets for financial reporting, corporate tax, corporate M&A, employee stock ownership plans, and gift and estate tax purposes.David joins the firm's Oil and Gas industry team. Throughout his career, he has worked extensively with clients in the oil and gas industry. He has performed numerous valuations in the oil and gas exploration, oil and gas field services, oil and gas equipment, and gathering system and pipeline industries.David holds the Accredited Senior Appraiser designation from the American Society of Appraisers and the Chartered Financial Analyst designation from The CFA Institute.“We are very pleased to have David join us. He brings a depth of experience and expertise to the firm,” commented Matt Crow, Mercer Capital’s president. “David has a stellar reputation in the Houston market and will build a strong team for the firm in Houston. We are committed to the Texas market and David’s addition allows us to continue to serve that market with the highest quality valuation and consulting services.”Bryce Erickson, Mercer Capital's Oil and Gas industry team and Dallas office leader, remarked, "Given David's experience, his addition greatly strengthens our ability to serve our oil and gas clients. We couldn't be happier to have him on board."Smith said, “I was initially interested in Mercer Capital because of their strong reputation. Once I met the people, I knew it was the right decision. Mercer Capital is one of the most respected business valuation and financial advisory firms in the nation. Their work and people are highly regarded. I’m looking forward to building the Houston office and am happy to be part of this great team.”For more information about David, view his CV.
Limited Partners, What Are Your Rights?
Limited Partners, What Are Your Rights?

Legal Rights and Valuation Considerations For Your Limited Partner Interest

A partnership is a business owned by two or more individuals. In its most basic form, a partnership typically falls into one of three categories: a general partnership, a joint venture, or a limited partnership. While the specifics of these three types can vary depending on the goals of the business, they all share similar features.For the purposes of this post, we will be examining benefits and rights we have come across in performing valuations over various types of partnership structures and their relation to value. And while Mercer Capital has worked with complex legal structures in the scope of our work, we do caveat that we are examining these issues through the lens of informed business professionals. If you have specific matters regarding your investment that require legal advice, you should consult an attorney.How Does a Limited Partnership Work?A limited partnership is a type of partnership that has at least one general partner and one or more limited partners. Under this structure, the partners unite to conduct business and only the general partner is liable beyond the extent of the amount of money invested. Each limited partnership has a general partner who is responsible for the day-to-day management of the business. While a general partner is typically an individual, it is not uncommon for separate entities, such as a management company, to fill this position. This type of general partner structure is seen commonly in private equity and hedge funds.  The general partner has complete control of operations, and they assume the debts and liabilities of the partnership. Since the general partner is in charge of the successful operation of the business, they are typically compensated in the form of management fees, performance fees, or both depending on the structure and purpose of the entity.Because limited partners do not participate in the day-to-day operations, their financial liability is limited to the amount of invested money into the partnership.In addition to a general partner, the limited partnership also has to have at least one limited partner. Sometimes referred to as “silent partners,” limited partners do not have to do anything except invest in the business and receive a share of the profits. Because limited partners do not participate in the day-to-day operations, their financial liability is limited to the amount of invested money into the partnership, similar to owners (members) in a limited liability company (LLC). In order to maintain this “limited” status, though, limited partners may not contribute more than 500 hours of work towards the limited partnership or else they may be considered a general partner.The tradeoff to this financial limit of liability is that limited partners have no say in management or business decisions. They are also only compensated in the form of dividends or capital appreciation pro rata or as otherwise agreed upon in the partnership agreement. More to the point, they do not have the ability to request dividends or sell/partition the underlying assets directly. We will show further below how this lack of ability directly impacts value of a limited partner’s interest.However, this does not mean that limited partners do not have other rights and entitlements to ensure that their investment is appropriately utilized. First, we will look at activities in which limited partners may participate and still retain limited liability.Safe HarborsAs mentioned, limited partners are not only limited by the amount of their investment but also in their involvement in business operations. However, there are some activities in which a limited partner can engage which will not impact their level of liability, these are known as, “safe harbors.” These activities may include the following:Serving as an agent, contractor or employee of the companyServing as a board member, officer, director or shareholder of the company, provided they do not own a majority shareProviding consultation to the general partner(s) of the companyRequesting or attending a meeting of partnersActing as a surety for the partnership to guarantee or assume its specific obligationsVoting on changes that may affect the nature of the limited partner relationship Many limited partners do not realize they have these safe harbor activities allowing them to exercise a level of power while protecting their liability and maintaining limited status. Best practice, of course, would be to consult your partnership agreement or attorney to ensure that no conflicts arise.Rights as a Limited PartnerAlthough not a requirement, the vast majority of partnerships are born through a partnership agreement (sometimes referred to as a limited partnership agreement or “LPA”). This contract is between two or more partners and is used to establish the rules and responsibilities of the parties conducting business, such as capital contributions, withdrawals, profit and loss distribution, and financial reporting.Contained within partnership agreements are specific rights and duties outlined for both limited partners and those acting as the general partner. The rights of limited partners in a limited partnership, LLP, or even an LLC theoretically share similar to those of a shareholder in a corporation.In the absence of specific provisions in a partnership agreement, there are generally rights available to a limited partner in conjunction with the safe harbor activities mentioned above. A summary of rights we have encountered include the following:Voting within safe harbor provisionsInspection of books and recordsAbility to bring derivative actionAssignment of interest without dissolution of partnershipRight to withdraw from partnershipApplication for dissolution of partnership if business purpose cannot be fulfilled Specific rights available to you may vary depending on the facts, circumstances, and structure of your partnership. To fully understand what is available to you, be sure to review your partnership agreement or consult an attorney.Valuation ConsiderationsKnowing your rights as a limited partner is important so that you can stay informed and ensure that your investment is deployed and utilized correctly. Another important item to understand is the valuation considerations of your limited partnership interest.We can differentiate the roles and responsibilities fairly easily as general partners do the work to ensure successful operation and limited partners provide the capital, let the general partners work, and earn a passive return. From a valuation standpoint, it may be harder to conceptualize how much a limited partner interest is worth compared to a general partner, a different limited partner, or even the entire partnership as a whole. We refer to our “Levels of Value” chart to provide a visualization of where a limited partnership interest may fit in terms of a valuation hierarchy. A limited partner that owns a minority interest in a private partnership falls at the bottom of this chart. But how do we get down there from the net asset value? There are likely multiple tiers of discounts applicable to a limited partner interest.  The first is the portion attributable to the general partners. This is made in accordance with their capital contribution, though it is frequently small as the general partner receives payment through management fees. Secondly, because limited partners lack the ability to make the decisions afforded to general partners, they will likely be subject to a minority interest discount. There have been observed ranges of 7-10% for the minority discount, but this amount can be much higher or even lower. It all depends on specific characteristics of the partnership. This brings us to the marketable minority level of value in the above chart. However, limited partner interests aren’t typically marketable, meaning limited partners do not have the ability to freely dispose of their interests like they could sell shares in a publicly traded company for instance. Knowing your rights as a limited partner is important so that you can stay informed and ensure that your investment is deployed and utilized correctly.This brings us to our final discount, the marketability discount. There is a wide range of potential marketability discounts and again, these depend on the characteristics of the partnership in question. At Mercer we have seen marketability discounts range between 20-45%, but similar to the minority interest discount, these discounts can go much lower or even much higher depending on multiple factors regarding the partnership. Frequently, these discounts are considered in tandem with any minority interest discount applied, and the total effective discount must be considered.An example of this tiered discounting is provided below of a limited partnership with a total Net Asset Value of $100,000 and a general partner interest of 1%. In order to illustrate the calculation of value at the non-marketable minority interest level, we have used a minority interest discount rate of 5% and a discount for lack of marketability of 20%. The result of the calculation yields a conclusion of value at $75,240 with an effective discount rate of 24%. This shows how a limited partner whose net asset value share of $95,000 can be discounted to reflect the lack of control over their position and the lack of marketability for a sale or assignment of interest. ConclusionKnowing rights entitled to a limited partner in connection with understanding the relative value of their investment enables limited partners to make informed decisions.Mercer Capital is an employee-owned independent financial advisory firm with significant experience (both nationally and internationally) valuing assets, companies, and partnership interests in the energy industry (primarily oil and gas, biofuels, and other minerals).  Our oil and gas valuations have been reviewed and relied on by buyers and sellers and Big 4 Auditors.As a disinterested party, we can help you understand the fair market value of your limited partnership interest. Contact a Mercer Capital professional today to discuss your limited partnership valuation questions in confidence.
Do The Upstream Sector's Mosaic Of Indicators Create A Clear Picture?
Do The Upstream Sector's Mosaic Of Indicators Create A Clear Picture?
Considering the precipitous drop in oil prices at the end of last year, 2018 finished with somewhat unexpected results in the upstream sector. Take the OGJ 150, one of the industry’s upstream indexes. It was on a roller coaster. It began the year at 1,858 and generally climbed for the first three quarters. It peaked on October 9th with a closing of approximately 2,021. It then took a fall and finished the year at 1,522 about 18% off from the start of the year. However, it has since climbed back up in January and closed last week at 1,646.Questions and opinions abound. Causes, concerns, opportunities and optimism are being bandied about. There are several indicators out there that are sending mixed messages. Pricing, supply, DUC counts, LNG growth, bankruptcy activity, capex budgets and merger and acquisition trends are out there to name a few that interplay with each other. They create a visual of what is happening and what could happen going forward. We’ll look at a few of these to try to get more clarity.Prices (Bearish)As U.S. crude oil prices plunged by 40% in the fourth quarter of 2018, from $75 in the beginning of the quarter to $45 per barrel at the end of December, valuations dropped alongside prices. What were the causes? Reasons started with concerns about potential increasing of U.S. shale output, inconsistency in Russia and OPEC’s execution of their production deal and fears of a global economic slowdown. Even OPEC’s deal with Russia to cut 1.2 million barrels per day during the December 6-7 meeting couldn’t stop oil prices from falling. The sharp decline once again demonstrates that higher prices fostered by supply-side management have a difficult time lasting.On the other hand, natural gas prices benefited from seasonal fluctuations. Prices jumped to over $4.80 per mcf in mid-November due to several factors including an early and colder winter hitting North America. In its December edition of the Short-Term Energy Outlook, the EIA reported the price of Henry Hub averaged $4.15/MMBtu in November, up 27% from October. Higher inventory helped to smooth price volatility in the energy market, but U.S. natural gas inventories began the season at a 15-year low. This will most likely be a temporary issue, as reserves are plentiful and the LNG market will begin to offtake more supply in 2019.[caption id="attachment_24731" align="alignnone" width="640"]Source: Bloomberg[/caption] It is relatively rare to see the inverse relationship between crude oil and natural gas prices. A more than 50% increase in natural gas prices was coupled with nearly 30% downturn in crude oil prices during a seven-week period from early October to mid-November. Long oil short natural gas, once a popular trade by speculators, was punished during this unusual period of time. Natural gas prices ended the year at $2.94 per Mcf, a 2.3% decrease for the fourth quarter and essentially flat for the year. Supply and Demand (Bullish)In 2019, it is expected that the U.S. will continue to lead the growth in oil supply worldwide. Improving pipeline capacity, particularly in West Texas, and the combination of horizontal drilling and hydraulic fracturing continue to drive higher and more efficient production in the U.S. Good news is that a lot of this supply will be at a lower cost to producers because part of the costs has already been sunk. Drilled but uncompleted wells (“DUCs”) which jumped to new records in 2018 will likely be drawn down as a lower cost production alternative. This will contribute to supply growth.According to the December Short-Term Energy Outlook, the EIA expects global liquid fuels consumption to increase by 1.5 million barrels per day in 2019.  Growth is largely coming from China, the U.S. and India. U.S.-China trade tensions remain high entering 2019 and have shaken up most if not all industries, and oil and gas is not an exception. China is the second largest in terms of oil consumption and surpassed the U.S. as the world’s largest crude oil importer in 2017. Slower growth in China is looming for the demand side of crude oil. In 2019, the continuation of worldwide central banks tightening pressures global economic growth and the prices of assets and commodities. Higher rig counts and higher capital expenditures by major oil & gas companies worldwide during the recovery also cause concerns of oversupply. According to Baker Hughes, as of December 28, 2018, the rig count in the U.S. was 1,083, 16.6% higher from December 29, 2017.LNG (Bullish)U.S. LNG daily production hit record high of 5.28 Bcf during the week of Christmas, according to S&P Global Platts. Large-scale additions to production capacity in 2018 included Shell’s Prelude and Inpex’ Ichthys, both offshore Australia, and Novatek expanded its Yamal LNG facility, while demand is slowing down in Asia, the biggest LNG market in the world. Europe is likely to play the key role in absorbing all the additional production as geopolitical factors, pipeline capacity issues and the controversial Nord Stream 2. Also, Gazprom’s contract for gas transit via Ukraine is expiring at the end of this year and surprise during negotiation is always possible among Russia, Ukraine and Europe.Going forward, LNG capacity will grow significantly in the U.S. The ability to send U.S. gas overseas will be a welcome reprieve for an oversupplied domestic gas market. This could create positive price pressure in gas markets. However, this could also have more localized effects as opposed to widespread.Bankruptcies (Mixed to Bearish)After ebbing for the past several years, bankruptcies in the energy sector increased slightly in number and dollars. According to the latest bankruptcy tracking report from Haynes and Boone LLP, bankruptcies upped a notch in 2018.[caption id="attachment_24732" align="alignnone" width="606"]Source: Haynes and Boone LLP[/caption] Thoughts on these statistics are mixed. With the drop in prices in the second half of 2018, concern could mount that more bankruptcies may be ahead. The good news is that many companies have already restructured their balance sheets over the past few years and oriented their business models to operate at $50 oil and $3 gas. Therefore, they can have some stability in this pricing environment. However, at the same time, a number of public companies made announcements of significant reductions in their 2019 exploration and production budgets. This could lead to an increase in filings for remaining producers who may have tighter cash positions in the event of capex and budgetary strains. Capital Spending for 2019 (Mixed)North American E&P spending as a whole is expected to lag behind international markets but is estimated to grow 9% in 2019, according to a global E&P report released from Barclays. Barclays noted, however, “spending is exposed to more downside risk given the recent oil price collapse,” which isn’t fully captured in budgets that have been approved thus far. It’s also important to note that not all companies have announced 2019 plans yet.Several companies (such as Apache, Diamondback, Parsley, Centennial, Halcon and Chesapeake) are expecting to make budgetary reductions.[caption id="attachment_24733" align="alignnone" width="640"]Source: Shale Experts[/caption] However, several others (such as Anadarko, Pioneer and Devon) appear to be looking to maintain or even increase rig counts in the Permian Basin in 2019. [caption id="attachment_24734" align="alignnone" width="640"]Source: Shale Experts[/caption] Hess Corp announced a 2019 E&P capital and exploratory budget of $2.9 billion slated for 2019, up from $2.1 billion in 2018. Approximately 75% will be allocated to high return growth assets in the Bakken and Guyanna. ConocoPhillips has set a capex budget for 2019 of $6.1 billion, which is comparable to its 2018 capex, excluding any acquisition costs. Approximately $3.1 billion will be allocated to rigs across the Eagle Ford, Bakken and Delaware plays. M&A (TBD)Activity in this realm has been relatively slow lately. This is probably due to the drop in oil prices. However, this pricing could also portend more M&A activity. Upstream valuations are trading at relative lows compared to the wider stock market. This could combine for more transactions in 2019. Companies plan for longer term pricing and long term expectations, using the futures curve as an indicator, are still around $54 going out about five years.There is a lot of capital in the marketplace that is waiting to be placed. If these conditions continue, it could give rise to more deals and more dollars in 2019.ConclusionThe indicators are out there, and one thing’s for sure—they don’t all align.  Economist Karr Ingham, while recognizing the challenges of some of these bearish signals, remains optimistic. “The growth in Texas crude oil production even in the face of lower prices, rig counts, drilling permits and employment compared to 2014 peak levels remains the story of the year.”Valuations have suffered in 2018, but if the structural undergirding of the recovery over the past few years is strong, then the U.S. upstream sector should still be able to not only survive but thrive in 2019. Whatever happens, this muddied picture will become more clear as the year gets going.Originally appeared on Forbes.com.
Risk and Return
Risk and Return

Working Interests and Royalty Interests

Because of the historical popularity of this post, we revisit it this week. Originally published in 2017, this post helps you, the reader, understand the various risk factors which pertain to mineral interests. U.S. Mineral Exchange defines a mineral interest as “the ownership of all rights to gas, oil, and other minerals at or below the surface of a tract of land.” Last week we reviewed the three types of mineral interests – royalty interests, working interests, and overriding royalty interests. This week we analyze the risks associated with working interests versus royalty interests.  An overview of royalty interests and working interests is included below:Royalty Interest – an ownership in production that bears no cost in production. Royalty interest owners receive their share of production revenue before the working interest owners.Working Interest – an ownership in a well that bears 100% of the cost of production. Working interest owners receive their share of the profit after (i) royalty owners have received their share and (ii) after all operating expenses have been paid. Central to corporate finance is the principle that returns follow risk. As the risk of an investment increases, so do potential returns and potential losses; lower risk means less expectation for reward.  The Oil and Gas Financial Journal illustrates oil and gas investment risk in the following graphic:When valuing mineral interests, it is important to consider the nuances of each type of mineral interest. Given that risk and asset values are indirectly related, it is important to keep in mind the various risk factors which pertain to the mineral interest.  We’ll begin by examining the various risks surrounding both types of interests.RiskBoth working interests and royalty interests are exposed to fluctuations in oil and gas prices. When crude oil prices fell in mid-2014, so did the value of working interests, whose worth is based on the present value of the cash flows generated from production, and the value of royalty interests, whose value is based on future payments of revenue. Further, both working interests and royalty interests face the risk of depletion as oil and gas wells are depleting assets.  Even if the price of oil and gas is stable from one year to the next, a well may have 30% less production in its second year.  This can dramatically decrease the yield of particular royalty and working interests.Holders of working interests can mitigate the risk of depletion by drilling new wells or improving production of existing wells.  While this gives a working interest holder more flexibility, it also requires a substantial investment in CAPEX. Working interest holders accept all fiscal burdens associated with the drilling process.Royalty interest holders, on the other hand, bear no cost of production but are at the mercy of their operators. Only the working interest owner can decide to halt production when prices drop and to increase production when the drilling environment is favorable.  The Oil and Gas Financial Journal compares buying a royalty interest to “buying an income strip in producing wells, and the risks are primarily price volatility and depletion.”Each type of interest has unique attributes, but the fact that working interest owners are responsible for operating expenses makes working interests inherently riskier than royalty interests which are characterized by monthly “mailbox money” precipitated by zero costs. We see this when examining the volatility of select E&P companies who spun off their royalty interests into royalty trusts structured as MLPs.The royalty trusts above generally demonstrate less volatility, which is often used as a proxy for financial risk, than their parent E&P companies.  The principles of risk and return, however, tell us that because there are fewer risks associated with royalty interests they will yield lower returns than their riskier counterparts. Royalty interests range in percentage ownership of revenues from 0.025%-25%, meaning that, at the highest royalty interest, at least 75% of revenue is still funneled to the working interest owners. Due to differences in risk, royalty interests are unlikely to generate the magnitude of returns that working interests can experience. At the same time, they are less likely to experience the same degree of loss.ReturnThe standardized measure of investment performance for a given unit of time is return.  Investment returns have two components.  The first, yield, measures the current income (distributions) generated by an investment.  Capital appreciation, the second component, measures the increase in value during the period.  As shown below, total return is the sum of yield and capital appreciation.Royalty trusts commonly make substantial distributions because they generate revenue as long as their operators are drilling and they have minimal operating expenses. Thus it is important to examine total return when comparing interests in E&P companies, who own working interests, and royalty trusts who own royalty interests. In the chart below we examine the total returns of the companies introduced above and their associated royalty trusts.As expected, the E&P companies which hold working interests show higher returns and steeper losses than their associated royalty trusts.We have assisted many clients with various valuation and cash flow issues regarding royalty interests.  Contact Mercer Capital to discuss your needs in confidence and learn more about how we can help you succeed.
Mineral Interest Owners: How to Know What You Own
Mineral Interest Owners: How to Know What You Own
As we’ve discussed, there are plenty of factors to consider when determining the value of mineral interests. While some mineral owners may be very well attuned to decline curves and local pricing dynamics, others may only casually monitor the price of oil and gas to get a general sense of the trend in the industry.  This post is geared towards those mineral interest owners who have less knowledge on the subject and should serve as a guide for those seeking to learn more about what they own. We frequently receive calls from mineral interest owners who know little about what they own other than the operator’s name on the check and the amount they receive each month. Besides just the amount paid by the operator, royalty checks provide valuable information to mineral owners that can help determine the value of their minerals.How to Read a Royalty CheckThe information on royalty checks is beneficial because it gives mineral interest owners plenty of granular detail on how the operator calculates their monthly payment. The problem is that companies may issue checks with differing formats (see two examples below) and they can be hard to read. However, with a trained eye, mineral interest owners can learn to read these checks and glean valuable insight into what is driving the value of their interests.The first example is a check one might actually receive in the mail. The second is a sample check provided by an operator to help owners understand what it means. Regardless of the operator, there are a few key items that appear on every check:Ownership PercentageProduct CodeCountyOwnership PercentageA lease arrangement is designed to be a mutually beneficial agreement. Mineral owners own the rights to a valuable commodity, but they lack the ability to harvest it themselves. Operators come in with the equipment and requisite knowledge necessary to extract minerals from the ground. In exchange for the right to drill on the property, operators pay mineral owners a fraction of the revenue generated from the production. This fraction can appear on a check as a string of numbers like 0.0234375. You may be wondering, where does this number come from? This is the product of the net mineral acreage owned multiplied by the royalty percentage negotiated.Most of the United States uses the Public Land Survey System which is divided into townships and further into sections. A township is 36 sections and a section is 640 acres (or one square mile).[1] Sections are further broken down into quadrants, or some other division as the land is passed down over time. For instance, a lease could specify “all of the mineral interest under the E ½ SE ¼ of 11-2N.” This is read “The east half of the southeast quarter of Section 11, township 2 North.”  As depicted below, this would be the rectangle in the bottom right quarter, and would represent 80 net mineral acres.  That is: 640 acres per section times ¼ times ½. The lease would go on to specify the royalty percentage to be paid, like 3/16. This will frequently be presented in some form similar to the follow: “To pay Lessor for gas (including casinghead gas) and all other substance covered hereby, a royalty of 3/16 of the proceeds realized by Lessee from the sale thereof.” This simply means the operator will pay a royalty of 3/16 of revenue generated from production on the property. Multiplied by the 80 net mineral acres that make up the 640 acre section, we arrive at: 80/640 x 3/16 = 0.0234375Owners will note much larger dollar figures on their checks which represent the gross revenue the operator receives from production of the minerals.  This gross value is multiplied by the ownership percentage, which determines the amount actually received by the owner on their check. Knowing the net mineral acreage owned (not determined by the operator) can help determine the royalty rate the mineral owner is being paid, which helps to understand the value ultimately being paid for their interests.Product CodeThe information on royalty checks is beneficial because it gives mineral interest owners plenty of granular detail on how the operator calculates their monthly payment.The revenue received by both the operator and ultimately the owner depends on both the quantity produced and the price achieved.  As of the writing of this article, crude oil prices are trading around $53 per barrel for West Texas Intermediate (WTI), the most commonly tracked figure for U.S. crude oil. By comparison, natural gas is trading around $3.04 per Mcf at the Henry Hub, the most common benchmark for natural gas in the country.  Knowing what is being produced: oil, gas, NGL, or a combination of these is crucial to understanding the value of the interests. Owners can figure this out by looking at the product code on their checks, which can be expressed as either a letter or number. Our first example lists the product code as 204, and the legend at the bottom of the check indicates that gas is being produced. Even less clearly, our second example shows the letter “G” under the “P” column, and which, according to the legend, means gas is being produced. This can be far from intuitive without some sort of key describing each item.When oil prices decline, as they have since the beginning of October, mineral owners who receive royalty checks based on oil production can expect to see smaller figures on their checks. But the price isn’t purely based on the value listed on an exchange. It also depends on location and infrastructure to bring the commodity to market.CountyThe county where the minerals are produced is another common feature of royalty checks. However, it is not clearly stated as “Gaines County” for example. In our first example, we see the check says /TX/ Gaines which tells us the mineral interests are in Gaines County, Texas, which is located in the prolific Permian Basin. Again, this isn’t very clear just from looking at the check, and someone not from the region may not automatically know the names of counties in different states.Knowing the county where the minerals are located can go a long way to understanding their value.  For instance, oil production in the Permian Basin has increased significantly in recent years and has been a very attractive place for industry players. However, a lack of pipeline infrastructure has led to oversupply, meaning operators were forced to take a discount to the WTI price. Mineral owners have no control over where and when operators choose to produce, and current production leads to more upfront revenue, but taking a discounted price to get the revenue upfront could ultimately be detrimental to mineral owners in the long term, given the way production tends to decline significantly.Other Sources of InformationWhile royalty checks are tangible pieces of information sent frequently to mineral owners, there’s more information out there that owners can turn to. The lease agreement itself can be the primary source for determining what you own. While many may look the same, lease agreements are ultimately an economic agreement between two parties and can have a variety of different clauses. However, there are frequently instances where our clients do not have access to these key documents. In the case of interests being passed down or donated, clients are usually dealing with legacy arrangements with operators and may not have all the documents that spell out the specific rights with their particular lease.Royalty checks provide valuable information to mineral owners that can help determine the value of their minerals.There are other potential sources of information published online that owners can access free of charge. For instance, in Texas, there’s the Texas General Land Office and Texas Railroad Commission where mineral owners can, among other things, zoom in on plots of land and see well locations. Mineral owners can also learn about historical drilling permits and activity by region. The FDIC also publishes sales of oil and gas interests which can be helpful to see actual sales prices for mineral interests observed in the market.ConclusionRoyalty checks are hardly intuitive, and not everyone would bother asking too many questions when they regularly receive a check in the mail. However, without putting in some research, it can be hard to know if the next check will be higher or lower, or if there will even be one next month. That’s where it becomes crucial to understand what drives the value for mineral interests and what are the relevant risk factors. For those looking to sell their interests, or simply looking to understand the value of what they own, an appraisal can be a helpful tool in understanding both the value of mineral interests, and what drives this value. It is important to seek advice from someone who has experience valuing mineral interests and is well-versed in all potential sources of information.Mercer Capital is an employee-owned independent financial advisory firm with significant experience (both national and internationally) valuing assets and companies in the energy industry (primarily oil and gas, bio fuels and other minerals). Our oil and gas valuations have been reviewed and relied on by buyers and sellers and Big 4 Auditors.As a disinterested party, we can help you understand the fair market value of your royalty interest and ensure that you get a fair price for your interest. Contact anyone on Mercer Capital’s Oil and Gas team to discuss your royalty interest valuation questions in confidence.[1] Exampled based on a presentation at the National Association of Royalty Owners (NARO) 2018 Conference in Denver, CO
Oilfield Services in 2018
Oilfield Services in 2018

A Year in Review

Companies in the energy sector and the broader market experienced an interesting year showing steady and strong growth in Q1-Q3 and met volatility in Q4, which effectively erased gains on the year and even resulted in negative returns.The oilfield services (OFS) sector, in particular, was impacted heavily during last quarter’s downturn driven primarily by fears of oversupply in the market and E&P companies cutting back and looking for discounts. Oil prices steadily rose from about $47 per barrel in August 2017 to over $73 per barrel in October 2018 as OPEC and a Russia-led pact of non-OPEC members coordinated efforts to bring supply production into balance.However, reports of increased global supplies, including from countries such as Saudi Arabia, Russia, and the U.S. resulted in prices falling again. WTI experienced a 44% decline from a 2018 high of $75 per barrel to lows of around $43 in late December. The OSX, the index tracking OFS sector stock performance, was sideways for the most of 2018 and fell in tandem with the fourth quarter oil crash, resulting in an all-time low for the index of $80. The large and rapid hits were reminiscent of the declines experienced in 2014, and operators have been playing it close to the chest in terms of spending. Volatile oil prices and E&P spending will be among the major factors contributing to overall OFS performance going into the new year. M&A ReviewTransaction activity for the oilfield services sector for 2018 was near identical to 2017 in terms of number of deals, and total deal value saw a slight uptick. Low volatility and stable growth that defined 2017 markets and steadily increasing oil prices for most of 2018 have allowed for moderate transaction activity compared to the two years prior to 2017. This environment has also facilitated OFS companies to be more methodical in acquisitions compared to the past.As we discussed in a prior post, factors influencing transaction activity shifted from financial stress and cost efficiencies to economies of scale and enhanced offerings especially in technology and other efficiencies. The following table shows select transactions that occurred in 2018 with relevant enterprise value multiples, as companies sought strategic growth opportunities. Despite the fourth quarter turmoil, transactions from October to December constituted over 30% of total year deals. The observed mix of transactions for the year covered a broad spectrum of subsectors within the OFS sector. Contract drilling and well servicing/completion companies appeared to have slightly more transaction activity compared to other subsectors, but there was not an apparent trend identified within subsector deal activity.Fewer Bankruptcies for 2018Bankruptcies in the energy sector have ebbed since 2015 and 2016, but the recent slump in commodity prices do not point toward continued improvement for 2019, according to the latest bankruptcy tracking report from Haynes and Boone LLP.During 2018, the OFS bankruptcy filings decreased both in number to 12 filings and in aggregate debt of $3.85 billion compared to 2017 which consisted of approximately 40 filings and aggregate debt of $35 billion.However, with oil prices dropping over a third of its value in the final quarter of the year, a number of public companies made announcements of significant reductions in their 2019 exploration and production budgets, directly impacting prospects for many OFS companies. In turn, this could lead to an increase in filings in the first quarter of 2019 in the event of capex and budgetary strains.But while a number of companies are expecting to make budgetary reductions, several are looking to maintain or even increase spending in 2019.Spending and Outlook for 2019Analysts with Moody’s Investors Service believe that the health of the OFS sector is still quite weak with many burdened by high debt and added pressure brought by the drop in crude prices in late 2018. But the sector could see a 10% to 15% increase in overall earnings in 2019 as E&Ps increase spending. The key factor alluded here is that spending for many of these companies is anticipated to follow later in the year after riding out Q4 2018 shocks.Spending for many of these companies is anticipated to follow later in the year after riding out Q4 2018 shocks.Sajjad Alam, vice president-senior analyst for Moody’s, said in his report, “Most of that growth will likely come only later in 2019 after the heightened oil-price volatility of late 2018. Infrastructure constraints in the Permian Basin will also limit OFS operators’ ability to raise prices early in 2019.”Limited spending is a concern for OFS companies as many E&Ps weigh the choices surrounding budget appropriations. But many companies and private equity firms still appear to be committed to proposed capex budgets of increased spending on much needed infrastructure.Hess Corp announced a 2019 E&P capital and exploratory budget of $2.9 billion slated for 2019, up from $2.1 billion in 2018. Approximately 75% will be allocated to high return growth assets in the Bakken and Guyanna.ConocoPhillips has set a capex budget for 2019 of $6.1 billion, which is comparable to its 2018 capex, excluding any acquisition costs. Approximately $3.1 billion will be allocated to rigs across the Eagle Ford, Bakken, and Delaware plays.North American E&P spending as a whole is expected to lag behind international markets but is estimated to grow 9% in 2019, according to a global E&P report released from Barclays. Barclays noted, however, “spending is exposed to more downside risk given the recent oil price collapse,” which isn’t fully captured in budgets that have been approved thus far.Value ConsiderationsFrom a valuation perspective, we examined a selection of guideline company groups for relative value changes over time. One way to observe this relative value change is to look at enterprise value, adjusted for cash, relative to total book value of net invested capital (debt and equity) held by the company or “BVIC.” Any multiple over 1.0x indicates valuations above what net capital investors have placed into the firm.Take for example, Land Contract Drilling and Services subsectors: EV/BVIC multiples have fallen since the middle of the year and even below observed 2017 levels. Investors were not expecting to receive adequate return on capital deployed at these companies. After analyzing our guideline companies for oilfield services and equipment overall, observed average and median multiples for 2018 were below 1.0x for 2018. The only outliers within this sector are pressure pumping and fracking concentrated businesses, which are more directly tied into the value expansion in the oil patch.  The demand for pumpers’ technology and services has driven through the fourth quarter woes, showing that the market recognizes the contributions from these companies. ConclusionAs the energy sector brings in the new year, continued strategic M&A and fewer bankruptcies indicated positive signals for the health of the sector, but the fourth quarter collapse in oil prices have had companies and analysts alike cautious on the outlook for 2019 as evidenced in value considerations above.Ultimately OFS is weak right now due to multiple factors; however, there are reasons for optimism in the sector and growth opportunities during these uncertain times.Several companies underperformed to close out 2018, and many have made adjustments to conserve cash through debt restructurings, leverage reduction, and stringent capital discipline. Although oil prices have rebounded somewhat in the first weeks of January, volatility is still a primary concern when it comes to forward planning.U.S. spending is expected to increase in the next year, but many budgets among larger North American E&Ps have been reduced or have yet to be unveiled, which could mean further reduction of spending compared to preliminary estimates.Ultimately OFS is weak due to multiple factors stemming volatility, general market uncertainty, and the price crash; however, steady and methodical M&A during the year coupled with very few bankruptcy filings and prospects for late E&P spending increases offer optimism in the sector and growth opportunities during uncertain times.In addition to our corporate valuation services, Mercer Capital provides investment banking and transaction advisory services to a broad range of public and private companies and financial institutions.  We have relevant experience working with companies in the oil and gas space and can leverage our historical valuation and investment banking experience to help you navigate a critical transaction, providing timely, accurate and reliable results.Whether you are selling your business, acquiring another business or division, or have needs related to mergers, valuations, fairness opinions, and other transaction advisory needs, we can help.  Contact a Mercer Capital professional to discuss your needs in confidence.
Q4 2018 Review and Outlook for 2019
Q4 2018 Review and Outlook for 2019
Oil Prices: 40% Off From Its Four-Year HighIn the fourth quarter of 2018, U.S. crude oil prices plunged by 40%, from $75 in the beginning of the quarter to $45 per barrel. The sanctions on Iran, OPEC’s third-largest producer, seemed to be the last push to higher prices in late September. The recovery since 2016 has been primarily driven by the supply side of the equation: OPEC’s production cut lowered inventory, and geopolitical tensions (such as Iran and Venezuela). The years-long recovery ended in just three months. The reasons include concerns about swelling U.S. shale output, rising crude oil inventories, inconsistency in Russia and OPEC’s execution of their production deal, and fears of a global economic slowdown. OPEC’s deal with Russia to cut 1.2 million barrels per day during the December 6-7 meeting couldn’t stop oil prices from falling. The sharp decline once again proved higher prices driven by supply almost always have a difficult time lasting.Natural Gas Prices: A Roller Coaster Ride in the Fourth QuarterNatural gas prices soared to $4.70 per mcf in mid-November due to several factors including an early and colder winter hitting North America. It's relatively rare to see the inverse relationship between crude oil and natural gas prices, which happened in the fourth quarter of 2018. A more than 50% increase in natural gas prices was coupled with nearly 30% downturn in crude oil prices during a seven-week period from early October to mid-November. Long oil short natural gas, once a popular trade by speculators, was punished during this unusual period of time. Natural gas prices ended the year at $3.25 per mcf, a 9.8% increase for the fourth quarter and 10.1% rise for the year. The roller coaster ride exhibits the notion that there are few long-term supply issues in natural gas in North America.Outlook for 2019It was truly a dramatic quarter for the industry. The fourth quarter of 2018 marked the end of the two and a half-year oil price recovery that began in 2016, while natural gas prices reached their highest point since 2014. Volatility disrupted capital intensive industries in general. Large investments consisting of millions, or even billions, may take years to complete while circumstances may totally change within a short period, such as the fourth quarter of 2018 we just experienced. However, many producers make capex decisions based on long-term expectations. The latest World Bank commodities price forecast released on October 29, 2018 shows Brent crude will average $74.0 in 2019 and approximately $69.2 from 2020 to 2023.According to the December Short-Term Energy Outlook, the EIA expects global liquid fuels consumption to increase by 1.5 million barrels per day in 2019, with growth largely coming from China, the U.S., and India. Trade tensions between the U.S. and China remain high entering 2019 and have shaken up most, if not all, industries, and oil and gas is no exception. China ranks second in oil consumption and surpassed the U.S. as the world’s largest crude oil importer in 2017. Slower growth in China is looming for the demand side of crude oil. In 2019, the continuation of worldwide central banks tightening pressures global economic growth and the prices of assets and commodities.  Higher rig counts and higher capital expenditures by major oil & gas companies worldwide during the recovery also cause concerns of oversupply. According to Baker Hughes, as of December 28, 2018, rig counts in the U.S. were 1,083, 16.7% higher than December 29, 2017.Improving pipeline capacity and the combination of horizontal drilling and hydraulic fracturing continue to drive higher and more efficient production in the U.S.In 2019, it is expected that the U.S. will continue to lead the growth in oil supply worldwide. Improving pipeline capacity and the combination of horizontal drilling and hydraulic fracturing continue to drive higher and more efficient production in the U.S. According to the EIA, U.S. crude oil production recently set a record of 11.5 million barrels per day in September 2018. For a single week in November 2018, the U.S. was a net exporter of crude oil and petroleum products. EIA expects U.S. crude oil production will average 10.9 million barrels per day in 2018, up from 9.4 million barrels per day in 2017, and will average 12.1 million barrels per day in 2019.U.S. LNG daily production hit a record high of 5.28 Bcf in Christmas week, according to S&P Global Platts. Large-scale additions to production capacity in 2018 included Shell’s Prelude and Inpex’ Ichthys, both offshore Australia, and Novatek expanded its Yamal LNG facility, while demand is slowing down in Asia, the biggest LNG market in the world. Europe is likely to play the key role in absorbing all the additional production given geopolitical factors, pipeline capacity issues, and the controversial Nord Stream 2. Also, Gazprom’s contract for gas transit via Ukraine is expiring at the end of this year and surprise during negotiation is always possible among Russia, Ukraine, and Europe.The EIA expects Brent spot prices will average $61 per barrel in 2019 and that West Texas Intermediate (WTI) crude oil prices will average about $7 dollar per barrel lower than Brent prices next year, while Henry Hub natural gas spot prices to average $3.11 per MMBtu in 2019.  With ongoing oversupply concerns, stabilizing geopolitical tensions, and lower forecasts for global oil demand, it appears in 2019 oil prices have a long way to recover to its previous high in 2018.
Cooler Weather Could Heat Up Appalachia
Cooler Weather Could Heat Up Appalachia
As the calendar turns to 2019, we turn our attention to the Appalachia region, and not by coincidence. Cooler temperatures in the winter months tend to lead to increased natural gas prices and consumption, and the Appalachia region is the largest natural gas producer in the country.  Fourth quarter energy prices moved in opposite directions—crude prices declined steadily over the period and natural gas prices increased from about $3.0 to $3.5 per Mcf, peaking at over $4.8 in mid-November.November Price SpikeIn its December edition of the Short-Term Energy Outlook, or STEO, the EIA reported the price of Henry Hub averaged $4.15/MMBtu in November, up 87 cents, or 27% from October. It attributed this increase to colder temperatures and lower inventory levels.  The EIA estimated that inventory in the U.S. stood at 3.0 trillion cubic feet at the end of November, which was 19% lower than the five-year average.Increased production, spurred by the season and higher prices, has increased supply to meet demand to a degree.Declining nearly 26% since its peak six weeks prior, the run-up in natural gas prices appears to have only been temporary. As we discussed with crude oil in our Q2 newsletter, higher inventory helps to smooth price volatility in the energy market. During this part of the year, natural gas inventories are drawn down as people fire up their heating units, but this year the initial draw down of inventories hamstrung as U.S. natural gas inventories began the season at a 15-year low. Increased production, spurred by the season and higher prices, has increased supply to meet demand to a degree. Milder weather forecasts and energy substitutes (coal) have reigned in prices as well.As we alluded to recently, the price spike was also due in part to short covering by hedge funds in response to the rapid decline in crude prices. Worried investors diverted funds from oil to gas to compensate for accumulating losses in oil. Given the smaller nature of the gas market compared to oil, there was an uptick in activity and prices. Quickly rising prices led to an overbought market that subsequently corrected and has been trending downward with trading volume throughout the end of the year.Appalachian Ethane Storage HubAt the beginning of December, the U.S. Department of Energy published a report to Congress on the feasibility of establishing an ethane storage and distribution hub in the United States, specifically, the Appalachia region. The report noted that significant production growth is expected to occur in the Permian and Appalachia, though the latter trails the former in terms of current infrastructure (95% of ethane storage in the U.S. is located near the Gulf Coast). Storage hubs balance seasonal supply and demand variations, and are crucial to smooth volatility, as evidenced by the November activity. The report notes that a distribution hub near the Marcellus and Utica plays would help allay geographic concentration risk along the Gulf Coast that is susceptible to severe weather events (e.g. Hurricanes Harvey and Irma). While such a hub would provide a competitive advantage, the report crucially notes it would not be in conflict with further expansion of infrastructure in the Gulf Coast.U.S. Secretary of Energy Rick Perry, who signed the report, said, “There is an incredible opportunity to establish an ethane storage and distribution hub in the Appalachian region and build a robust petrochemical industry in Appalachia.” While the report focused on the economic benefits of a hub, detractors note the lack of consideration of environmental costs. It remains to be seen how this will impact production and pricing in the region, but it would undoubtedly be a boon for the region and the industry.Rig Counts and ProductionAccording to calculations based on data from Baker Hughes, rig counts in North America increased 2.9% in the last three months and 16.6% over the last twelve months. The Permian Basin led the way and currently has just fewer than 500 rigs, representing about 46% of total rigs in the U.S. By comparison, the Appalachia region has had below 80 rigs since July 2015 though it has remained relatively consistent, above 70 since last May.Though production has spiked, Appalachia significantly lags the other regions in terms of total production.Oil production in the Marcellus and Utica plays has increased by 45.1% in the past year, growth even higher than the Permian.  Though production has spiked, particularly in the second half of the year (up 34.8% since June alone), it’s important to recognize the magnitude: Appalachia significantly lags the other regions in terms of total production.Natural gas is the major focus of the region, where production has increased 15.5% in the past year, trailing both the Permian (34.1%) and the Bakken (25.1%).  Again, size plays a role in these growth figures as Appalachia has about 2.5x the production than the next largest play, the Permian. A deeper dive into the DUCs tells a slightly different story, however, with the inventory of drilled but uncompleted wells declining 17% in the region over the past 12 months. This could temper the rate of growth for production for the region in 2019 if drilling in the regions doesn’t increase.Valuation ImplicationsAppalachia has consistently lagged the other regions in terms of EV/production multiples, also known as price per flowing barrel.  The Permian took center stage in 2017 but has retreated back to the rest of the pack.  The lower multiple seen in Appalachia is largely due to declines in enterprise values, though increasing production has played a role as well.Despite the recent increase in price, the EIA expects increased production in 2019 will cause the average price of natural gas to drop 6 cents, compared to 2018, to $3.11. This could explain why key players in the region are seeing lower stock prices.Range Resources is the largest natural gas producer in the Marcellus, but it has not seen a positive impact from higher prices over the past few months. The company’s share price has dropped further than the overall market, but this cannot solely be attributed to swings in natural gas prices. While Range’s share price has dropped along with the recent slide, it did not get the same treatment when the market spiked in mid-November. Since its long-term debt obligations do not begin to mature until 2021, the drop in share price has had a significant impact on its enterprise value. Range is uniquely positioned with capacity on the Mariner East 1 pipeline that will allow it to tap into the rising global demand for NGLs, so there is potentially an upside to its current price.ConclusionNatural gas prices have followed a curious path in the past three months with index prices spiking at the Henry Hub, but gas being flared in record proportions and even given away at a loss in the Permian. While pricing will remain dynamic, there are certainly positives for natural gas producers heading into 2019 with the potential for an ethane storage hub in the Appalachia region and a ramp-up in production of NGLs to satisfy the global market.We have assisted many clients with various valuation needs in the upstream oil and gas space in both conventional and unconventional plays in North America, and around the world. Contact a Mercer Capital professional to discuss your needs in confidence and learn more about how we can help you succeed.
EP First Quarter 2019 Region Focus Eagle Ford
E&P First Quarter 2019

Region Focus: Eagle Ford

Region Focus: Eagle Ford // After a sharp decline in crude prices and the stock market in general, the first quarter saw prices bounce back to finish about halfway between their Q4 peak and trough.
M&A in the Marcellus-Utica Shale
M&A in the Marcellus-Utica Shale

The Beast in the East

The domestic natural gas market has benefitted from large expansion in recent years, and this can be largely attributed to the growth experienced in Appalachia. According to a Deloitte study, Appalachia was the world’s 32nd-largest natural gas producing region in 2007, with levels comparable to Bolivia and Kazakhstan. As of 2017, it was the third largest, trailing only the full United States and Russia.Companies already with an established presence are planning to put more wells online in the coming year and increase infrastructure to supply a growing demand in the natural gas market.Henry Hub prices have been hovering around $3/MMBtu for over three years and recently have increased to just over $4/MMBtu in November due to a combination of expectations of colder than usual weather and short squeezes, increasing trading and price influencing in a market that is much smaller than oil. Despite the long-term low price environment, supply and demand have increased, driven primarily by the increased demand needs from the power sector. Economic viability of recoverability has not been impacted in light of the lower prices as Deloitte estimates that 50 years’ worth of natural gas can be recovered for less than $3/Mcfe.Despite the continued growth, transaction activity in the Marcellus-Utica in 2018 was slower than in 2017. Some companies have been moving in to capitalize on the increased demand for natural gas, as indicated by the energy outlook by the EIA, while others are restructuring their balance sheets in order to focus primarily on oil. While companies may not be rushing to the Marcellus-Utica in a similar manner as the Permian, companies already with an established presence are planning to put more wells online in the coming year and increase infrastructure to supply a growing demand in the natural gas market.Recent Transactions in the Marcellus-Utica Details of recent transactions in the Marcellus-Utica, including some comparative valuation metrics are shown below. Overall, deal count and average deal size have decreased from twelve months ago. There have been a handful of large deals though that show increased interest in the area.Ascent Resources Acquires 113,400 Acres in OhioAscent Resources, a company founded by Aubrey McClendon after he left Chesapeake Energy, announced that it is buying 113,400 Utica Shale acres in multiple deals along with 93 operating wells located in eastern Ohio for a total of $1.5 billion. The new acreage puts Ascent at over 300,000 Utica acres and catapults the company into one of the largest privately owned E&P drillers in the U.S. The selling companies are CNX Resources and Hess (each selling their share of a joint venture for $400 million each), Utica Minerals Development and a fourth, unnamed seller.The CNX and Hess JV sale marks a complete exit in the play, and both companies plan to utilize proceeds to fund share repurchase programs, pay down debt, and focus on growth opportunities in other established plays, such as the Bakken.Chesapeake Energy Sells Entire Utica Position to EncinoIn an even larger deal, Chesapeake Energy disposed of its entire interest in the Utica Shale to Encino Acquisition Partners for about $2 billion. EAP is backed by the Canadian Pension Plan Investment Board and Encino Energy. Chesapeake sold its stake in the Utica Shale to strengthen its balance sheet and further shifts its focus from gas production to oil, Chesapeake CEO Doug Lawler said in an interview. “We will absolutely be driving for a greater percentage of oil production in our portfolio,” Lawler said. “We hope to achieve that through organic growth, exploration and future acquisitions.”The sale to Encino Acquisition Partners includes 320,000 net acres in Ohio’s Utica Shale and 920 wells that currently produce about 107,000 barrels of oil equivalent per day. The purchase price also includes a $100 million contingent payment based on future natural gas prices. With a sale price of approximately, $2,222 per acre, this appears to be in line with the median transaction amount for 2018.Observed M&A Trends in the Marcellus-Utica Large Exits and Balance Sheet AdjustmentsSimilar to trends we observed last year in the Marcellus-Utica, large companies that have had established presences are moving out of the play entirely to focus on higher margin assets. Demand for natural gas is very high, but the inexpensive extraction costs paired with longer laterals for extraction have allowed supply to catch up, causing prices to remain low and relatively flat in the long term, with the exception of the high trading volume experienced last month.The price run-up in November, however, appears to be short-lived, and the commodity appeared to be overbought.  High expectations and rising EIA forecasts for domestic production explain why the U.S. gas futures market has held backwardation even though near-term pricing has spiked. Futures prices for 2019 and 2020 have declined back to the $2.50 to $3.00 range, and with margins remaining low for the foreseeable future, it makes sense for companies to adjust their balance sheets and unload assets that are not meeting their margin goals.Continued Ease of M&AAlthough the low price and low margin environment has caused some to exit the Marcellus and Utica plays, the stable prices environments make mergers and acquisitions easier, with public companies in a better position to make deals than private equity investors.The stable prices environments make M&A easier, with public companies in a better position to make deals than private equity investors.According to Robert Hagerich, Senior Vice President at Macquarie Capital (USA) Inc., established public companies are looking to expand acreage and existing holdings, and can use their stock as currency to buy leases that are adjacent to their holdings with operating midstream infrastructure and production volumes that can be immediately booked with the purchasing company. On the other hand, private equity buyers are usually financing the exploratory drilling that expands the core fairways of the shale plays essentially buying an option on improved prices. This trend began in the later part of 2017, and it has continued into 2018. "Stable pricing brings buyers to the table," says Hagerich. "Buyers are looking for leases that are exposed to the core areas of the shales, contiguous acreage, leases held by production, ownership of the gathering system and access to more than one transportation pipeline." The low volatility nature of the natural gas market compared to oil or LNG facilitates M&A activity and allows for consolidation opportunities as observed from the merger of Blue Ridge Mountain Resources and Eclipse Resources Corp. in August and the heavy consolidation activity from EQT in 2017. The Marcellus-Utica continues to be a powerhouse for natural gas production and doesn’t show signs of slowing down anytime soon. Strategic transactions in the area allow companies to focus on assets that drive their core business and others to consolidate in the area and supply the growing demand for natural gas in the U.S. We have assisted many clients with various valuation needs in the upstream oil and gas in North America and around the world.  In addition to our corporate valuation services, Mercer Capital provides investment banking and transaction advisory services to a broad range of public and private companies and financial institutions.  We have relevant experience working with companies in the oil and gas space and can leverage our historical valuation and investment banking experience to help you navigate a critical transaction, providing timely, accurate and reliable results.  Contact a Mercer Capital professional to discuss your needs in confidence.
Before Selling Your Oil and Gas Royalty Interest, Read This
Before Selling Your Oil and Gas Royalty Interest, Read This
Because of the historical popularity of this post, we revisit it this week. Originally published earlier this year, this post helps you, the reader, think through important issues when considering selling your oil and gas royalty interest. There are many reasons that you may want to sell your oil and gas royalty interest, but a lack of knowledge regarding the worth of your royalty interest could be very costly.  Whether an inflow of cash would help you make ends meet or finance a large purchase; you no longer want to deal with the administrative paperwork or accounting cost of reconciling monthly revenue payments; or you would prefer to diversify your portfolio or move your investments to a less volatile industry, understanding how royalty interests are valued will ensure that you maximize the value. There is a market for royalty interests, making them fairly liquid; therefore, most of the time, the difficulty is not finding a buyer, but determining whether the buyer’s offer is appropriate.Understanding how royalty interests are valued will ensure that you maximize the value.Given that many royalty owners have little connection with the oil and gas industry aside from the monthly payments they receive, buyers may bid substantially below a royalty’s fair market value hoping to earn a profit at the expense of an uninformed seller. As such, it is critical that royalty owners looking to liquidate their interest understand its value to ensure that they can identify legitimate bids.Before attempting to sell your mineral interest, understand these issues.Understand What You Are SellingA royalty interest represents a percent ownership in the revenue of an E&P company.  Royalty interest owners have no control over the drilling activity of the operator and do not bear any costs of production. Royalty interest owners only receive revenue checks when their operator is producing minerals but see no monthly payments when production is suspended.1Recognize Production and Price as Value DriversThe value of a royalty interest is based on the present value of expected future cash flows, which are a percentage of an operator’s revenue.An operator’s revenue is dependent upon production and price.  Thus, when determining the value of a royalty interest, it is critical to understand a well’s future potential for production and the market forces that affect price.Production: The Decline Curve’s ImpactAs oil and gas is extracted from a well, its production declines over time.  Every well has a unique decline curve which dictates production. A decline curve graphs crude oil and natural gas production and allows us to determine a well’s Estimated Ultimate Recovery (EUR).   A variety of factors can affect the shape of a well’s decline curve.  For example, decline curves are generally much steeper if the well is drilled using unconventional techniques, like horizontal drilling, or hydraulic fracturing. When determining the value of an oil and gas royalty interest, it is critical to understand a well’s EUR because the value of your royalty interest is dependent upon future production.Price: Local and Global Market ForcesOil and gas prices are affected by both global and local supply and demand factors.  The oil and gas industry is characterized by high price volatility.  The size and global nature of this market mean that these prices are influenced by countless economic – and sometimes political – factors affecting individual producers, consumers, and other entities that comprise the global market.  Most operators, however, sell their oil and gas at a slight discount or premium to the NYMEX because of local surpluses or shortfalls.  Thus, it is important to understand the local market as well.Understand Location’s ImpactDrilling economics vary by region. There are geological differences between oilfields and reserves that make it harder to drill in some places than others. Whereas some wells can be drilled using traditional, conventional techniques like vertical drilling, less permeable shale wells must be drilled using unconventional methods, like horizontal drilling or hydraulic fracturing. These unconventional methods tend to bear higher operating costs. Location also tends to influence drilling and transportation costs, ultimately making breakeven prices and profits vary across and within regions. Although a royalty interest owner is paid before any operating expenses are accrued, an operator considers break-even pricing when determining whether to continue operating a well or suspending operations. Accordingly, the value of any royalty interest is strongly influenced by its location, and it is important to consider geological differences when valuing any mineral interest.Proceed with CautionWhile there are legitimate online brokers who will buy your royalty interest for a fair price, it is important to be on the lookout for those who aim to profit at your expense.Beware of online royalty brokers who only consider rules of thumb such as 4x to 6x annual revenue. While industry benchmarks can be a helpful aid, they should not be relied upon solely to determine value, as they do not consider specific well economics.A lack of knowledge regarding the worth of your royalty interest could be very costly.If the entity valuing your interest is also an interested party, it is critical to remember that they have an incentive to quote a low value.Mercer Capital is an employee-owned independent financial advisory firm with significant experience (both nationally and internationally) valuing assets and companies in the energy industry (primarily oil and gas, bio fuels and other minerals).  Our oil and gas valuations have been reviewed and relied on by buyers and sellers and Big 4 Auditors.As a disinterested party, we can help you understand the fair market value of your royalty interest and ensure that you get a fair price for your interest. Contact anyone on Mercer Capital’s Oil & Gas team to discuss your royalty interest valuation questions in confidence.End Note1 For more information on mineral interests see our post, Three Types of Mineral Interests.
Accounting for Risk in Oil and Gas Reserve Valuations
Accounting for Risk in Oil and Gas Reserve Valuations

Reserve Adjustment Factors and Risk-Adjusted Discount Rates

One of the most complex aspects of oil and gas valuation is accounting for the risk associated with proved developed nonproducing reserves (PDNP), proved undeveloped reserves (PUD), and the less certain probables and possibles (P2 and P3 Reserves).When valuing proved developed producing reserves, estimates of future production, pricing, and expenses are based on historical results.  However, production projections and expense forecasts are more speculative when it comes to PDNP reserves as they are not based on recent production history, and are even more abstract when it comes to PUD reserves since the wells have not yet been successfully drilled.Accounting for RiskGenerally, there are three ways to account for the additional risk associated with PDNP, PUD reserves, probables, and possibles:Using a risk-adjusted discount rate (RADR),applying a reserve adjustment factor (RAF), orutilizing a modified option pricing model. In this post, we outline the basics of risk-adjusted discount rates and reserve adjustment factors. Some of the best guidance on measuring this risk is published by the Society of Petroleum Evaluation Engineers (SPEE).  Every year at its annual meeting in June the SPEE presents the results to its annual survey to better understand the parameters used in property evaluation. The SPEE Survey is a global study, however, the majority of participants evaluate U.S. properties.  The June 2018 survey had a total of 266 responses with over 80% of participants spending over half of their time evaluating U.S. properties.  It covers a wide range of topics such as futures prices, costs and escalation, accounting for risk, reserve disclosures, and probabilistic methods.  The survey presents the average RAF and RADR, as well as the 10th percentile, 50th percentile, and 90th percentile results, based on the reserve type.What are RADRs and RAFs?A RADR is used to discount future cash flows to their present value while compensating for the additional risk associated with estimating future production from PDNP, PUD, P2, and P3 reserves.  A RADR is higher than a discount rate used in a typical discounted cash flow analysis associated with companywide cash flows.  Risk-adjusted discount rates generally fall within the range of 10% to 27%, according to the SPEE Annual Survey.Reserve adjustment factors are applied to the present value of all future cash flows after a standard discount rate has been applied.  RAFs vary widely; PDNP reserves generally have RAFs of 100% (no discount), while we have observed appraisals that have applied an RAF of 0% (implying a 100% discount) to PUD, P2, and P3 reserves.There are many qualitative factors that should be considered when determining the appropriate RAF or RADR.The current pricing environment. Is it economical to drill or start producing in the region given the current pricing environment for oil, natural gas, and NGLs?Regional infrastructure issues. Is the necessary infrastructure in place to move products to market or is future production dependent upon increasing infrastructure out of the region?Outlook/health of operators. For non-operators, there is additional risk associated with this relationship with a third party.  Is the operator considering exiting the region due to the local drilling economics?  Does the operator have enough capacity to bring new projects online?  Is the operator financially stable or at risk of going out of business? These are just some of the many pertinent questions to ask when analyzing the risk associated with PDNP and PUD reserves.Applying a RAF or RADRGenerally the application of a RADR and RAF are interchangeable; however, it is important to avoid double counting risk when determining an appropriate discount rate to use in conjunction with a RAF.The examples below show typical valuations of PUD reserves. The first applies the 50th percentile result of the SPEE Survey for the reserve adjustment factor (60%) and the second uses the 50th percentile result for the risk-adjusted discount rate (20%).The results presented in the survey do not necessarily present reserve adjustment factors and risk-adjusted discount rates that compensate for the same level of risk, as shown by the lower valuation conclusion reached when using the RADR from the 50th percentile.  For a test of reasonableness, it is important to consider the implied risk-adjusted discount rate based on the selected RAF.  In the example above, a 60% RAF is approximately equivalent to a 15.25% risk-adjusted discount rate.Market Evidence for RAFs and RADRsThere is evidence in the public marketplace that undeveloped reserves are priced at a discount to their proven producing counterpart.  For example, a recent acreage transaction in Gaines County was priced at a significantly lower acreage multiple than a transaction in Cochran County Texas, although the acreage was relatively close (only one county away). The acreage in Gaines County is in the Midland Basin, but the acreage in Cochran County is in the Northern Shelf; thus, in theory, the acreage in Gaines County is considered to be of higher quality.  The acreage in Gaines County, however, consisted entirely of undeveloped acreage whereas the acreage in Cochran consisted of mostly producing acreage. The transaction of undeveloped acreage in Gaines County of the Midland Basin transacted at a 76% discount to acreage in Cochran County in the Northern Shelf, which equates to a reserve adjustment factor of 24%. While there are unique aspects of every transaction which make them hard to compare, there is a logical case to be made for the appropriateness of reserve adjustment factors and risk-adjusted discount rates.  In the valuation profession, the most commonly used standard of value is “fair market value” which is defined as: The price, expressed in terms of cash equivalents, at which property would change hands between a hypothetical willing and able buyer and a hypothetical willing and able seller, acting at arm’s length in an open and unrestricted market, when neither is under compulsion to buy or sell and when both have reasonable knowledge of the relevant facts.[1]A hypothetical investor would weigh the risks associated with the development of PUD reserves and would consider an investment in these assets to be inherently riskier than an investment in PDP reserves.  As valuation professionals, we account for this risk by application of a RADR or RAF.Mercer Capital has significant experience valuing assets and companies in the energy industry, primarily oil and gas, biofuels, and other minerals.  Our oil and gas valuations have been reviewed and relied on by buyers and sellers and Big 4 Auditors. These oil and gas related valuations have been utilized to support valuations for IRS Estate and Gift Tax, GAAP accounting, and litigation purposes. We have performed oil and gas valuations and associated oil and gas reserves domestically throughout the United States and in foreign countries. Contact a Mercer Capital professional today to discuss your valuation needs in confidence.[1] American Society of Appraisers, ASA Business Valuation Standards (Revision published November 2009), “Definitions,” p. 27.
Non-Operated Working Interests: Are You Investing in the Operator, the Oilfield, or Both?
Non-Operated Working Interests: Are You Investing in the Operator, the Oilfield, or Both?

Joint Ventures in Oil and Gas

Joint ventures (JVs) are fairly ubiquitous in the energy sector with as much as 71% of upstream investment through alliance or JV relationships. Companies will often enter into JVs to share the sheer capital intensive load of upstream and midstream activities.An oil and gas JV in its most basic form is fairly straightforward. A company will take on the operator role by working the field and constructing or managing the infrastructure in a given area, and another company will assume a non-operator role by providing capital so that each player is mutually benefited. Those entering into these relationships may contribute assets, capital, technologies, or even combinations of the aforementioned in order to access advantages such as scale, risk sharing, or entry into a specific market or play and both share in the future costs.Megaprojects of over $1 billion are largely structured as JVs and are especially useful to capitalize on synergies, infrastructure, and risk sharing. In an EY study of 365 megaprojects, JVs made up 85% of the projects in upstream activities and over 50% were in LNG and pipeline projects. On the surface, this may seem like an effective way for companies to structure a hedge and mitigate systematic risk through diversification of assets, but in reality, the benefits of a JV are much harder to realize. Management considerations quickly become complicated and time horizons tend to be short-lived. Research has shown that as many as 70% of JVs in oil and gas tend to fail within 5 years. From a valuation perspective, struggling or failing JVs can put a strain on overall company value as future income streams are subjected to a greater amount of uncertainty and, thus, are further discounted. In addition, most JVs lack a defined exit plan as a study from Boston Consulting showed that only 19% of respondents had a clear exit strategy. Even in a well-structured JV agreement, the absence of an exit strategy in an environment of high failure rates inevitably results in large tangible and intangible exit costs that can erode the value the JV initially was set up to create. Does the success of the JV hinge on the quality of the oilfield or the technical ability of the operator?Put simply, executing a successful joint venture requires a number of items working in harmony such as solid due diligence, good location, cooperation between both firms, and a degree of luck on the bet they are making.It seems a bit contradictory that a large number of projects are structured as joint ventures if they have such a high failure rate. This begs the question, does the success of the JV hinge on the quality of the oilfield or the technical ability of the operator? The answer, we think, lies somewhere in the middle.Location, Location, LocationEven with the difficulties of maintaining a successful JV, many companies have been entering into joint ventures to take advantage of the oil boom that the U.S. has enjoyed for the past several years. Not surprisingly, a large portion of recently formed upstream JVs since 2016 has been in the Permian Basin, and several large midstream JVs have been formed in the Gulf of Mexico. Recently, Williams Companies Inc. announced that it is forming a joint venture with privately-held Brazos midstream in the Permian Basin to gain exposure to crude and NGL and position itself for potential midstream opportunities. Williams is offering their gas gathering assets for a 15% stake in Brazos as part of the JV terms, with Brazos retaining 85% in the venture as well as operatorship. Almost all of the assets including gas and crude pipelines, storage and a planned processing plant are coming from Brazos Midstream with Williams offering dedicated acreage, a small amount of gas gathering infrastructure and inexpensive sources of financing. Companies have been scrambling to get a piece of the pie in the more recent surge in demand for natural gas.Even though the Permian has seen a large amount of activity and natural gas prices remain low, companies have been scrambling to get a piece of the pie in the more recent surge in demand for natural gas. Royale Energy has recently entered in a JV with California Resources Corp. to drill 30 wells throughout the Rio Vista Field, the largest dry gas field in California. This agreement expands on a previous JV and will give Royale up to three years to drill in any of the formations on the property.The historic property is abundant with gas, producing approximately 4 trillion cubic feet from more than 15 stacked gas reservoirs, and according to Royale, “The joint venture will lead to multiple years of drilling activity at Rio Vista at a time of upward trending natural gas prices due to declining natural gas inventories nationwide.”These transactions are but a few of the many JVs structured in areas to take advantage of the location and the resources it has to offer in a demanding market. And while it may seem like a no-brainer for the non-operator to search out operators in successful plays, many have had a history of missing the mark when it comes to structuring effective non-operated portfolios resulting in value being left on the table or outright failure.Adding Value to Non-Operating PortfoliosOil and gas companies are typically skilled at maximizing value with their operated assets. But more often than not, these companies tend to take a backseat approach to their non-operating portfolios, almost akin to treating them like equity investments. The detached and unsystematic treatment conflicts with the shared responsibility for the success or failure of their ventures.Boston Consulting Group identifies three main sources of value loss due to failure of material participation by non-operators: A nonstrategic approach, inconsistency, and lack of priority.They also outline a four-step framework for non-operators to add value to their non-operational portfolios:Clear strategic intent about what each non-operating venture (NOV) asset contributes to broader company goalsSharp risk and opportunity assessmentConsistent NOV organization and governanceRigorous execution strategies for each NOV asset The critical factors within this framework that can really determine success within a JV are operator assessment and analyzing venture risk. Non-operators with longstanding relationships and clearly defined roles and objectives (for example, ExxonMobil and Shell’s continued relationship in the North Sea) would most likely apply a less stringent approach to assessing key operator risk. But those looking to invest in active plays in the U.S. from a non-operator perspective should assess operators on the following criteria:Level of experience and familiarity of the play/assetUnderstanding and application of proven technologiesHistory of productivity and efficiencyClear understanding of role within the partnershipStrong safety, environment, and previous contract records andAlignment on ethics. Venture risk must be analyzed by non-operators to properly determine uncertainties related to the underlying objective within the JV. Resource size, character, and technology application must be considered especially when undertaking more exploratory ventures. Commercial and economic uncertainties should also be analyzed since a major culprit for failing JVs are large cost overruns and other unexpected costs.Final ThoughtsA major benefit of a JV is to gain exposure to areas and effectively deploy resources and capital where it could be best used and thus create maximum value. As we have mentioned above, however, failure rates are very high in the short term mostly as a consequence of cost overruns due to inadequate planning. But the natural frictions associated with a JV make planning and communication all the more important. While non-operators need the proper location for success in a joint venture, they can get further through proper due diligence and planning concerning operators.We have assisted many clients with various valuation needs in operator and non-operator roles in North America and around the world.  In addition to our corporate valuation services, Mercer Capital provides investment banking and transaction advisory services to a broad range of public and private companies and financial institutions.  We have relevant experience working with companies in the oil and gas space and can leverage our historical valuation and investment banking experience to help you navigate a critical transaction, providing timely, accurate and reliable results. Contact a Mercer Capital professional to discuss your needs in confidence.
Haynesville's Gigantic Gas Resurgence Could Be A Winner In LNG Export Race
Haynesville's Gigantic Gas Resurgence Could Be A Winner In LNG Export Race
Ever since producers took some big financial beatings after prices plummeted a few years ago, the Haynesville Shale play has positioned itself for an economic resurgence. For those following natural gas production in the U.S., this should not come as a surprise. It has a lot going for it.Haynesville’s Wells – Bigger, Faster, StrongerConsider the following:It’s a behemoth of a gas field that produces enormous wells. It’s been known for some time that the Haynesville has potential, but that is being realized further as more experience is developed among operators. For example, long lateral wells (some now stretch nearly two miles each) can produce up to 24 bcf of natural gas. Compared to the nearby Eagle Ford Shale, whose wells produce 12-15 bcf of natural gas, the Haynesville wells are big. In today’s low gas price environment, this matters quite a bit.The formation is more naturally pressurized than many others. This means, among other things, that more gas is produced in the first year. This is important, considering how expensive it is to drill these wells, and in turn, it means higher rates of return for investors (since time can erode returns according to present value theory).Breakeven prices have fallen. According to Chesapeake, which has the largest acreage position in the Haynesville, breakeven prices are currently between $2.00–$2.25 mcf. Even with price differentials of about $0.60 to Henry Hub, this provides an opportunity for profitable wells. Two or three years ago, this was considered an improbability. Investors have noticed. Amid the land rush for liquid plays such as the Permian Basin, some investors have quietly spent billions to reposition themselves in the Haynesville over the past few years at relatively low valuations. The most notable of which is Jerry Jones’ $620 million investment in Comstock Resources over the summer. Comstock has been one of the leading players in the basin for years and is confident that their experiences, amid a rough recent financial history, will propel them going forward. Lesser known private companies such as Aethon Energy and Indigo Natural Resources (which has contemplated going public) have also poured substantial investments into the play in the past few years.LNG Exports – A New Proverbial Finish LineThat said, one of the vexing problems that the natural gas sector often has is getting the product to relevant markets. The current situation in the Permian Basin is a prime example. Even though gas production is there, it doesn’t matter much if it can’t easily and inexpensively get to where it’s needed. And while the Haynesville has had its own struggles in this area, there may be solutions on the horizon to provide some relief. This is where the Gulf Coast LNG export resurgence comes into the picture.Currently, the ability to export LNG is relatively trivial. The continental U.S. has only two facilities operating with less than 4 bcf of capacity per day. That’s about to change. The Gulf Coast alone has nearly 8 bcf per day capacity under construction and another 6.8 bcf per day has been approved. Over 26 bcf per day has additionally been proposed.  Facilities are being proposed up and down the coast from Brownsville, Texas to Pascagoula, Mississippi. [caption id="attachment_23202" align="alignnone" width="640"]Source: Federal Regulatory Energy Commission[/caption] Along with capacity, transportation is getting easier too. The widening of the Panama Canal has certainly helped. In addition, certain transit restrictions on LNG vessels were lifted just last month. Over the past two years, 372 LNG transits have passed through the canal; and incredibly, earlier this year three tankers crossed at the same time. This is incentivizing the investment and engineering race to get capacity built and shipped to foreign markets. Most recently, Germany initiated stepstoward installing an LNG import facility.Haynesville’s Head Start – A Shorter And Cheaper Race To RunIn the race to chase efficiencies, the Haynesville’s proximity to the Gulf Coast provides a big opportunity for investors.What are the options to service the strongly growing demand? There’s a plethora of potential gas sources in the U.S. to fit the bill. Currently, the largest supply is the Marcellus and Utica shales in Appalachia, and this would seem to be a natural fit except that there is a problem. Prices for gas in the region are far below Henry Hub prices. In addition, transportation costs tower above other plays due to the multi-state journey it needs to take to get to the Gulf Coast.  By the time the gas arrives at its destination, it would almost certainly lose money for producers. Margins are simply too tight right now in the gas business and efficiency is becoming increasingly critical.In the race to chase efficiencies, the Haynesville’s proximity to the Gulf Coast provides a big opportunity for investors. At a recent conference, Tom Petrie, a leading energy investment banker, gave some estimates of transportation costs from proximate U.S. gas basins. Not surprisingly, the Haynesville was by far the cheapest at $0.25 per mcf. [caption id="attachment_23203" align="alignnone" width="587"]Source: Oil and Gas Investor, Petrie Partners[/caption] In a business where the window for profitability is small, pennies per mcf matter a lot. Naturally this dynamic calls for more localized gas. Considering the Gulf Coast concentration of LNG facilities, the Haynesville, Eagle Ford and other nearby plays may have a leg up with proximity and infrastructure ability to get gas to facilities. The Haynesville looks like it could have an international role to play in energy markets going forward. That is a golden opportunity to create value. As for the Marcellus and Utica shales in Appalachia, they might miss out on this one. It makes one wonder, why haven’t LNG applications shown up in Pennsylvania yet? Originally appeared on Forbes.com.
Four Themes from Q3 Earnings Calls
Four Themes from Q3 Earnings Calls

We Read the Q3 Earnings Calls so You Don’t Have to

Improvements in technology have driven the shale revolution. Among these improvements are both cost cutting by oilfield service providers and longer laterals from E&P companies. While capacity constraints from a lack of infrastructure has led to pricing differentials (particularly in the Permian Basin), a lack of inventory in the global oil market is expected to support higher prices, while also increasing price volatility.As we plan to do every quarter, we take a look at some of the earnings commentary of large players in the oil and gas space to gain further insight into the challenges and opportunities developing in the industry.Theme 1: Regardless of Region, Longer Laterals are Driving Efficiencies for E&P Companies[W]e continue to capture efficiencies through longer laterals. Last year, our program averaged 8,000 feet, but our portfolio high-grading efforts and asset swaps are enabling us to push beyond that, especially in New Mexico. Our average lateral length for the entire program will increase 20% next year to 9,700 feet. – Jack F. Harper, President and CFO, Concho Resources, Inc.We expect to continue to improve returns through the use of longer laterals and optimizing completion techniques. – Taylor L. Reid, Director, President, and COO, Oasis Petroleum, Inc.[T]here's quite a bit of room for 15,000 foot and even longer laterals in the Eagle Ford, particularly in the Western area. […] On the Permian, it's really driven by the existing well in the lease geometry. So there's areas where there's quite a few 15,000 foot wells. – Herbert Vogel, EVP – Operations, SM EnergyThe well mix in the Eagle Ford during the third quarter included a higher proportion of western acreage wells. While the pay is thinner in the west, there's less faulting, which allows for longer laterals. The longer laterals you can drill, the better the efficiencies to be gained during drilling and completions. – Ezra Y. Yacob, EVP of Exploration and Production, EOG Resources, Inc.When you break down the value of drilling long laterals, there are three areas to consider: development efficiency; well performance; and capital efficiency. [… Development efficiency] is our ability to maximize access to the reservoir with a single wellbore, allowing us to develop more acreage and resource from a much smaller footprint. […] It’s still early in the game when it comes to evaluating well performance for long laterals […] but none of our reviews have indicated any adverse impact of lateral length to well performance. […] Longer laterals can significantly reduce and even eliminate a number of costs in areas such as well pad and road construction, top-hole drilling, drilling and completion mobilizations, surface facilities and reduce cycle times. […] We are now at the point where the time to drill an additional 5,000 to 10,000 feet of lateral length may only be a couple of days requiring minimal incremental capital to being spent. – Jeffrey L. Ventura, President and CEO, Range Resources Corp.Longer laterals allow companies a host of advantages in terms of cost, while not necessarily negatively impacting performance. While longer laterals have been used in the industry for some time now, industry players have been more vocal about the possibilities created by drilling longer laterals. Lateral length has consistently increased over the years. For example, the average lateral length per well in West Virginia was 2,500 feet in 2007, compared to more than 7,000 feet in 2016. Although they are not the common place, many operators have reported laterals in the 12,000 to 13,000 feet range.Longer laterals lower costs for E&P companies which increases firms’ values with more revenue reaching the bottom line. Of course, there are limitations. Longer laterals generally require the consolidation of acreage ownership.Theme 2:  Oilfield Services Costs are Expected to Remain SteadyNew technology is increasing drilling speeds, drilling more consistent targets and lowering cost, all at the same time. Combined with cost reductions from local sand, water recycling and infrastructure projects, we are well on our way to achieving our stretch goal of reducing average cost 5% by year-end 2018. […] As we near the end of 2018, industry activity is slowing. Consequently, the service sector is experiencing a period of softness in the market. To take advantage of market conditions, we elected to secure some of our existing service providers through the fourth quarter for next year's program. This will capture favorable prices and sustain the operational continuity of these high-performing service providers into 2019. –  Lloyd W. Helms, Jr., COO, EOG Resources, Inc.My perspective long term on service costs is that what [oilfield service] companies really needed was utilization and now we're seeing that across the industry. A lot of them are pretty much fully utilized. And we still see a lot of expansion within our industry today. That's what's going on when you look broadly. So, these service companies are getting healthier all the time. And so, instead of just forcing prices up, continually getting more efficient and with more utilization, we think it could stay in about the same plane that it's in today. – Harold G. Hamm, CEO, Continental Resources, Inc.[W]ith respect to service costs, what we're seeing at least at this point is not a lot of move overall in the service costs. There are pockets of small things that we've seen bump up. We're optimistic on the pressure pumping side that it's going to be flat to down. And so we're not anticipating a big move in service costs for 2019, but we'll continue to monitor that. – Thomas B. Nusz, Director and CEO, Oasis Petroleum, Inc.In regions where drilling has ballooned, service providers are fully utilized. New players are entering these markets to deal with the expansion, which has helped keep prices steady.  In regions where there is less activity, some players are looking to lock in longer-term contracts to take advantage of lower costs. Regional market dynamics are different, though the impact on oilfield service costs appears to be the same.Increased activity means more revenue for E&P companies and oilfield service providers.  However, if oilfield service providers are able to command a higher price, E&P companies, valuations will suffer.   However, the majority of industry players believe that oilfield servicers will not continue to raise prices next year.Theme 3:  Infrastructure Issues PersistCosts have started to stabilize as the industry awaits new long haul pipe capacity before increasing activity […] the drilled but uncompleted backlog has reached new highs and will likely be a catalyst for activity once the new pipeline projects are completed. The Midland discount to Cushing's WTI has narrowed as capacity may come online sooner than previously expected. The futures curve indicates that Midland barrels will be priced at a premium WTI in 2020 and beyond. – Timothy A. Leach, Chairman & CEO, Concho Resources, Inc.Range has also seen significant, improved in-basin pricing compared to last year as the Appalachian gas market is benefiting from new pipeline capacity additions in both northeast and southwest Pennsylvania […] Over the next couple of years, we expect basis to remain strong in southwest Pennsylvania as additional pipelines are placed into service that will keep that portion of the basin free-flowing in the other markets. – Jeffrey L. Ventura, President and CEO, Range Resources Corp.Although we expect to see oil differentials to be wider for the fourth quarter, we retain our existing annual guidance, although likely in the upper half of the guidance range. The productivity of the Bakken is driving a significant expansion of basin takeaway. We expect to see the expansion of existing pipeline capacity as well as new pipelines entering the basin. Some of this capacity will come online in the next few months with a strong ramp-up through 2019 and entering 2020. On the gas side, we expect fourth quarter gas differentials to remain strong and reiterate our annual guidance. Looking forward to 2019, we expect a significant expansion of gas processing capacity in the Bakken, expanding as much as 50%. – John D. Hart, SVP, CFO, and Treasurer Continental Resources, Inc.If you look at the DAPL [Dakota Access Pipeline] and size that line until you know that you've got expansion capabilities there that it's going to be almost 40% more capacity that's going to come on with that eventually. That was from their initial projections to where that's going to go. So, that's a good bit of capacity right there that they'll be adding. And the next is new construction. Obviously […] there's a lot more oil to come out of the Bakken. And so, these new pipeline projects are going to pay off beautifully as time goes on. So, there's going to be a lot of brownfield, greenfield pipe to be added. – Harold G. Hamm, CEO, Continental Resources, Inc.As we’ve discussed, differentials between the standardized Cushing, Oklahoma prices and more localized Midland prices have been climbing for much of the year and remained wide until the end of the third quarter due in large part to capacity constraints from a lack of infrastructure in place to bring the product to market. As we see from these quotes, infrastructure issues aren’t confined solely to the Permian as many operators are dealing with in basin pricing differentials. Infrastructure issues are curbing the gains that are typically associated with rising prices and production. Theme 4:  Less Inventory in the Global Market Leads to Higher Prices and More VolatilityLooking at the macro environment, with the oil markets in a more balanced position, OECD commercial stocks have declined to below the 5 year rolling average. U.S. crude and product stocks, which account for around 40% of total OECD inventory, have reduced significantly over the last year to the middle of the range. With lower stock levels, the oil price remains volatile to any uncertainties, particularly around supply and geopolitics. Recent factors include the impact of U.S. sanctions on Iranian exports, supply disruption from Venezuela, together with production uncertainty from Libya and levels of spare capacity within OPEC. In summary, the oil price outlook has strengthened. We expect the oil market to remain volatile in the near term, characterized by lower stock levels and ongoing geopolitical factors. We expect current supply concerns to ease and continued robust demand growth to be matched by growth in the U.S. tight oil production and additional supply from non-OPEC countries. – Brian Gilvary, CFO, British PetroleumIt all comes back to supply and demand in the world, and we still see demand strong, about 1.5 million barrel to 1.8 million barrels of new oil. And on the supply side, hopefully, we can keep up with that. About 65% of that will come from the U.S. But if we go forward with the Iranian sanctions, as I anticipate, take another 800,000 barrels off the market, long term, things are going to get tight. And so, we expect it to be pretty close going forward through the end of the year. So, oil prices are going to be strong, and hopefully we'll have a cold winter to keep us there with natural gas. – Harold G. Hamm, CEO, Continental Resources, Inc.When there are supply constraints, price tends to go up. Despite increases in production in the United States, global oil production has experienced declines, causing global oil inventories to be drawn down amid strong demand. When there are lower levels of global inventory, there is less supply available to smooth volatility in the energy market.Higher crude prices should be a positive sign for the E&P industry. However, it must be viewed in the context of the global environment. With significant differentials experienced regionally, companies are not reaping the benefit of global price improvements. Further increased volatility makes it more difficult for companies to make accurate projections, which is particularly important given the size of the capital budgeting decisions required in the industry.
Four Key Takeaways from NARO 2018
Four Key Takeaways from NARO 2018
I recently attended the 38th Annual National Association of Royalty Owners (NARO) National Convention in Denver, Colorado. NARO is an organization that represents the interests of oil and gas royalty owners. The group promotes education and collaboration among its members for royalty owners to better understand their minerals, what goes into the royalty checks they receive, and the future of both production and legislation for the energy industry.The conference had educated speakers who talked on a broad range of topics, and the fast-paced and engaging lectures tied together nicely. Royalty owners learned about laws and court cases currently impacting other areas that could affect them in the future. They also learned about the future of production and consumption both in the U.S. and abroad. Additionally, speakers discussed how critical phrasing included (or not included) in their lease can have an impact on the royalties they receive and the importance of advocating on their own behalf. There were even more topics discussed, some of which could have their own blog posts devoted to them, but below are the key takeaways I drew from the conference.1. Regional Regulation and Legislation Doesn’t Stay RegionalA panel on Thursday discussed current legislative initiatives in various regions of the U.S., such as a court case in Pennsylvania (Briggs v. Southwestern Energy Prod. Co. 2017) currently dealing with the rule of capture. The rule of capture means that the first person to “capture” or extract oil from the ground is the owner of the resource.[caption id="attachment_22968" align="alignnone" width="404"]Source: Marcellus Drilling News[/caption] As illustrated in the above picture, sources of oil do not fall along property lines. Even if the oil comes from a common pool that extends to another property owner’s land, common law currently says the resource belongs to whoever can extract it. The court case in Pennsylvania is challenging this ruling, as it grapples with whether or not the “extraordinary means” associated with hydraulic fracturing could cause this means of production to be deemed trespassing. In other words, because fracking requires significantly more effort to extract the oil and could pose more environmental concerns, the impact it could cause to a neighbor’s property may mean that the extraction of oil that crosses property lines could be trespassing. Another big topic was Colorado’s Prop 112 that could increase setback measures to the detriment of royalty owners in the region. As it turns out, this Proposition was defeated 57% to 43%. Regardless of the outcome of these court cases and legislative initiatives, one thing became clear at the conference: rules and regulations, like drilling, have the ability to cross borders, whether they are state lines or property lines. 2. Net Exports Doesn’t Equal IndependenceDr. Mark Cronshaw is a natural resource economist with vast experience in the industry. He discussed different ways in which energy is produced and consumed in different plays and regions in the country as well as across the globe. Of particular note, he spoke on the notion of energy independence. We can view this through the following equation:Imports/(Exports) = Consumption - ProductionFor a long time, consumption has outpaced production, requiring imports to balance the equation. However, with consumption flat and increasing production, it is anticipated that production will surpass consumption in 2022, making the U.S. a net energy exporter. Keep in mind that becoming a net energy exporter does not necessarily equate to energy independence. While horizontal drilling and fracking have had a profound impact on U.S. production, exports of LNG, coal, gasoline, etc., are vital for the economy. The U.S. may produce more than it consumes, but trade is still necessary, meaning true “independence” is unlikely.3. What’s in Your Lease and Maybe More Importantly, What Isn’tJames Holmes, Esq. is an attorney in the Dallas area with diverse experience in oil and gas litigation, operation, and investment. He spoke on post-production deductions (PPDs), which is a continuous cause of concern for royalty owners. As we discussed a while back, PPDs are the expenses incurred in order to get the gas from the wellhead to market, such as gathering, compressing, processing, marketing, dehydrating, and transporting. Royalty owners benefit when their royalty percentage is applied to the ultimate price achieved when the gas is sold in the market. However, the oil and gas companies who bear the costs of making the product marketable would prefer to deduct the expenses they incur after extracting the gas. The laws governing the deductibility of post-production expenses are different depending on location.Compared to Texas trend states, Oklahoma trend states tend to be more favorable to royalty owners.Compared to Texas trend states, Oklahoma trend states tend to be more favorable to royalty owners, as they do not allow PPDs by default. Royalty owners are protected by common law in these states, whereas Texas trend states get their best protection from well-crafted lease agreements.If a lease in a Texas trend state uses the phrase “at the well,” that means the price on which the royalty percentage will be applied is the value of production when first taken out of the ground, or “at the well.” This is before it makes its way to a refiner, where the value will ultimately be higher. Even with clauses in a lease that specifically restrict PPDs, the phrase “at the well” can act like Pacman, gobbling up all helpful clauses and leaving royalty owners with less money on their royalty checks.The differences in the two trends and the states that follow each are enumerated in the table below: While Mr. Holmes emphasized handling these issues up front, particularly in Texas trend states, we learned from another speaker that sometimes implicit beats explicit. It seems obvious that a lease contract should have everything spelled out to protect the royalty owners, but John McArthur talked about implied covenants and how they can help. Implied covenants date back to a court case in 1905 that stated, “a covenant arising by necessary principle is as much a part of the contract—is as effectually a part of its term—as if it had been plainly expressed.” Just because something isn’t explicitly stated, doesn’t mean a producer can give royalty owners the short end of the stick. In general, they must act as a prudent operator and in good faith, along with the other main implied covenants listed below. 4. Royalty Owners Need to be Self AdvocatesMany royalty owners have reaped the benefits of consistent and long-lasting production. Mineral interests tend to be passed down from one generation to the next, which distances current owners from the process that was involved with negotiating the original lease. Economic and personal circumstances change, however, and this can leave royalty owners looking for a better lease arrangement.Frequently, leases are held by production meaning once an E&P company has drilled on the property, their lease will continue as long as they continue to produce. At a certain point, further production at a well may become disadvantageous to an operator if they cannot get a good enough price in the market. The location can also be depleted to the point that it is more expensive to produce than it would be in other areas.As the saying goes, “the squeaky wheel gets the oil.”Even if E&P companies don’t intend to produce any more, however, they are not motivated to terminate a lease. The end of a lease requires companies to incur expenses that do not produce revenue, like cleaning up and leaving the site. Additionally, when a company loses access to a reserve, it is removed from the company’s balance sheet. Although production of a reserve is not economical, removal from the balance sheet can impact a key metric used to assess a firm’s value in the marketplace.Therefore, the onus is on the royalty owner to terminate a lease, which can be done if there is not production in paying quantities (an implied covenant from Garcia v. King 1942). Additionally, royalty owners can also negotiate a new lease for new production in untapped zones, even if the acreage is leased, if the current operator is unable to reach these zones. As the saying goes, “the squeaky wheel gets the oil.”ConclusionThese takeaways are only some of the topics that were discussed at the NARO 2018 Convention, which provided an excellent platform for new attendees to become informed about the industry while still being beneficial to more experienced people who have been attending the conference for years. Going for the first time myself, I certainly learned about the issues that impact royalty owners most.In order to fully understand the operations of a business, an analyst must have knowledge of all aspects of the industry. Mercer Capital has over 20 years of experience valuing assets and companies in the oil and gas industry. We have valued companies and minority interests in companies servicing the E&P industry and assisted clients with various valuation and cash flow issues regarding royalty interests.  Contact one of our oil and gas professionals today to discuss your needs in confidence.
Royalty MLPs Are Devouring Mineral Assets To Fund Growing Investor Appetites
Royalty MLPs Are Devouring Mineral Assets To Fund Growing Investor Appetites
Last year Kimbell Royalty Partners went public in a $90 million IPO. In May of this year, Kimbell announced its acquisition of Haymaker Minerals for $404 million in cash and stock. To top it off, last month Kimbell priced a follow on public offering for $57 million. The Haymaker acquisition remains the largest corporate mineral acquisition so far this year and exemplifies the continuing growth in a relatively new niche of publicly traded MLPs: Royalty MLPs. With around $1 billion in corporate or mineral rights acquisitions so far this year by leading royalty MLPs and mineral aggregators Viper Energy Partners (VNOM), Kimbell (KRP) and Black Stone Minerals (BSM), the segment is consolidating fast in a historically opaque market. Going back decades, the royalty and mineral market has been dominated by smaller, private transactions oftentimes with information asymmetry in negotiations. The strategy for Kimbell and its peers: create liquidity and thus value in an attractive, yet relatively untapped marketplace.Royalty-focused MLPs and mineral aggregation has the potential to provide growth through acquisitions and distribution payments that public investors desire.Kimbell is the most recent entrant to the public market and is emblematic of the increasing capital stacks being deployed to buy up mineral rights all across the country. Private equity players such as Haymaker’s sponsors, KKR and Kayne Anderson Capital Advisors, LP have been growing participants in this space, especially after the drop in oil prices in 2014.On the investor side of the equation, individuals and institutions are looking for opportunities to be exposed to mineral plays and benefit from technological advances without taking operator risk. This is a primary attraction of these types of investments, and many of these investors’ best platform to do so is through public companies. More and more investors are looking to the mineral market to find investment growth. The emerging field of royalty-focused MLPs and mineral aggregation has the potential to provide this growth through acquisitions, as well as distribution payments that public investors desire. Kimbell’s acquisition of Haymaker is a good example of this.Royalty MLPs and aggregators (not to be confused with royalty trusts which do not actively aggregate minerals) have only recently entered the public investment sphere, although the oil and gas mineral market has been around since Colonel Drake begat the industry in 1859. Viper Energy Partners IPO’d in 2014, Black Stone Minerals followed in 2015 and Kimbell went public last year. Performance this year has generally been strong with Black Stone Minerals lagging. Viper Energy Partners has led the way this year in market value increase. Two factors appear to be pushing it ahead of its peers: (1) it is focused in the hot Permian Basin; and (2) about 39% of its acreage is operated by its sister company, Diamondback Energy (the “other” FANG stock).[caption id="attachment_22837" align="alignnone" width="683"]Source: Bloomberg[/caption] Growth aside, yields are the primary investment objective for these vehicles. Although potentially more volatile, the yields this year have been healthy as well. [caption id="attachment_22838" align="alignnone" width="640"]Source: Bloomberg[/caption] Alongside the acquisition, Kimbell converted its tax status from an MLP to a C Corp, a growing trend in light of the recent tax law changes. Now that the corporate tax rate is lower than the individual tax rate, the tax pass-through structure of an MLP does not provide the benefit it once did. Kimbell believes that this conversion will give the company access to a much broader base of investors and access to a more “liquid and attractive currency.” Tapping The Vast Mineral Royalty MarketKimbell estimates that the total oil and gas royalty mineral buying market is close to $500 billion, excluding overriding interests which are hybrid style mineral interests. These estimates suggest that public companies make up only about 2% of the total market or about $10 billion, with the two largest players, Black Stone Minerals and Viper Energy Partners, making up over $8 billion of that total market value. While the public minerals market is only made up of a handful of companies giving public investors a limited number of investment options, the private minerals market is highly fragmented. Organizations such as the National Association of Royalty Owners work to educate mineral owners, but they still only scratch the surface of the market. Small mineral aggregators can operate with a higher attention to acreage details. These small aggregators are able to focus more on negotiating directly with the landowners and handpick the acreage of their choosing. As a result, they expect higher yields than the public companies. While these yields are higher, the acreage is typically less diversified. Combined with their small size, these investments are inherently riskier than a larger, more diverse pool of assets, such as those held by public royalty trusts.Liquidity Discounts And Valuation OpportunityKimbell’s acquisition of Haymaker also demonstrates disconnect between the public and private markets and the discounts at which private LPs are valued. It appears that private royalty LPs simply do not have the same access to capital as the public MLPs or C Corps. This lack of access is potentially why KRP and Haymaker had distinctly different yields and why KRP was able to successfully negotiate such a highly accretive deal. Valuation professionals call this a liquidity or marketability discount. Mercer Capital sees this phenomenon quite often when valuing client’s privately held assets as demonstrated in the chart below, which highlights these “levels” of value. [caption id="attachment_22839" align="alignnone" width="640"]Source: Mercer Capital[/caption] Private equity investors and sponsors recognize this too. Haymaker’s sponsors most likely saw the potential behind the accretive mix of the two companies, which is why they were willing to accept roughly 50% of the purchase price in Kimbell shares. Not only was Kimbell public, its transition to a C Corp opened itself up to a broad array of inexpensive capital, less expensive than what Haymaker likely would have been able to find on its own. This access to cheaper capital makes it easier for Kimbell to grow through acquisitions and continue to increase returns and shareholder value.The Royalty Sector Is Just Warming UpThis is one of the biggest deals so far this year, but it may not be the last. Regardless of whether the MLP moniker sticks or they mostly become C Corp vehicles, the market remains vast, and public royalty aggregators are still at the front end of the consolidation trend. Oil and gas conferences regularly feature these firms now and they have become a regular part of the industry’s conversation. However, as more light shines on this market, efficiencies will grow and value will eventually get harder to find. In the meantime, there is opportunity to feed investors’ appetites and value seekers with oil and gas royalty minerals.Originally appeared on Forbes.com.
How to Interpret Breakeven Prices
How to Interpret Breakeven Prices
Before mid-2014, few investors took notice of efficiency-oriented metrics, instead focusing on stories of new oil discoveries and the development of new wells and new technologies.  Since the crash in oil prices, a new measure of success was brought to the forefront:  breakeven prices.Since the crash in oil prices, a new measure of success was brought to the forefront:  breakeven prices.Over the last couple of years, E&P companies have become more efficient, forced to create investor returns at $40 - $50/barrel oil.  Well productivity has improved as companies drilled longer laterals and used less proppant.  After the crash in oil prices, oilfield services companies lowered their prices to compete for limited work.  As oil prices recovered, the price of oilfield services was slow to catch up.  Additionally, companies have more capital discipline than they ever did at $100/barrel oil prices.Even as oil prices have started to recover, companies are showing lower breakeven costs than ever before.  As shown in the chart below, breakeven prices in the Midland Basin fell by 50% from $87 in January 2014 to $44 in September 2018. As more companies present this metric and more investors rely on it as an indication of performance, it becomes increasingly important to understand what it actually measures, and if breakeven prices can be compared consistently from company to company. What is a Breakeven Price?The Wall Street Journal stated, “At its simplest, the metric represents the oil price that a company needs to generate enough cash so it can cover its capital spending and dividend payouts.”  Most public E&P companies report breakeven costs in their investor presentations, oftentimes measuring themselves against peers.  However, these companies rarely explain how they develop these metrics.  Some companies, such as Chevron, don’t include covering dividends in this metric.  Additionally, some companies look at project-specific breakeven prices which don’t always cover all spending and dividends.Many analysts and investors, including our oil and gas team, track Bloomberg New Energy Finance for region specific breakeven prices.  Beginning in January 2014, Bloomberg began publishing monthly breakeven oil prices and breakeven natural gas prices for the following regions. According to Bloomberg, breakeven prices by region are sourced from BTU Analytics and provide: Average wellhead breakeven prices estimates for all wells turned to sales each month.  Well economics calculations use a 10% discount rate. Well life is assumed to be 240 months. Gathering, processing, compression, fractionation, and operating expenses are estimated for individual basins and plays.While somewhat helpful, this definition leaves a lot unexplained.   We talked to BTU Analytics so that we could better understand what it calculates.BTU Analytics’ data set includes 60,000 horizontal wells from 2013 to present across major basins in the continental U.S.  Their data is collected at the well level and calibrated with production data from state agencies and reconciled with overarching trends discussed by major regional operators.BTU’s breakeven measure on Bloomberg is a half-cycle breakeven price, meaning that all operating costs from drilling to completion of the well are accounted for. Additionally, the costs to keep the well operating such as taxes, royalties, and gathering and compression costs are included. However, what is not included in Bloomberg’s breakeven calculation is just as important.What is Not Included in Bloomberg’s Breakeven Prices?Notably, the Bloomberg Breakeven Price does not include wellhead differentials.  This means, that breakeven prices in the Permian are based off the WTI-Cushing benchmark, not off the regional hub which traded at as high of an $18 discount in August, according to pricing information from Bloomberg.As the Permian Basin struggles with bottlenecks, differentials have become exceedingly important to consider.  Although there are plans underway to address the growing need for infrastructure in the Permian Basin, adjusting Bloomberg’s breakeven pricing to account for differentials observed at the wellhead is necessary to accurately understand a regions breakeven price.Additionally, according to Matt Hagerty at BTU Analytics,These breakevens exclude acreage acquisition costs which can vary significantly between operators and even across acreage for a specific operator.Other ConsiderationsAs mentioned previously, it is often difficult to compare breakeven prices across companies.  Since BTU Analytics calculates each of these metrics, it would seem that they are more comparable across regions. But it is important to remember that these regional breakeven prices are averages and may not explain company or inter-regional dynamics.If we continue to rely on breakeven pricing, then it is pertinent that we better understand what is included in these calculations.In August of this year, breakeven prices in the Bakken fell below breakeven prices in the Permian.  While we do not doubt the credibility of this metric, it leads us to consider the actual observations that make up this average.  By mid-2016, the Bakken had only 22 operating rigs and even now has only 52 rigs as compared to 489 in the Permian.  It would be interesting to get a deeper look at the standard deviation of breakeven prices in regions such as the Bakken, as these regions may exhibit a much wider range of breakeven prices.Even at $70 oil, investors and analysts alike are still talking about breakeven pricing, suggesting that this metric has survived the downturn.  However, if we continue to rely on the metric, then it is pertinent that we better understand what is included in these calculations.Mercer Capital has significant experience valuing assets and companies in the energy industry. Our oil & gas valuations have been reviewed and relied on by buyers and sellers and Big 4 Auditors. These oil & gas related valuations have been utilized to support valuations for IRS Estate and Gift Tax, GAAP accounting, and litigation purposes. We have performed oil & gas valuations and associated oil & gas reserves domestically throughout the United States and in foreign countries. Contact a Mercer Capital professional today to discuss your valuation needs in confidence.
BP & Diamondback Mergers Set Q3 Tone For Upstream Producers
BP & Diamondback Mergers Set Q3 Tone For Upstream Producers
The third quarter just wrapped for upstream producers.  Stock performance has been volatile, infrastructure issues are lurking and the industry as a whole ended the quarter a notch above flat. However, approximately $21 billion in strategic acquisitions by BP and Diamondback Energy highlighted the continued optimism for the segment. BP’s merger looks particularly interesting as it focuses on the Eagle Ford while most investors have been looking to the Permian. BP’s earnings have yet to be reported, so stay tuned.BP’s Big DealBP brought on approximately 470,000 acres of rights and 90,000 barrels per day of current production.BP certainly wasn’t waiting for the industry’s current infrastructure issues to sort themselves out as they forged ahead with the biggest single upstream merger this year, a $10.5 billion acquisition of BHP Billiton. This is BP’s biggest acquisition in nearly 20 years. The primary assets acquired were spread across the Eagle Ford shale in South Texas, the Haynesville Shale in East Texas and to a lesser extent, the Permian Basin. Through this transaction, BP brought on approximately 470,000 acres of rights and 90,000 barrels per day of current production. BP was naturally enthusiastic about the deal, and after some review, this deal appears to have a lot of potential to create value for BP. Here’s why:This Is Not BP’s First Venture Into The Texas Shale PlaysBP dipped their toe into the Eagle Ford shale back in 2010, before they fully jumped into this deal.  Joining with local dry gas powerhouse Lewis Energy, BP bought at $4,000 to 5,000 per acre for joint venture rights on the dry gas window of the Eagle Ford shale. Over the course of the past few years, BP has more than doubled per-well production in the Eagle Ford by utilizing improved production techniques. This experience, particularly in that region, could serve BP’s shareholders well going forward.There’s Commodity Price UpsideBP based their return models on $55 oil and $2.75 gas.  As of the acquisition, oil prices were already in the mid-$60’s and closed around $75 this week. On the other hand, gas prices have been flat and returns have been driven by the cost side of the equation. Although only about 45% of the reserves purchased are liquids-based, it has the potential to boost returns and increase values.At First Glance, BP Does Not Appear To Have OverpaidWith over 80% of the assets weighted towards the lesser celebrated Eagle Ford and Haynesville plays, BP did not focus on the higher priced Permian Basin as much in this deal. Although the Permian’s stacked geology is superior, it is also more expensive. On a per net acre basis, BP paid just over $22,000 per acre.Diamondback Energy’s Big DealNot to be outdone, Diamondback Energy made two acquisitions within a week of each other that cost around $10.4 billion. Both transactions were in the Permian and were spread between the Delaware and Midland Basins. Both were similarly priced and are more oil and liquids heavy than BP’s acquisition, notable because margins for oil and liquids are generally much better than gas.The deals were notable because margins for oil and liquids are generally much better than gas.Diamondback’s larger deal was its purchase of Energen for  $9.2 billion, providing 179,000 acres and about 90,400 barrels per day of current production. Diamondback also purchased AJAX Resources for $1.2 billion, gaining over 25,000 acres and about 12,130 barrels per day of production. Although smaller, this deal was more focused on acreage located in the Midland Basin.Betting On SuccessBased on implied production multiples of other companies, deal pricing for both Diamondback mergers was generally in line with current implied values and creates one of the largest pure-play Permian producers. All three transactions appear to either be generally in line with implied public company market valuations in their respective regions.Overall, upstream indexes were muddled in the third quarter, although earnings reports could shift the sentiment. BP and Diamondback are betting big that future quarterly (and annual) performance will be better.The Bigger PictureGenerally, oil prices started and ended the quarter in almost the same place – around $73-$74 per barrel, but it took a circuitous route, dropping down to $65 in mid-August before climbing back.  West Texas, however, has been a different story. Differentials between the standardized Cushing, Oklahoma prices and more localized Midland prices have been climbing for much of the year and remained wide until the end of the third quarter. This gap has been created as a result of a supply traffic jam that has overwhelmed the Permian’s infrastructure. Production in Texas actually fell this summer due in large part to these issues, and this dynamic pervades beyond the Permian Basin. Appalachia and the Bakken have similar issues, although not discussed as often. Efforts are underway to alleviate these bottleneck issues in all of these areas, but it will continue to take time and capital.  This extends not only from public markets, but private equity as well. Have these issues impacted productivity or activity? So far, the answer is no.  Capex budgets, a harbinger of drilling plans, have continued to grow and be revised upward for many producers. Drilling and production figures continue to climb everywhere but West Texas. However, that is temporary. Noting the Permian’s drilled but uncompleted (“DUC”) well figure, the Permian’s effective inventory is waiting to be unleashed on the market. Could this be setting up strong earnings and production? One can only hope, and Diamondback and BP seem to think so. It appears the market may be transitioning from ascribing value on enthusiasm about potential shale production from undrilled reserves to realization of those reserves and more real dollars to show for it. Originally appeared on Forbes.com.
U.S. Energy and Private Equity
U.S. Energy and Private Equity

Show Me the Money

Private equity companies in the energy sector are positioned for an interesting opportunity. These companies have seen a surge of fundraising in recent years, leaving managers with large cash reserves or “dry powder” to be appropriately deployed.  Despite the large amount of cash available, these firms are having trouble finding places to invest resulting in a decline in PE activity in 2016-2018 with deal counts dropping for the second year in a row by 8%. However, investments could see a marked increase in energy in the last quarter of 2018 and into 2019 as there is a climate of high demand for return on investment and low supply of cash needed for capital expenditures in upstream oil companies.Oil and gas prices in 2018 have been steadily increasing in the midst of strong demand and constrained supply, and the U.S. energy sector is at the center of this focus. Forecasts from the International Energy Agency (IEA) show that the U.S. is expected to supply almost 60% of the demand growth over the next 5 years as conventional discoveries outside of the U.S. have hit historic lows since the early 1950s.Supply-Side ProblemsU.S. companies seem adequately poised to capture business in the swelling energy market, but the mechanics needed to supply this demand growth are turning out to be somewhat problematic. Upstream management teams that survived the oil crash in 2014 have had to cut costs aggressively in order to stay afloat, with capex spending plummeting nearly 45% between 2014-2016. These cost cuts, while necessary a few years ago, have largely continued into 2018 and conflict with the strong increase in spending that is needed to improve daily output to reach current demand. Morgan Stanley believes this output has to increase by 5.7 million barrels per day by 2020 in order to keep up. This level of increased production has only happened once since 1984.Another issue facing supply is the lack of new oil discoveries.  According to a study performed by Rystad Energy, discovered resources have fallen to an all-time low of around 7 billion barrels of oil equivalent in 2017. At current consumption rates, that is a replacement rate of around 11%, down from 50% in 2012. Not only are there fewer discoveries being made, but the sites found contain much less oil than prior discoveries.International AlleviationRussia and members of OPEC met in June and agreed to boost their collective output of oil production, amid U.S. sanctions on Iran, in order to help with the global shortfall and meet increased demand. Although there was no clear guidance on the increased output, the group has been tentatively aiming for an additional million barrels per day to overall production. World total oil supply has risen by approximately 680,000 barrels per day in July, but this was largely contributed by the Organization for Economic Cooperation and Development, a group of non-OPEC members that includes the U.S.In fact, from recent figures, Russia’s increased output amounted to only 20,000 barrels a day, and Saudi crude output actually decreased by 200,000 barrels a day.  The decline in the oil production in Iran and Saudi Arabia and lackluster production boosts from Russia are proving that any alleviation in oil prices will come later as prices continue to rise. While the IEA agrees that the Saudis can supply over 12 million barrels a day, there is little incentive to do so as fiscal breakeven figures for Saudi oil production provided by the IMF show nearly $88 per barrel. Why turn on the spigots if there is no profit to be made?Shortfalls in CapexThe U.S. has been ramping up production to make up for the underwhelming boost in international output. For the U.S. to continue to operate at the required level to reach demand, large investments in capex are necessary. From a Deloitte study in 2016, the industry needs a minimum investment of about $3 trillion from 2016-2020 to ensure its long-term sustainability even in the case of non-linear demand. When paired against the operating cash inflows and the required cash outflows of listed entities, there is a gap of roughly $750 billion to $2 trillion to cover payouts, debt repayments, and upstream capex. Even if companies have enough operating cash flow to fund capex on the lower levels, capex may not have the first call on available cash. Other balance sheet focuses and maintenance of reduced payouts may command higher priority for that cash. So where does the money come from to close the capex gap and supply the growing demand? This is where private capital and U.S. shale come into play.Private Equity FactorsAs the price of oil steadily increases, private equity backers for these upstream companies should see a similar uptick in new fundraising. Historically, rising prices equates to higher investment returns. The scenarios outlined above create an opportunity for energy investors that is not likely to be seen again for many years. Not only is the demand outlook in the investors’ favor, but the return per dollar invested is attractive as well due to innovations in efficiency from U.S. companies, as mentioned in a prior blog post, in areas like the Bakken. Well completion times have fallen by roughly half since 2013, which allowed for U.S. upstream companies to profit on $30 per barrel.The disconnect between rising prices and the relative performance of publicly traded energy companies creates an opportunity for private ventures to collect properties and assets and start drilling. Global private equity raised a record of $453 billion from investors in 2017 leaving it with more than $1 trillion to put into companies and new business ventures. Subsequently, this has resulted in the record amounts of dry powder in $1 billion+ funds. Coming into 2018, U.S. oil and gas PE funds alone were holding around $52 billion in dry powder, which can be seen in the PitchBook figure below. EnCap Investments was the largest player holding approximately $6.75 billion to be deployed in its Energy Capital Fund XI. Other industry giants such as Riverstone Holdings and Blackstone are holding around $3 billion and $2.7 billion, respectively. With such a large influx of new capital waiting to be deployed, the energy sector offers attractive opportunities to capitalize on the high level of demand coupled with rising prices and need for capital. ChallengesThe challenges typically facing energy-focused private equity companies are that they tend to be risk-averse. New discoveries and new drilling are capital intensive in both cash and time. PE firms tend to gravitate toward established shale plays and, as a consequence, pay a hefty premium for a “sure bet.”   As a result, one could argue the better use of capital would be making a long only bet on NYMEX and avoid the liabilities of owning an operating company.Additionally, the time horizons of these PE sponsors are often mismatched with the energy sector cycles. Cycles and manipulations by OPEC can occur over many years or even decades, while the typical time horizon for a PE sponsor is generally around 7 years.ConclusionPrivate equity firms are positioned to capture a rare investment opportunity in the U.S. energy sector.History has shown that there is a connection between higher oil prices and higher investment returns. In this relatively high price environment, private equity backers can supply the key ingredient of large capital injections to close the much-needed capex gap in U.S. upstream oil companies and enjoy the subsequent investment returns.We have assisted many clients with various valuation needs in the upstream oil and gas in North America and around the world.  Contact a Mercer Capital professional to discuss your needs in confidence and learn more about how we can help you succeed.
How to Value an Oil and Gas Mineral Royalty Interest
How to Value an Oil and Gas Mineral Royalty Interest
Well-informed buyers and sellers are critical to an efficient market for royalty interests because there is a specialized and relatively complex body of knowledge to consider in the transfer of these types of assets.Often called a net revenue interest (NRI), royalty interests do not bear the costs of production and only participate in the potential upside of a resource.  The value of a royalty interest, however, is often difficult to observe because they are typically closely held.  In addition, once discovered and drilled, the natural resources are physically depleted, resulting in a declining asset as opposed to a growing one.A lack of knowledge regarding the worth of a royalty interest can be very costly. A shrewd buyer may offer a bid far below the interest’s fair market value, opportunities for successful liquidity may be missed, or estate planning could be incorrectly implemented based on misunderstandings about value.Understanding how royalty interests are properly appraised will ensure that you maximize the value of your royalty, whenever and however you decide to transfer it.This blog post summarizes our whitepaper – providing an informative overview of the valuation of mineral royalty interests within the oil and gas industry.  While there are a myriad of factors (mostly out of a royalty holder’s control) impacting the economics of a royalty interest, this blog post focuses on valuation methodology.What Does the Valuation Process Entail?Valuation approaches refer to the basis upon which value is measured.There are three commonly accepted approaches to determining value:Asset-based ApproachMarket ApproachIncome Approach In the realm of business valuation, each approach incorporates procedures that may enhance awareness about specific economic attributes that may be relevant to determining the final value of a given entity. Ultimately, the concluded valuation will reflect consideration of one or more of these approaches (and perhaps several underlying methods) as being most indicative of value for the subject interest under consideration. However, due to fundamental structural differences between businesses and assets, the available valuation methodologies tend to be utilized differently when valuing royalty interests. 1The Asset-Based ApproachThe asset-based approach can be applied in different ways, but the general idea is that the enterprise value of a business is given by subtracting the market value of liabilities from the market value of assets. While the asset-based approach can be useful when valuing companies operating within the oil and gas industry, this approach is not typically employed to determine the value of a royalty interest.Oftentimes a mineral royalty owner purchased land which included the mineral rights and an allocation of surface vs mineral rights was not performed. Additionally, considerable time may have passed between the time the surface and mineral rights were purchased and the valuation date. Adding to the ambiguity of the cost basis of the asset, mineral royalty interests are often family assets that are handed down for generations. For this reason, the asset-approach is rarely used to determine the market value of mineral royalty interests unless the mineral rights were recently purchased.The Market ApproachThe market approach utilizes transaction pricing from guideline transaction data or valuation multiples from a group of publically held companies to determine the value of a privately held enterprise or asset. To develop an indication of mineral royalty interest value using the market approach, you can utilize data from market transactions of mineral interests in similar plays. This data can be derived from direct transactions of mineral royalty interests or from publically traded royalty trusts and partnerships.Direct comparable transactions of mineral royalty interests are often the best indication of fair market value.  However, the data with which to benchmark a subject mineral royalty interest against is often unavailable.  If it is available, a careful comparative analysis must be made.  Royalty trusts and partnerships hold various mineral royalty interests in wells operated by large exploration and production companies. Royalty trusts and partnerships tend to have very low, if any, operating expenses and can be an investment to provide exposure to oil and gas prices.Acquisition data from these trusts can be utilized to calculate valuation multiples on the subject royalty’s performance measure(s). This will often provide a meaningful indication of value as it takes into account industry factors (or at least the market participants’ perception of these factors) far more directly than the asset-based approach or income-based approach.Traditional oil and gas earnings multiples, such as EV/ EBITDAX, should not be used to calculate indication of values because royalty trusts do not have high operating costs and operational earnings margins are not a necessarily meaningful indication of performance for a royalty owner. Rather, a royalty trust's performance can be better understood by its distribution yield and potential for future revenue streams from new, undrilled wells.In many ways, this approach goes straight to the heart of value: a mineral royalty is worth what someone is willing to pay for it. However, the market approach is not a perfect method by any means for businesses or for mineral royalties.Royalty trust transaction data may not provide for a direct consideration of specific mineral royalty characteristics; it is imperative that the value conclusion be adjusted for differences in value level and in well economics, potential future drilling locations, among other factors. In any valuation, the more comparable the transactions are, the more meaningful the indication of value will be.The Income ApproachThe income approach can be applied in several different ways. Generally, such an approach is applied through the development of a cash flow or ongoing earnings figure and the application of a multiple to those earnings based on market returns. For mineral royalty interests, however, we oftentimes perform a discounted cash flow analysis. This approach allows for the consideration of characteristics specific to the subject mineral royalty, such as its well economics making it the most commonly used approach for mineral royalty interest valuations.To perform a royalty’s DCF analysis, production levels must be projected over the well’s useful life. Given that well production decreases at a decreasing rate, these projections can be calculated through deriving a decline rate from historical production. Revenue is a function of both production and price; as such, after developing a legitimate prediction of production volumes, analysts must predict future price values. The stream of revenue is then discounted back to present value using a discount rate that accounts for risk in the industry.Because revenue cash flows are the main driver of mineral royalty values, the income approach is the most reasonable and supportable valuation approach when determining the value of a mineral royalty interest.ConclusionA proper valuation of a mineral royalty interest will factor, to varying degrees, the indications of value developed utilizing the market-based and income-based approaches outlined above. A valuation, however, is much more than the calculations that result in the final answer. It is the underlying analysis of the mineral royalty and its unique characteristics that provide relevance and credibility to these calculations. This is why industry "rules-of-thumb" are dangerous to rely on in any meaningful transaction.Such "rules-of-thumb" fail to consider the specific characteristics of an interest and, as such, often fail to deliver insightful indications of value. A mineral royalty owner executing or planning a transition of ownership can enhance confidence in the decisions being made only through reliance on a complete and accurate valuation of the interest.Mercer Capital's Oil & Gas team has extensive experience valuing mineral royalty interests. Despite attempts to homogenize value through the use of simplistic rules of thumb, our experience is that each valuation is truly unique given the purpose for the valuation and the circumstances of the interest. We hope this information, which admittedly only scratches the surface, helps you better shop for royalty valuation services and understand valuation mechanics.We encourage you to extend your wealth planning dialogue to include valuation of any mineral interests because, sooner or later, a valuation is going to happen. Proactive planning and valuation services can alleviate the potential for a negative surprise that could complicate an already stressful time in your personal life.For more information or to discuss a valuation or transaction issue in confidence, do not hesitate to contact us at (901) 685-2120 or (214) 468-8400.End Note1 Treasury Regulations 1.611-2(d) asserts that the income approach will not be used if the value of a mineral property can be determined using the cost-approach (under the asset approach) or the market approach.  However, those circumstances are rare and not consistent with industry norms.  The income approach is most often employed to estimate the fair market value of mineral properties such as this.
EP Fourth Quarter 2018 Region Focus Appalachia
E&P Fourth Quarter 2018

Region Focus: Appalachia

Region Focus: Appalachia // As the new year begins, we turn our attention to the Appalachia region, and not by coincidence.
Refining Year-End 2018
Refining | Year-End 2018
The first half of 2018 provided positive momentum for refineries that had increased revenues and margin expansion in the second half of 2017.
Bakken Business
Bakken Business
Companies that have maintained a presence in the Bakken since the downturn in oil prices are beginning to reap the rewards of their patience. Rising oil prices have begat increases in production, and efficiencies gained in recent years have led to higher margins and increased production. As noted in last week’s post about transaction activity in the region, while the Permian Basin has received much of the attention recently, the Bakken certainly appears to be back in business.Efficient and Engaged OperatorsContinental Resources, Hess Corporation, and Whiting Petroleum Corporation are among the biggest players in the region. Whiting has rebounded with its stock price up 141% in the past twelve months, and their related royalty trust Whiting USA Trust II has also shown improved performance. Speaking of the decline in oil prices, Continental’s CEO Harold Hamm said recently, “We would never have gained the efficiencies that we have today without going through that.” This can be further illustrated by looking at breakeven prices in the Bakken, which have dropped from about $77 in September 2014 to below $39 per barrel in the third quarter of 2018, lower than those seen in Texas.Greg Hill, President and COO of Hess, recently emphasized the importance of the Bakken in their portfolio, saying about 43% of Hess’ capex budget would be devoted to the region over the next three years, targeting $1 billion annually.  He added that production constraints seen now in the Permian are very similar to those seen in the Bakken a few years ago.Infrastructure IssuesThe United States has long trailed other countries in terms of energy production.  With the leaps and bounds made in production, the question for industry executives and investors alike is now what? Increased production has led to the need for better infrastructure, a problem currently besetting the Permian basin in particular.  Extreme pricing differentials have occurred and plenty of natural gas coming off as a byproduct of oil production is being flared as a result.About 388 million cubic feet per day of natural gas was flared in June in North Dakota. Kinder Morgan, one of the largest energy infrastructure companies has proposed a $30 million natural gas pipeline that would alleviate 130 million cubic feet per day, with the project slated to begin construction mid-2019 and be finished by year-end, pending regulatory approval. Pipelines have been cast by industry executives as a safer alternative to rail transportation, though critics view this as a straw man argument. With the introduction of the Dakota Access pipeline (DAPL) in mid-2017, about half of the region's production (470,000 barrels per day of crude oil) will travel by this pipeline.  Despite the DAPL and other pipelines like the one proposed by Kinder Morgan, rail travel will still figure heavily into the equation as refiners on the East and West coast have low pipeline connectivity and much of the oil from other regions ends up with one of the numerous refiners in the Gulf of Mexico.The Minneapolis Fed recently outlined five other projects aimed at increasing gas processing capacity, including a $100 million expansion of a natural gas processing plant near Killdeer, ND. While companies seek high levels of production to take advantage of higher oil prices, these infrastructure constraints have a negative impact. Hamm emphasized this point saying, “Instead of just producing oil, we’re going to make sure we produce shareholder return.”Rig Counts and ProductionAccording to Baker Hughes, rig counts in North America declined 1.0% in the last three months, but increased 11.4% over the last twelve months. The Permian Basin has led the way with an increase of 26.2% in the past year, leading them to have 46.5% of total rigs. Rig counts peaked in the Bakken in May 2018, reaching heights unseen since 2015, but the Bakken continues to trail the Eagle Ford, Permian, and Appalachia regions. While rig counts aren’t ballooning in Bakken, this may be because operators like Continental are focusing on completing wells that have already been drilled (“DUCs”), a cheaper alternative to drilling new ones.Although oil production in the Bakken has increased 9.9% in the past year, it lagged the other four regions covered with the Permian setting the pace with a 26.6% increase. Natural gas production in the Bakken increased 17.2% in that same time, again trailing the Permian’s growth of 25.5%. Given the Bakken only produces a little over a third as much crude oil and a fifth of the natural gas, it will be interesting to see if the Permian can maintain its torrid pace or if capacity constraints will allow others to close the gap.Valuation ImplicationsBefore the crash in oil prices, the Bakken was booming with the highest EV/production multiples, also known as price per flowing barrel.  The Permian took center stage in 2017, but the Bakken is closing that gap as the Permian has come back to the pack a bit in 2018.ConclusionA rising tide raises all boats, and a rising oil price raises production in all regions. With the efficiencies gained, operators and investors in the Bakken and elsewhere will seek higher revenue and higher returns. Soaring production has led to unintended consequences such as flaring and inadequate infrastructure constraining capacity. Increasing this capacity will allow E&P Companies to increase returns and continue to ramp up production.We have assisted many clients with various valuation needs in the upstream oil and gas space in both conventional and unconventional plays in North America, and around the world.  Contact a Mercer Capital professional to discuss your needs in confidence and learn more about how we can help you succeed.
M&A in the Bakken
M&A in the Bakken

Under the Radar

Over the past year, followers of the oil and gas industry have taken note of the multitude of transactions occurring in the Permian Basin with large deal values and hefty multiples. But the price differential between WTI and other benchmarks has grown over the last few months, and some attention has moved from the Permian to other domestic shale plays.  The activity in other regions such as the Bakken was at one point slow (when compared to the Permian) causing the recent increase in production and the swapping of acreage to fly under the radar while many were focused on Texas.Transaction activity in the Bakken in 2017 marked the departure of a number of companies that were active in the play, such as Halcon Resources. At the end of 2017 and into 2018, the exodus from the Bakken to the Permian continued. Recently, the Bakken is being viewed as another viable option to the Permian Basin, which has seen a growing price differential due to insufficient infrastructure. This, and rising oil prices, has resulted in an increase in production in the region, leading to more transaction activity and inflows of capital.Recent Transactions in the BakkenDetails of recent transactions in the Bakken, including some comparative valuation metrics are shown below.Overall, the average deal size has decreased from twelve months ago when companies sold off large bundles of assets to clean up their balance sheets and survive in the low oil price environment. While deals today may be smaller in size, they are more strategic in nature.Whiting Acquires 65,000 Acres from OasisOne of the largest deals in the region over the last twelve months was Whiting Petroleum Corp. purchase of 65,000 acres from Oasis Petroleum Inc. in June for $283 million.  A Seeking Alpha contributor noted that this transaction is a “case of one company believing that it can achieve better results in an area that the other company considered lower quality acreage.” This is observed in Oasis’ acceptance of a lower than average transaction price per acre, and Whiting’s willingness to pay an above average price flowing barrel.US Energy Acquires 1,600 Acres from APEGOne of the smaller deals was US Energy Corp.’s acquisition of 1,600 acres from APEG Energy LP (a related party) for $18 million. US Energy and APEG Energy II, LP announced a strategic partnership in October of 2017 in a deleveraging transaction. APEG Energy II is one of Angelus Capital’s (a private equity firm headquartered in Austin, Texas) funds focused on acquiring domestic oil and gas assets. Since then, US Energy has focused on cleaning up its balance sheet to focus on producing oil assets. Recently, US Energy has been working to add assets that will immediately increase production in the Williston Basin and South Texas.US Energy expects their most recent transaction “will create additional opportunities for development and acreage swaps that would permit the company to continue consolidating its leasehold position in the area.”  US Energy paid $44,500 per flowing barrel, which is in line with average production multiples paid in the region but is somewhat lower than those observed last year. Deal values last year may have been based on the expectation that production would increase in the future, inflating current multiples. Now that production has picked back up in the Bakken, deal multiples appear to have normalized somewhat.Observed M&A Trends in the BakkenThe following are two good examples of transactions we are seeing in the region this year:Strategic Deals Between Regional OperatorsOne of the disadvantages of the Bakken, as compared to the Permian, is that it is an older play and many of its sweetest spots have already been drilled.  However, age is often equated with wisdom, and the significant experience of operators who have been in this region since the early 2000s gives them a competitive edge.  As Senior Beck, a senior director at Statas Advisors explained, “The Bakken’s maturity and production characteristics could lead to a growth in consolidation over the next few years.”Acquisitions of Property by Non-OperatorsAdditionally, the prominence of activity of non-operators in the Bakken has increased.  Private equity funds like Angelus Capital, single-family offices, and other providers of capital that see an opportunity in the Bakken are buying acreage and partnering with the best operators in order to realize superior returns on investment.Combining these trends, Northern Oil and Gas Inc. is a non-operator who aims to be the Bakken’s “natural consolidator.”  In July it completed its largest acquisition yet of 10,600 net acres for $100 million cash plus approximately $190 million of Northern Oil stock.  Northern Oil is relying upon the superior abilities of longtime regional operators and the trend towards consolidation. However, it is also an example of a non-operator who has become more prominent in the last year.The Bakken may have gone unnoticed for a couple years after the downturn in oil prices in 2014, but it may be rising back to prominence as increases in efficiency and cost reductions impress investors.We have assisted many clients with various valuation needs in the upstream oil and gas in North America and around the world.  In addition to our corporate valuation services, Mercer Capital provides investment banking and transaction advisory services to a broad range of public and private companies and financial institutions.  We have relevant experience working with companies in the oil and gas space and can leverage our historical valuation and investment banking experience to help you navigate a critical transaction, providing timely, accurate and reliable results.  Contact a Mercer Capital professional to discuss your needs in confidence.
M&A Activity in the Oilfield Service Sector
M&A Activity in the Oilfield Service Sector

From Surviving to Thriving

The oilfield service sector has recovered significantly since the crash in oil prices in mid-2014. As capex budgets have expanded, especially in the Permian Basin, demand for oilfield services such as drilling and pumping has increased. But what does this mean for transaction activity in the sector?The oilfield service industry was in consolidation mode over the last few years as smaller servicers struggled to survive in the low oil price environment which translated to lower day rates. Thus the relatively fewer transactions from 2015 through much of 2017 were mainly distressed sales.Now that oil prices have recovered, drilling activity has picked up, and day rates have increased, the reason for deals has changed. Rather than merging to survive, companies are acquiring in order to thrive. When discussing transactions in oilfield services sector over the past few years, maybe it should be called mergers THEN acquisitions.From Mid-2014 to Mid-2017 Oilfield Servicers Were SurvivingWhen oil prices fell, demand for oilfield services declined significantly. Despite the steep drop in prices, production did not fall through the floor because the cost of stopping and starting production can outweigh the loss incurred from lower oil prices. Still, the oilfield services sector felt the pain as many of its high value-added services occur at new sites rather than currently producing ones. With low oil prices, people became more judicious with how they deployed capital and new projects were largely tabled. Companies in financial duress were forced out of the market through consolidations and bankruptcy, as other sources of capital such as debt or additional equity offerings dried up due to the uncertainty surrounding future oil prices.M&A activity for the oilfield services sector was largely muted during the downturn in terms of both deal volume and value. Deal value would have been larger had Halliburton Company successfully completed its megamerger with its competitor Baker Hughes Inc. for an announced $34.6 billion. Instead of searching for synergies to boost revenue, companies were seeking to combine to eliminate duplicative expenses. In the case of Halliburton and Baker Hughes, the merger was expected to cut nearly $2 billion in annual costs according to the investor material seen below. Ultimately, this became the downfall of the deal as regulators denied it on grounds of decreased competition and reduced innovation on account of too much overlap in services. One year after the U.S. Justice Department blocked the deal due to anti-trust laws, General Electric bought a controlling interest (62.5%) in Baker Hughes. The combined entity resulting from GE’s investment caused GE’s combined revenue to surpass Halliburton, becoming the second largest company by revenue in the industry, trailing only Schlumberger. In early 2017, streamlining operations and eliminating expenses via consolidations was viewed as “the last big step to margin improvement,” according to the Coker Palmer Institutional. By the end of the year, there were 215 transactions in 2017, up 13% from 2016. As the tide began to turn, factors influencing transaction activity shifted from financial stress and cost efficiencies to economies of scale and enhanced offerings, particularly in digital technology. Oilfield Servicers Are Now ThrivingAs oil prices have recovered, up to $60 a barrel at the end of 2017 and peaking at $72 in May 2018, transaction activity has increased, but the reason for this increase in activity has changed. Companies that survived the downturn in oil prices stood to gain as rising oil prices aided margins and increased capex budgets for E&P companies. As break even prices became less of a concern for the industry, growth and innovation became the focus. Oilfield services companies depend on innovation to distinguish themselves in a highly fragmented industry, and when prices caused capital to flow out of the industry, companies were unable to fund the research and development necessary to innovate. Now, that trend is reversing with funding flowing into the sector to support growth and innovation. This is particularly important due to the capital-intensive nature of oilfield services, requiring significant investment to buy more equipment to meet growing demand.The following table shows some strategic transactions that have occurred thus far in 2018, as companies seek growth opportunities.  However, we are starting to see more investment from other sources.Private Equity Firms Are Suppling Growth CapitalAfter years of industry executives searching for diamonds in the rough, institutional investors have joined the fray. Over the last twelve months, there has been an influx of funds from private equity firms and hedge funds as growth, innovation, and fragmentation are all desirable traits for these investors.In March, Morgan Stanley Energy Partners (MSEP), the energy-focused private equity arm of Morgan Stanley Investment Management, completed an investment in Specialized Desanders, Inc. a Canadian-based oilfield equipment company that specializes in efficiently removing sands and other solids during the well flowback and production process.  MSEP’s investment seeks to accelerate growth in the U.S. market and expand their product offerings.In August, MSEP continued investing with its announcement of a partnership with Catalyst Energy Services. Proceeds from the investment will be used to buy state-of-the-art equipment which will allow the company to grow to meet increased demands for modern completion designs from E&P companies.Black Bay Energy Capital recently closed its inaugural fund with commitments of $224 million, exceeding their $200 million target.  This includes six investments in oilfield service companies exhibiting rapid growth that “improve the efficiency and cost-profile of oil & gas producers.”These investments made by MSEP and Black Bay show the three trends currently being exhibited in transactions in the oilfield services sector: niche product or specialty, innovative offering or technology, and growth. Whether it be strategic investors or private equity sponsors, acquisitions we are seeing now are largely spurring revenue growth instead of eliminating expenses.ConclusionTransaction volume in the oilfield services sector ebbed and flowed with oil prices over the last few years. On the way down, companies cut costs to survive, and mergers played an important role in increasing efficiencies in order to survive. On the way back up, companies sought capital to propel growth and fund innovation. As the market shifts from backwardation to contango and back again, Mercer Capital is here to help throughout all stages and economic environments.In addition to our corporate valuation services, Mercer Capital provides investment banking and transaction advisory services to a broad range of public and private companies and financial institutions.  We have relevant experience working with companies in the oil and gas space and can leverage our historical valuation and investment banking experience to help you navigate a critical transaction, providing timely, accurate and reliable results.Whether you are selling your business, acquiring another business or division, or have needs related to mergers, valuations, fairness opinions, and other transaction advisory needs, we can help.  Contact a Mercer Capital professional to discuss your needs in confidence.
Oilfield Service Valuations
Oilfield Service Valuations

Missing The Party Or Just Fashionably Late?

Latecomers are inevitable at parties. They skulk in at the end, missing out on most of the fun, food and games that everyone else has been enjoying. Yet, savvy socialites aim to arrive fashionably late, after the labor of getting the party going but still in time to enjoy the night.When it comes to valuations, are oilfield servicers late to the proverbial oil patch valuation gala or just in time to enjoy the recovery?Energy Sector Performance ImprovingSince oil prices fell off a cliff in the summer of 2014, most other energy sectors have been climbing back in various phases of recovery:E&P company valuations are recovering as companies have benefited from increases in production, escalating acreage values, lower breakeven prices and a recuperating oil price. This is especially true in the Permian Basin. In fact, activity and production in West Texas is growing so fast that existing pipelines and infrastructure struggle to keep up.Meanwhile, US refiners, feasting on the spread between Brent and WTI, continue to see valuation gains as well. Refineries are busting at the seams, with current utilizations over 98%, and acquisitions abound. Refinery performance appears sustainable for the short to intermediate term, but in the long run, capacity may be a limiting factor.Even midstream and pipeline valuations, after taking a beating through the end of 2015, are recovering nicely. The current West Texas hydrocarbon traffic jam presents a growth opportunity for this sector.Past Oilfield Service Performance Oilfield service providers, drillers, pumpers and equipment providers enabled E&P companies to make impressive efficiency leaps. So, where do they stand today? One lens through which to view things is the OSX index–a popular metric to track sector performance. Since mid-2014, the OSX index does not exactly portray an inspiring comeback by oilfield service companies. In fact, looking at the index alone might lead one to think oilfield servicers have not even received an invitation to this reputed party, much less arrived. Earnings sunk in 2015 and bottomed out in 2016 as a result of producers cutting drilling and completion costs. Balance sheets went through significant write downs, impairments and asset sales. Not surprisingly, bankruptcies for the sector peaked in 2016 with 72 oilfield service companies filing for bankruptcy, up from 39 the year prior. It was a mess, to say the least. Oh, but how things have changed in the past two years. Current Oilfield Service Performance Higher oil prices, coupled with lower breakeven costs for producers, are making drillers, completers and a host of other servicers busier than a gopher on a golf course. Capex budgets for E&P companies, known as lead indicators for drillers and contractors, have taken off. While dormant for decades, proven drilling locations (PUDs) now multiply in light of new fracking technologies and their resultant economics. Drilling and completion budgets are not only growing for operators, but an increasing percentage of those budgets are being spent in West Texas.Utilization Rates and Day RatesSpecifically, as it pertains to oilfield service companies, two key metrics, utilization rates and day rates, have begun to align in a way not seen since 2014.By the end of 2017, utilization rates for certain rigs averaged around 80%, or almost fully utilized considering necessary downtime and transition from one drilling location to another. However, things are currently so hot that utilization rates have now risen to over 90%.Day rates, the measure of how much a servicer can charge an operator for every day the rig is operating, have been slower to increase. Increases in day rates started to move upward in the last six months or so. Estimates suggest that day rates will notch up 10-15% by the end of 2018. This is good news for oilfield servicers.Valuation TurnaroundNow that utilization rates and day rates are both trending upward, valuations should logically respond and by certain aspects, they are.Take, for example, a selection of guideline company groups: onshore drillers and pressure pumpers (fracking companies). One way to observe the degree of relative value changes is to look at enterprise value (sans cash) relative to total book value of net invested capital (debt and equity) held by the company or “BVIC”. Any multiple over 1.0x indicates valuations above what net capital investors have placed into the firm, which for drillers and pumpers is a notable threshold. While 2016 was an anomaly (due to the significant balance sheet changes mentioned above), the rest of the time frame shows a clear trend. In 2015, with a multiple below 1.0x, investors didn’t expect to get an adequate return on the capital deployed at these companies. However, as 2017 came to a close and now moving into mid-2018, that trend has reversed. All except Parker Drilling have met or exceeded their 2014 multiples, and the average is around 1.2x. This suggests that the market is recognizing intangible value again for assets such as developed technology, customer relationships, trade names and goodwill. For pressure pumping and fracking concentrated businesses, which are more directly tied into the value expansion in the oil patch, the trend is clear. Intangible asset valuations have grown even faster, more heavily weighted towards pumpers’ developed technology that is driving demand for these companies’ services. However, the recent infrastructure logjam in West Texas has pushed multiples lower.  Nonetheless, the market has been recognizing the value contributions of these companies. ConclusionTo be clear, nearly all of these companies had to shrink their balance sheets to get these multiples in line. This explains why some of the data is not as meaningful in 2016. However, it appears that’s what was necessary in light of the shift in the market.Overall rig counts have shifted downward since 2014 and are currently nowhere near prior levels, thereby forcing these companies to shed assets in recent years. That’s the price of market efficiency. However, with those challenges no longer weighing them down, some oilfield services companies may be finally arriving at the valuation party.Remember the initial question posed in this post: When it comes to valuations, are oilfield servicers late to the proverbial oil patch valuation gala or just in time to enjoy the recovery? Maybe the question to ask is: How much time is left before the celebration ends?Originally appeared on Forbes.com.
Bryce Erickson is a Contributor to Forbes.com
Bryce Erickson is a Contributor to Forbes.com
Based upon the content in this blog, representatives from Forbes.com reached out to Bryce Erickson, ASA, MRICS with an invitation to become a contributor to Forbes.com in their Energy section.Read Bryce’s first contribution: "Oilfield Service Valuations: Missing the Party or Just Fashionably Late?"Bryce leads Mercer Capital’s Oil & Gas Industry team. He has more than 20 years of oil & gas industry and valuation experience both in the U.S. and internationally.On Forbes.com, Bryce will focus on industry developments, economic trends, and the impact on valuation for companies operating in the Permian, Eagle Ford, Bakken, and Marcellus & Utica regions, in addition to topics related to mineral rights and royalty owners.Bryce provides oil & gas companies, midstream operators, and oilfield servicers, as well as mineral & royalty owners with corporate valuation, asset valuation, litigation support, transaction & due diligence advisory, and other related services.
Public Royalty Trusts (Part II)
Public Royalty Trusts (Part II)

Can Revenue Interests Still Benefit from Capital Appreciation?

In a recent post, we explored the ins and outs of MV Oil Trust. We analyzed the underlying net profit interests it holds, the underlying properties of the trust, and the rights of unitholders including their rights during termination of the trust. This week, we will look into how these play into the composition of the MV Oil Trust’s stock price, and the balance struck between investor’s current return in the form of dividends and potential for returns from capital appreciation.Tradeoff Between Current and Future ReturnsThere is a natural friction between distributions of earnings versus reinvestment for growth. Young and growing companies tend to reinvest their earnings to fund future growth opportunities. Investors in such companies, therefore, have to be willing to forego upfront returns in hope of realizing greater returns down the road. Investors in mature companies, however, generally expect to receive dividends as a return on their investment because these companies typically have fewer opportunities for growth.Composition of Stock PriceWhile public royalty trusts are equity securities by name, they have unique characteristics that differentiate them from many equity securities. Investors typically take on exposure to equity securities for two basic reasons: receipt of cash dividends and anticipation of capital appreciation. Cash dividends are residual earnings of the Company paid to the investor at the discretion of management, and these are current returns. Capital appreciation occurs through the sale of shares at a price higher than what the investor paid, and this is a future return.Investors in public royalty trusts are typically seeking dividends. Because the investment is ultimately in a depleting asset (oil or gas reserves), capital (and therefore stock price) is expected to depreciate to zero in the long run. Many public royalty trusts, including MV Oil Trust, are restricted from acquiring more assets or interests, and most earnings are required to be paid out. These restrictions are similar to another type of trust: Real Estate Investment Trusts (REITs). Because most earnings must be distributed, dividends paid to investors would not appear to be constrained by the discretion of management, and therefore some investors consider investments in trusts to be less risky. This is not necessarily the case for royalty trusts, however, because the source of income is less stable and the ultimate level of cash distributions is dependent on the level of production set by the operator (who is not always associated with the management of the trust). Thus, investments in royalty trusts may be viewed to be riskier than investments in REITs due to this unique control structure.Let’s Get TheoreticalAccording to the dividend discount model, the intrinsic value of a stock is the expected value of future dividends, discounted back to the present at an appropriate discount rate. Forecasts of dividends are typically estimated for anywhere between 3-15 years, or until a time where future dividends will grow/decline at a stable rate. At this point, a terminal value is added, which accounts for all remaining value after earnings have stabilized, which is discounted back to the present. In the case of public royalty trusts, units of the trusts tend to hold declining intrinsic value. That is, their intrinsic value will drop to zero upon expiration of the trust agreement. This would imply no terminal value, save for the potential liquidation of assets. In the case of MV Oil, the trust will distribute the net proceeds from the sale of assets upon dissolution of the trust, so there will be a terminal value that accounts for future production remaining from the underlying properties. When a dividend is paid, the market value of the trust should decrease by the amount of the dividend. As an example, imagine a public royalty trust paying quarterly distributions of about 50¢ per share for the next two years prior to termination with a terminal value of zero. If the stock price is a little under $4.00, after accounting for the present value of these distributions, the stock price should decline by 50¢ upon receipt of the first dividend, because the stock at that point will only be worth the remaining seven distributions. Capital Expenditures ConstraintsMV Oil Trust is restricted from acquiring other properties or interests, but it will still spend money on drilling new wells on their established sites, as well as covering maintenance of currently producing wells. These maintenance expenditures may affect the quantity of proved reserves that can be economically produced. Because MV Partners has agreed to limit the amount of capital expenditures in a given year, they may choose to delay certain capital projects into the next year when the budget allows. If operators do not implement required maintenance projects when warranted, the future rate of production decline of proved reserves may be higher than the rate currently expected. So, the capital expenditure limit, implemented as a protection for unitholders, could actually have a deleterious effect.Is There Any Room for Capital Appreciation?The question then becomes, can revenue interests in an oil and gas royalty experience capital appreciation? With the requirement to pay out substantially all of its earnings as distributions and restriction on acquiring new properties or interests, it would appear that capital appreciation is unlikely. However, as we have seen in the public market, commodity price expectations can vary and change significantly in a relatively short time period. In the case of MV Oil Trust, the rebound in commodity prices and subsequent return to distributions caused the significant increase in unit price over the past two years. Even though investors are purchasing the right to obtain future distributions, buying low and selling high on the units is possible, as with any investment. For public royalty trusts, investors would need to be able to anticipate shifts in either production or price.Drill Baby Drill?Capital appreciation for royalties is not limited to the potential upside from increasing crude and natural gas prices. MV Oil Trust has drilled new wells in each of the past three years, providing investors with an upside not seen in all royalty trusts. Additional wells increase capacity which will increase royalty revenue and therefore increase future dividends, thus raising the value of the trust. Proved undeveloped reserves (PUDs) present an upside to unitholders, and drilling wells is the next step in developing these reserves, so they can eventually be produced and sold.Many royalty trusts either have not recently drilled any new wells or they do not have any proved reserves that are left undeveloped. This includes Permian Basin Royalty Trust, Mesa Royalty Trust, Sabine Royalty Trust, VOC Energy Trust, San Juan Basin Royalty Trust, and Pacific Oil Trust.Some trusts originally had upside from wells that they were contractually obligated to drill in an “Area of Mutual Interest (AMI)” when the trust was started. This includes the three SandRidge trusts, which we discussed in a recent post. Chesapeake Granite Wash Trust and ECA Marcellus Trust I also agreed to drill wells in an AMI, neither have drilled any further wells after fulfilling this requirement. Thus investors in these trusts will likely only realize capital appreciation if crude prices unexpectedly increase and stabilize at this higher price.Hugoton Royalty Trust and Cross Timbers Royalty Trust have had little to no drilling in recent years, but both benefit from having XTO Energy as an operator, who has indicated plans to drill new wells that will benefit each of these trusts.Enduro Royalty Trust, MV Oil Trust, BP Prudhoe Bay Royalty Trust, and Whiting USA Trust II have all had drilling in recent years. MV Oil Trust’s undeveloped reserves represent 14% of proved reserves, representing potential upside from future drilling. Prudhoe Bay has drilled over 100 wells in the past three years, and it has experienced the third highest 2-year return. Whiting USA Trust II has significant undeveloped acreage in the Permian, which likely plays a role in its superior 2-year return for investors.The remaining four mineral partnerships are either C Corporations or MLPs. As discussed recently, they are designed to gather assets and grow through acquisitions. Because they are not structured as trusts, they are not required to distribute a substantial amount of their earnings.ConclusionEven when royalty trusts are prohibited from acquiring more assets, investors can realize capital appreciation if oil price expectations change, the operator of the underlying assets drill more wells and/ or increase their operating efficiency, or if management expedites distributions.While the value of the underlying asset of royalty trusts (royalty interests) are expected to decline over time, there is still an opportunity for capital appreciation with commodity price changes or additional drilling. Ultimately, declining revenue distributions for private owners of royalty interests typically do not benefit from capital appreciation, but selling at the opportune time can effectively function as capital appreciation.We have assisted many clients with various valuation and cash flow questions regarding royalty interests. Contact Mercer Capital to discuss your needs in confidence and learn more about how we can help you succeed.
A Review of M&A Activity in the Downstream Oil & Gas Space
A Review of M&A Activity in the Downstream Oil & Gas Space

Nesting Dolls of Refinery Acquisitions

On April 30, 2018, Marathon Petroleum announced its acquisition of the newly formed Andeavor making Marathon the largest refiner in the U.S. (by capacity) and one of the top five refiners in the world.  The merger is moving into its final stages, and Marathon’s CEO is positive about the combination of the two well situated companies.In this post, we analyze the recent acquisition history of Western Refining, Tesoro, and Marathon, which has started to look somewhat like nesting dolls of acquisitions. For an industry that has had sluggish M&A activity in the last couple years, this line of acquisitions seems to hint to a possible trend of consolidation.  Domestic oil production has increased significantly over the last couple years.  Even though export bans on crude oil were lifted a couple years ago, overall, there is more crude oil in the U.S. that needs to be refined.  According to the EIA, U.S. refining capacity is “virtually unchanged from 2017 to 2018.”  Domestic refineries are now running at average utilization figures of 90%, as compared to the IEA’s global average of 70%.  Building a new refinery takes time and money and has significant regulatory hurdles; thus U.S. refiners appear to be combining in order to increase efficiencies and meet the higher demand for their services as a result of the recent increase in domestic crude oil production. Recent Acquisition HistoryThe table below shows metrics from the line of acquisitions leading up to Marathon’s acquisition of Andeavor, along with other recent transactions in the downstream space for comparison.Western Refining’s Acquisition of Northern Tier for $1.6 BillionIn late 2015, Western Refining bought all remaining shares of Northern Tier Refining, not already owned by Western Refining and its subsidiaries, for $1.6 billon. (Western Refining previously bought a controlling interest in Northern Tier for $775 million in 2013.) The resulting company had three refineries in Gallup, NM; St Paul, MN; and El Paso, TX.Western Refining paid 5.3x EBITDA for the remaining minority position in Northern Tier.  Some analysts such as Albert Alfonso, originally believed that the deal was undervalued.  While the deal multiples were quite a bit lower than the multiples observed in the downstream space at the time, it is important to consider the premiums paid for acquisitions of control versus the price paid in this acquisition of a minority position by a company that previously paid for control.  For comparison purposes, this transaction is more similar to Delek’s 2017 acquisition of the remaining shares of Alon at 5.9x EBITDA for a minority stake.Tesoro’s Acquisition of Western Refining for $6.4 BillionIn November 2016, Western Refining and Tesoro Corporation merged to form Andeavor. Tesoro bought Western Refining for 10.6x EBITDA and 80% of revenues, which at the time was in line with the earnings multiples observed in Delek’s acquisition of shares of Alon U.S. Energy for 11.0x EBITDA. (Through this transaction, Delek gained control of the entity of which they originally owned 48%.)  The newly formed Andeavor was the fourth largest independent refiner in the U.S.Tesoro had refineries in California, Washington, Alaska, Utah, and North Dakota. The addition of Western Frontier expanded their presence by adding refining locations in Texas, New Mexico, and Minnesota.Western Refining shareholders received either 0.4350 Tesoro shares, or $37.30 in cash per share. As compared to the previous day’s closing price of Western Refining, the shareholders received a 22.3% premium, according to a Fortune article about the transaction.  In order to prevent dilution from the offering of additional shares, Tesoro announced it would increase its buyback program by $1 billion.  The deal was expected to create between $350 and $425 million in synergies to be realized in the first two years of their combination.In addition to expanded refining capacity, the combined companies had over 3,000 retail stations.Marathon’s Acquisition of Andeavor for $23.3 Billion (Enterprise Value of $35.6 Billion)Marathon Petroleum is expected to close on its acquisition, newly formed Andeavor for 12.7x EBITDA, which shows a slight premium to the few transactions observed in the refining space lately.  Andeavor shareholders will have the option to choose 1.87 shares of MPC stock, or $152.27 in cash per share. This represents a 25% premium to the closing price the day before the transaction was announced.   In order to prevent dilution from the issuance of additional MPC shares, Marathon’s Board approved $5 billion repurchase authorization.The two companies were largely located in different parts of the country as shown in the map below. Andeavor Chairman and CEO Greg Goff (who will become Executive Vice Chairman at MPC) explained,“Look at the map of the two companies and the way they are positioned geographically in the United States and you come to the conclusion that this is a great opportunity to be able to bring the companies together.”The map below shows the locations of both Marathon and Andeavor’s refineries. Marathon had six refineries in the eastern half of the U.S. and Andeavor had 10 refineries in the western U.S. and Alaska.  The combined company will have approximately 15% of total fuel making ability in the U.S. Additionally, the combined companies have over 7,800 branded fuel stations. Immediately Accretive DealAccretive deals add more value than they cost, either over time or immediately.  The Marathon and Andeavor deal is expected to be immediately accretive to earnings per share; meaning the price paid by Marathon is lower than the immediate expected boost in earnings per share post-acquisition.The deal is expected to create significant synergies resulting in around $1 billion over the first three years.  These synergies will come as a result of stronger purchasing power, system optimizations, procurement efficiencies, leveraging of assets, and retail network efficiencies. Additionally, according to Marathon’s Chairman and CEO, Gary Heminger, thinks that the potential synergies could be even greater than the estimated $1 billion.  However, that remains to be seen.  Many analysts are sometimes skeptical of synergies due to their somewhat abstract nature.Did Marathon Pay Too Much?Marathon’s acquisition of Andeavor comes at a time when U.S. refineries are positioned to benefit from the increase in domestic production of oil and gas. Many refineries that purchase WTI crude are currently benefitting from the discount of WTI to Brent, which has lowered their costs of sales as refined product prices are still increasing.  Refineries margins have increased 8% worldwide and almost 25% in the U.S. Midwest year over year according to British Petroleum’s Refiner Marker Margins and crack spreads have increased as shown in the graph below. Management of both companies seem positive regarding the deal and there seems to be little reason to believe that the deal would face any resistance from regulators as there was is little overlap in the locations of the refiners.  However, investors of MPC could ask if MPC paid too much? Stock buybacks are generally a signal to investors that the Company views its own stock as a good investment.  Additionally, management will generally not buy back shares if they think the stock is currently overpriced.  Marathon’s announcement of a buyback should somewhat ease investors’ concerns. ConclusionIt is hard to pinpoint the root cause of the recent consolidation activity in the downstream oil and gas space. The pressure of RIN expenses on smaller refineries that do not have the capacity to blend their renewable fuels could be one cause of consolidation.  The immediate need for more operating capacity as U.S. oil production has increased might be pressuring larger refiners to purchase rather than build additional capacity. Additionally, the recent tumult of the global trade environment adds an additional layer of uncertainty for U.S. refineries whose main export market is Mexico.In addition to our corporate valuation services, Mercer Capital provides investment banking and transaction advisory services to a broad range of public and private companies and financial institutions.  We have relevant experience working with companies in the oil and gas space and can leverage our historical valuation and investment banking experience to help you navigate a critical transaction, providing timely, accurate and reliable results.Whether you are selling your business, acquiring another business or division, or have needs related to mergers, valuations, fairness opinions, and other transaction advisory needs, we can help.  Contact a Mercer Capital professional to discuss your needs in confidence.
Public Royalty Trusts (Part I)
Public Royalty Trusts (Part I)

Can Revenue Interests Benefit from Capital Appreciation?

In previous posts, we have discussed the relationship between public royalty trusts and their market pricing implications to royalty owners.  Many publicly traded trusts have a fixed number of wells, so the value comes from declining distributions.  Some of the trusts have wells that have not been drilled, which represent upside potential for investors. The future growth and outlook potential for each type of publicly traded trust is significantly different and a potential investor would want to know the details. The same is true for a privately held royalty interest.In this post, we will explore the subject characteristics of MV Oil Trust.  This will serve as a primer for a subsequent post in which we will look further into the composition of its stock price in order to better understand investors’ ability to achieve returns through distributions and capital appreciation.Market Observations1Over the previous two years, the performance of the 21 publicly traded royalty trusts has varied widely.  The table below shows the performance and other key metrics of the 21 main oil and gas-focused partnerships that are publicly traded, as of July 12, 2018. Clearly, there were some winners and losers, with more winners than losers. Of the winners, Whiting USA Trust II (WHZT) (+243%), discussed in a recent blog post, has had the highest price return.  The focus of this blog post will be MV Oil Trust (MVO) (+99%), whose market value has nearly doubled in the past two years. For comparison, the chart below shows the two-year returns from MV Oil Trust, Crude Oil, Natural Gas, and the S&P 500.   Over the last five years, there has been significant correlation between MVO’s share price and the price of crude oil (93.3%) and less correlation with the price natural gas (74.6%). MV Oil TrustOn January 24, 2007, MV Partners and MV Oil Trust completed an IPO.  MV Oil Trust holds net profits interests, which represents the right to receive 80% of the net proceeds from all of MV Partners’ interests in oil and natural gas properties located in the Mid-Continent region in the states of Kansas and Colorado.  As of December 31, 2017, the underlying properties produced predominantly oil (99% of production) from approximately 900 wells.MV Partners is the designated operator for these properties, but they are currently being operated on a contract basis by two affiliated companies, Vess Oil Corporation and Murfin Drilling Company, Inc.  MV Partners pays an overhead fee to operate the underlying properties, which is based on a monthly charge per active operated well ($3.1 million average in the past three years).It is important to note that a majority (76% in the past two years) of the oil produced from the underlying properties was sold to a related entity, “MV Purchasing.”  The price received is based on a recent NYMEX price, reduced for differentials based on location and oil quality.  In 2017, the average differential between the benchmark and the price realized by MV Oil Trust was just under $5 per barrel.  MV Oil Trust is extremely dependent on MV Partners and its related entities.  Where this private company experiences difficulties, the trust would undoubtedly suffer, both in terms of production level and the amount it could sell.What is a Net Profit Interest?Trust unitholders receive 80% of the NET proceeds.  “Gross proceeds” are the aggregate amount received by MV Partners from sales of crude oil, natural gas, and NGLs produced from the underlying properties. This does not include consideration for sale of any underlying properties by MV Partners, nor does it include any of the oil or gas lost in the production or marketing process. “Net proceeds” represents gross proceeds, less:Payments to mineral owners or landowners, such as royalties and expenses for renewals or extensions of leases;Any taxes paid by the owner of an underlying property;Costs paid by an owner of the underlying properties under any joint operating agreement;All exploration and drilling expenses;Costs or charges associated with gathering, treating and processing oil, natural gas and natural gas liquids;Any overhead charges, including the overhead fee payable by MV Partners to Vess Oil and Murfin Drilling; andAmounts reserved for approved capital expenditure projects (up to $1 million per 12 months), including well drilling, recompletion and workover costs. Unitholders are entitled to quarterly cash distributions of substantially all of the trusts quarterly cash receipts, less the trust’s expenses and any cash the trustee decides to hold as a reserve against future expenses.  As noted above, the trust’s share price is highly correlated with the price of oil because the trust is ultimately as valuable as the distributions it makes.Termination of the TrustUnlike a traditional royalty interest that continues into perpetuity, a net profit interest in MV Oil Trust will terminate on the later of:June 30, 2026, orThe time when 14.4 MMBoe have been produced and sold (equivalent to 11.5 MMBoe in respect of the trust’s right to receive 80% of the net proceeds from the underlying properties) As of December 31, 2017, the trust had received payment for approximately 8.0 MMBoe of the 11.5 MMBoe interest, or about 70% of the termination threshold. The trust will dissolve prior to its termination if it sells the net profit interest or if annual gross proceeds attributable to the net profits interest are less than $1 million for each of two consecutive years.  Upon dissolution, the trustee would then sell all of the trust’s assets and distribute the net proceeds of the sale to the trust unitholders.Underlying PropertiesThe underlying properties are in Kansas and Colorado, or the Mid-Continent region, which is a mature producing region.  Most of the production consists of desirable light crude oil.  Most of the producing wells are relatively shallow, ranging from 600 to 4,500 feet, and many are completed to multiple producing zones.  In general, the producing wells have stable production profiles with total projected economic lives over 50 years and an estimated average annual decline rate of 8.6% over the next 20 years.  This extended shelf life is attractive for unitholders of the trust because even though the trust is expected to terminate, the unharvested production capacity can still be sold.As seen in the tables below, the majority of proved reserves are developed, oil reserves.  Also, the majority of acreage is in either the El Dorado or Northwest Kansas area. The majority of the net operated wells are oil wells; however, there are also some non-operated oil wells.  In the past three years, each Trust has added to its well count by drilling additional development wells.  Most of these occurred in 2016 when 7.6 net wells were drilled.  These additional wells increase production capacity and thus potential for future distributions. Other Rights of Trust Unit HoldersNet proceeds received by unitholders exclude the sale of underlying properties, but this does not prevent the sale of assets.  Unitholders will be compensated if a sale occurs.  Further, the trust is only able to release the net profits interest associated with a lease that accounts for up to 0.25% of total production for the past 12 months without consent of unitholders.  This sale also cannot exceed a fair market value of $500,000.  This protects unitholders from having significant assets sold in any given year, which would decrease the level of future production.As mentioned earlier, capital expenditures are currently limited to $1 million per 12 months.  These expenditures are further limited after the “Capital Expenditure Limitation Date.” This is defined as the later of:June 30, 2023, orThe time when 13.2 MMBoe have been produced and sold (equivalent to 10.6 MMBoe in respect of the trust’s right to receive 80% of the net proceeds from the underlying properties) On this date, capital expenditures are further limited to the average of the prior three years of capital expenditures, which will likely drop it considerably below its current limit of $1 million per year.ConclusionIn our next post, we will use MV Oil Trust as a basis for examining how investor returns are affected by a royalty trust’s distribution of proceeds, volatility in the price of crude oil, the timing of entrance and exit, and other unique features of the royalty trust such as limits on capital expenditures.  We will do this by looking into what goes into the stock price of royalty trusts and the tradeoff between current and future returns.When investing in a public royalty trust or using it as a pricing benchmark for private royalty interests, there are many items to consider that are unique to each royalty trust.  The source of income, region, operator, termination, and other key aspects make each trust unique.We have assisted many clients with various valuation and cash flow questions regarding royalty interests.  Contact Mercer Capital to discuss your needs in confidence and learn more about how we can help you succeed.1 Capital IQ
Details and Analysis of Kimbell Royalty Partners’ Acquisition of Haymaker Minerals & Royalties, LLC
Details and Analysis of Kimbell Royalty Partners’ Acquisition of Haymaker Minerals & Royalties, LLC
As we have discussed in previous posts, there are 21 main oil and gas-focused partnerships that are publicly traded, as of June 30, 2018. Publicly traded royalty partnerships have been slowly regaining the value lost when crude oil prices fell below $30 per barrel in early 2016. In the two years since June 2016, 16 of the 21 royalty partnerships have had positive returns with an average return of 48%. Over the past two years, the remaining five partnerships experienced a negative 31% average return. In those two years, natural gas prices have experienced an insignificant increase of just 5%, while oil prices have risen more than 50%. The underperformance of natural gas prices is due to the surge in production of shale gas since 2006 and the more recent rise of natural gas production as a result of increased oil production.Kimbell Royalty Partners, LP (KRP)The youngest of the 21 partnerships, Kimbell Royalty Partners, LP (“Kimbell,” “KRP,” or the “Company”), went public in February 2017. The Company’s IPO opened at $18.00 per share, initially offering 5 million shares. Since going public, KRP’s price struggled in its infancy and fell under $16 per share in mid-August 2017. This year has been much kinder to Kimbell due to the high crude price with its share price peaking at $23. Approximately 70% of Kimbell’s revenues are from oil and natural gas liquids. Of the 21 mineral partnerships, Kimbell, Dorchester Minerals LP, Black Stone Minerals LP, and Viper Energy Partners LP are the only non-trust royalty partnerships and are either C Corporations or MLPs.  These MLPs and C Corps are designed to gather assets and grow through acquisitions, focusing on both dividend payments and the growth of shareholder value. On the other hand, the other 17 are royalty trusts, which have a limited pool of assets and must return most of the cash flow earned from the royalties to the shareholders through dividends. Trusts’ capital structures limit opportunities for reinvestment, making it difficult to grow their asset base through acquisitions. Of the MLPs/C Corps, Kimbell has the highest dividend yield at 7.63%, with Dorchester, Black Stone, and Viper at 6.23%, 6.76%, and 6.02%, respectively. KRP is the smallest of the four partnerships with a market capitalization of $370 million, while Black Stone and Viper each have market capitalizations near $3.7 billion. 1Acquisition OverviewPrior to its acquisition of Haymaker Minerals & Royalties, LLC and Haymaker Resources, LP (collectively, “Haymaker”), Kimbell had nearly 5.7 million gross acres in nearly every major oil and gas basin across 20 states with a primary focus in the Permian Basin and the Mid-Continent. Kimbell solely invested in mineral and royalty interests with the largest portion of its production concentrated in the Permian Basin, where it had 1.75 million gross acres of mineral interests and ~200,000 acres of overriding royalty interests (ORRIs). Currently, KRP has 25 active drilling rigs on its acreage and mineral and ORRIs on 50,000 wells. Kimbell’s holdings in the Permian Basin alone account for 26% of its net royalty acres, 60% of its gross acreage, and 60% of active wells on its total acreage.In comparison, Haymaker had ~5.4 million gross acres and ~43,000 net royalty acres primarily focused in the Mid-Continent. Haymaker had royalty interests in 33,800 wells and had more than double the number of active drilling rigs than Kimbell with 51. Kimbell acquired Haymaker for $404 million with $210 million of cash and 10 million newly issued common units going to Haymaker’s sponsors. The acquired company’s private equity sponsors are KKR & Co. LP (“KKR”) and Kanye Anderson Capital Advisors, LP (“Kayne Anderson”). Alongside the acquisition, Kimbell converted its tax status from an MLP to a C Corp. Kimbell believes that this conversion will give the company access to a much broader base of investors and access to a more “liquid and attractive currency.” Kayne Anderson’s and KKR’s willingness to take the newly issued shares, which will account for ~37% of Kimbell’s outstanding common units, shows the potential for investment growth that is achievable for Kimbell but not necessarily for Haymaker. Kimbell estimates that the acquisition will not only be accretive due to the quality of the assets, the acquisition will also be highly scalable and reduce the G&A costs on a per Boe basis. After the acquisition, Kimbell will have more than 11 million gross acres spanning 28 states, with 38,000 of its 84,000 wells in the Permian Basin. As of April 27, 2018, Kimbell’s 73 rigs account for 7% of the total rigs in the United States. To calculate price per acre, Haymaker’s 42,759 net royalty acres must be converted to the industry standard 1/8 conversion since Kimbell uses a non-standard method of calculating net royalty acres. The conversion, which assumes eight royalty acres for every mineral acre, results with Kimbell acquiring 342,072 net royalty acres for $404 million. This results in an implied price of $1,181 per net royalty acre. At the time of the transaction, Kimbell’s market capitalization was approximately $327 million with an 8.7% yield.  Post-transaction, KRP’s FCF yield rose to 12%, implying a 15% yield for Haymaker prior to the transaction. Much of Haymaker’s acreage is congruent to Kimbell’s existing acreage and is an evenly split oil and natural gas mix. Haymaker’s acres enhance the Company’s position in the Permian and Mid-Continent and also increase its exposure in the Appalachian Basin and the Marcellus and Utica Shales. After the transaction, Kimbell’s production will be approximately 2/3 liquids and 1/3 gas. KRP believes that through the consolidation of costs, their pro-forma G&A expense can decrease by as much as 50% to $3.22 per Boe. This decrease is due to the increased scalability of Kimbell after the transaction. The transaction is also projected to increase the net production per unit by 56%. The Company estimates the increased production and the cutting of costs alone could lead to a 20% increase in distributable cash flow per unit. AnalysisWhy would two companies with relatively comparable assets have such drastically different yields? Is it due to the fact that Kimbell is publicly traded while Haymaker is private? Perhaps the solution lies between the vast differences in public and private mineral market share sizes.Kimbell estimates that the total mineral buying market is close to $500 billion, excluding ORRIs. Public companies only make up 2.5% of the total market with a combined enterprise value of ~$12.3 billion. The two largest public, Black Stone Minerals and Viper Energy Partners, make up a combined $8.3 billion of that total value. While the public minerals market is only made up of a handful of companies giving public investors a limited number of investment options, the private minerals market is highly fragmented.Small mineral aggregators can operate with a higher attention to acreage details. These aggregators have the ability to negotiate directly with the landowners and handpick the acreage of their choosing. As a result, they expect higher yields than the public companies. While these yields are higher, the acreage is typically much more focused on certain areas.  Combined with their small size, these investments are inherently riskier than a larger, more diverse pool of assets, such as those held by public royalty trusts.Kimbell’s acquisition of Haymaker demonstrates the disconnect between the public and private markets and the discounts at which private LPs are valued. It seems that private royalty LPs simply do not have the same access to capital as the public MLPs or C Corps. This lack of access is potentially why KRP and Haymaker have distinctly different yields, 8.7% and 15%, respectively, and why KRP was able to successfully negotiate such a highly accretive deal. Private equity investors/sponsors seem to recognize this–Haymaker’s sponsors for example. Haymaker’s sponsors, a well-respected private equity firm (KKR) and one of the leading energy investors (Kayne Anderson), most likely saw the potential behind the accretive mix of the two companies, which is why they were willing to accept roughly 50% of the purchase price in Kimbell shares. Not only was Kimbell public, its transition to a corporation opened itself up to a broad array of inexpensive capital, far less expensive than what Haymaker could find. This access to cheaper capital makes it easier for Kimbell to grow through acquisitions and continue to increase its returns and shareholder value. Kimbell has the potential for growth as a public corporation far beyond what a private company like Haymaker could achieve.Public investors are looking for opportunities to invest in mineral plays; however, many of these investors’ only opportunity to do so is through public companies. Following the rise of crude oil prices, the increased demand from public investors has driven up the prices of the royalty trusts and MLPs and, in turn, lowered the yields. More and more investors, including institutional investors, are looking towards the mineral market to find investment growth. The emerging field of mineral aggregators has the potential to provide this growth through accretive acquisitions, as well as steady dividend payments, that public investors crave.We have assisted many clients with various valuation and cash flow issues regarding royalty interests.  Contact Mercer Capital to discuss your needs in confidence and learn more about how we can help you succeed.[1] Capital IQOur thanks to Daniel Murchison who drafted and did much of the research for this post in collaboration with our Energy Group.
Growing Pains Curb Valuation Gains in the Permian
Growing Pains Curb Valuation Gains in the Permian

2Q18 Review

[caption id="" align="aligncenter" width="337"]Too much to swallow?[/caption] The story of the Permian Basin in 2018 so far has been developing as one of the finest proverbial "fishing holes" in the world.  However, as the year has progressed, it appears many industry players have found their reputed "catch" too big to process and are scrambling to deal with it before it begins to stink. Translation: the year began with a flurry of developmental drilling activity followed by an emerging bottleneck.  The unintended consequence of this has been that some operators have been growing oil production too fast for pipeline and infrastructure to keep up.  A pricing differential has arisen due to the supply glut and there has been concurrent stagnation in valuations.  Here’s how some of it has transpired through the timeline of the first half of 2018. Q1: Flocking to the PermianThe Permian's 2018 journey began on the same trajectory that 2017 ended with growth, investment, and more growth.  This has been for a good triumvirate of key reasons too:Estimates vary by county, producer, and information source, but according to Bloomberg Intelligence, recent break-even prices in the Permian were as low as $38 in both the Delaware and Midland Basins.3Some of the best shale stacked geology in the world, andLong-standing pre-existing infrastructure to get petroleum to market (the play has been active since the 1920's). It's no wonder the Permian continued to attract operators and capital.  Capex budgets were not only growing for operators as a general matter, but increasingly higher percentages of those budgets were geared towards being spent in West Texas.  The chart below demonstrates this trend: Transactions in other basins were driven by motivations to re-deploy cash in the Delaware Basin, Midland Basin, or both.  We discussed this in a recent post.  Operators and mineral holders in other basins watched as activity and capital flocked to the Permian Basin. Q2: Hydrocarbon Traffic Jam However, plans, forecasts, and reality clashed around the end of the first quarter of 2018.  Although the takeaway capacity and infrastructure were present, it wasn't enough to keep up with growth, and it has burst at the seams.  This first began to be hinted at back in 2017, in regards to the growth and when new pipelines were coming online; it was discussed as a real problem issue in April with a few foreboding articles.This has led to capacity issues on a meaningful scale and there's too much of a good thing as a result.  Goldman Sachs' research team put together an interesting infographic that was referenced by HFI Research that characterizes it well:Local Permian Oil & Gas Prices: Falling FastThis has led to a rapid change in local wellhead prices in the Permian.  As early as January 2018, wellhead prices in the Permian were trading at a premium to markets at Cushing, OK.  However, as seen below in this Bloomberg chart, the gap skyrocketed over the course of the next 45 days and is currently hovering around $12 per barrel.  The primary driver of this differential is nested in alternative transportation costs as shown above.  This glut of production has rendered local natural gas to an almost forgotten status.  In the Permian, natural gas at the wellhead is almost worthless in some cases.  There's nowhere for it to go, and many producers have little choice but to burn (or flare) its' gas at the wellhead. It's not bad news for all in the oil patch.  Some players are embracing the turn of events.  Refiners are welcoming the low prices as they are able to arbitrage price differences at the gasoline pump and midstream producers are getting top dollar to transport more crude out of West Texas.  However, for many E&P producers (and royalty & mineral holders) this presents not only a problem from a pricing standpoint but from a future drilling standpoint as well.  Plans made as recently as a few months ago are undoubtedly being reconsidered by many producers.  The ones who have secured takeaway capacity are letting the market know about it. Q3 and Beyond: Valuation Stagnation and what about Backwardation?Valuations for Permian focused producers have stagnated this year.  Since January 1st only a handful of companies stock prices are up, while the majority have actually declined. This would appear counterintuitive in light of the overall optimism in the space.  Doesn't that bottleneck restriction push prices higher?  Isn't that a good thing? The answer is true in many respects, and producers worldwide and in other basins are reaping the benefits of this.  However, as far as Permian focused producers are concerned, they don’t get these benefits.  They are getting around $60 per barrel, instead of $70+ right now. Also, remember that valuations are a function not only of reserves (which are just as robust and optimistic as they have been recently), but of ultimately the production, cash flow, and timing that result from the development of those reserves.  This development has impacted all three: Production is anticipated to be curbed (at least until the bottleneck is dealt with – which might not be until late 2019 at this point);Cash flow is impacted by both production limitations AND pricing differentials; andTiming of when those cash flows will be received has been delayed. Speakers at a recent ASA Energy Conference in Houston, mentioned that certain upstream management teams have expressed elements of frustration that investors have not rewarded valuations with the oncoming of robust Q1 earnings, particularly out of the Permian Basin.  We're not so sure that's the case.  Acreage grabbing has slowed and earnings are expected to follow with all of the favorable aspects of the Permian.  Perhaps trepidations about this bottleneck and pricing differentials have fueled concerns and hampered values. Additionally, if futures curves are any indication, there is an expectation that prices will return from the current $70+ environment back down into the low $50s per barrel in a few years.However, the good news from a longer run perspective is that most producers make capital expenditure decisions from a longer-term perspective (several years out) due to the time it takes to deploy that capital and when it begins to make a return.  With break evens so low, this disruption – even if it lasts through 2019, does not change the longer term outlook in the Permian.  It mostly delays it, which is a good reason why stock values are on hold right now.Mercer Capital has significant experience valuing assets and companies in the energy industry, primarily oil and gas, biofuels and other minerals.  Our oil and gas valuations have been reviewed and relied on by buyers and sellers and Big 4 Auditors. These oil and gas related valuations have been utilized to support valuations for IRS Estate and Gift Tax, GAAP accounting, and litigation purposes. We have performed oil and gas valuations and associated oil and gas reserves domestically throughout the United States and in foreign countries. Contact a Mercer Capital professional today to discuss your valuation needs in confidence.
EP Third Quarter 2018 Region Focus Bakken Shale
E&P Third Quarter 2018

Region Focus: Bakken Shale

Region Focus: Bakken Shale // Oil and gas prices in 2018 have been steadily increasing in the midst of strong demand and constrained supply, and the U.S. energy sector is at the center of this focus.
Take What You Can and Get Out
Take What You Can and Get Out
When oil prices crashed in mid-2014, companies were forced to become more efficient in order to survive. It became clear that location meant more than ever and companies could no longer justify operating in regions such as the Bakken and the Eagle Ford, where break-even prices were higher than they were in the Permian.  Thus in order to stay in business, companies flocked to the Permian.  This week, we look at how the increased appeal of the Permian Basin has affected M&A activity in the oil and gas sector.The trend towards the Permian Basin was somewhat slow to begin as the uncertainty that accompanied the price collapse led to a standstill in activity. While some investors were quick to move to the Permian when acreage was still relatively inexpensive, most were slow to sell their acreage in other basins as the low oil price environment pushed down the price of acreage.   Now that the Permian has become the clear leader in production, M&A activity in the region has picked up and multiples for Permian acreage have increased due to high demand.  Although it was three to four years ago that the Permian emerged as the cost leader, companies are still moving to the Permian with haste.This trend is especially apparent as it relates to Pioneer Natural Resources’ recent acquisition activity.  Pioneer announced earlier this year that it would shift its focus to become a pure-play Permian producer, with plans to spend its entire $2.9 billion capex budget in the Permian Basin.Since the announcement, Pioneer sold Eagle Ford assets for $102 million and southeastern Colorado assets for $79 million, as summarized below.  It appears that Pioneer was willing to take a loss in order to re-deploy capital to the Permian Basin. In March 2018, Pioneer sold its assets in the Eagle Ford for $10,000/acre and $92,727 per flowing barrel.   The price Pioneer received was in line, or even above, industry averages which are more along the line of $4,200/acre and $98,000 per flowing barrel. However, this month Pioneer announced the sale of its Raton assets for only $79 million, a multiple of $5,600 per flowing barrel.  Meanwhile, multiples for acreage in southeastern Colorado are not expected to be at the same level as multiples seen in the Eagle Ford.  BusinessWire reported that this sale “is expected to result in a pretax noncash loss of $65 million to $75 million.” Pioneer seems to have shifted its strategy from a planned liquidation to a "take what you can and get out" approach.While Pioneer just exited its current position at multiples lower than what might be otherwise expected for the region, they are looking to buy acreage in a region where multiples have flown through the roof.  Recent acreage transactions in the Permian Basin are closing at median multiples of $16,000 per acre and over $180,000 per flowing barrel as summarized below, according to Shale Experts.Pioneer’s recent transaction activity shows the urgency with which companies are now shifting their focus to the Permian.  Pioneer’s acceptance of a large loss for its Raton assets is symptomatic of the recent dominance of the Permian to all other U.S. shale plays.  And while Pioneer accepted a loss in order to sell its acreage at meager multiples of $5,600 per flowing barrel, it will now likely use that cash to pay for Permian acreage at multiples of over $100,000 per flowing barrel.Part of the reason for paying the premium multiple can be explained by the existence of more proved undeveloped (PUD) reserves in the Permian Basin as compared to other regions.  Many transactions in the Permian are motivated by the existence of future drilling potential over current production. Thus multiples of current production in the Permian are inflated when compared to transactions in regions that have more current production but less potential for the development of PUD reserves.   However, the difference is mainly due to the obvious benefits of operating in the Permian Basin as compared to other unconventional shale plays, including low break-even prices, efficiencies generated multiple stacked plays, and lower costs from shorter transportation distances to refineries.  However, it is worth noting that increased drilling activity in the Permian Basin is beginning to strain the existing infrastructure in the Permian, creating transportation bottlenecks (or as Bryce Erickson likes to call it, a hydrocarbon traffic jam).Javier Blas with Bloomberg recently pointed out the logistical difficulties in getting Permian oil and gas to market and the growing price differentials as a result.  This could be a cause of short to intermediate term revenue and valuation disruptions for some producers.With such wide range of observed transaction multiples, it is especially important to understand each transaction and the main drivers of value before using a transaction as a benchmark of value.  We have assisted many clients with various valuation needs in the upstream oil and gas space in the Permian Basin, other conventional and unconventional plays in North America and around the world.  Contact Mercer Capital to discuss your needs in confidence and learn more about how we can help you succeed.
Piping Hot Permian
Piping Hot Permian
Production in the Permian is as hot as the summers in West Texas.  Despite being discovered in the 1920s, it was not until 2007 that the region’s true potential was realized when hydraulic fracturing techniques were used to access the play's tight sand layers. Given its low-cost economics and large well potential, in recent years, the Permian has been in the limelight with operators and investors alike prioritizing the region.According to Baker Hughes, there are virtually no active gas-directed rigs, but significant gas production is still occurring in the region because natural gas is coming as a by-product from the oil rigs.  As we discussed in a previous post, this is having a negative effect on natural gas prices and producers outside of the Permian.  Companies in the Permian have an advantage because they do not have to choose between oil and gas, and production is more efficient.  As such, the Permian is the largest producer of oil and the second largest producer of gas, after the Marcellus.Rig Counts and ProductionWith many producers clamoring for a piece of the action, the number of rigs in the Permian has consistently grown at a faster rate than total rig counts in the country.  As a result, the Permian has increased its share of total rig counts, as seen in the graph below.  In June 2015, the Permian accounted for 27% of all rigs, but that number steadily increased to 45% as of June 2018.  The number of rigs in the Permian has grown 32% in the past year, compared to 16% nationally; these figures were 156% and 125% for the year before that. According to the EIA, production of oil and natural gas in the Permian Basin has increased at a compound annual rate of 25.0% and 21.1%, respectively over the last five years.  In the past year alone, oil production increased 35.6% and gas production increased 26.5%, with over 45% of the U.S.’ crude oil and 15% of the country’s natural gas currently coming from the Permian Basin.1  A concerted effort has been made to increase efficiency, which has led to a rise in production per well.  Oil production per rig in the Permian increased more than 36% in the last year, which, when combined with the rise in rig count, further emphasizes the focus on the region. Economic ImpactWith this rush to West Texas, Midland and Odessa are in the middle of the action.  The boom has had a large impact on their economies as a whole.  Population growth from 2016 to 2017 was estimated at 4.2% for Midland and 4.8% for Odessa, compared to 2.0% for Texas and 0.8% for the country.  Unemployment was also extremely low at 2.1% and 2.8%, respectively, compared to 3.8% for the state and 3.7% for the country.  The national unemployment rate is already at its lowest of this millennium, emphasizing how razor-thin the margin is in Midland.  This has caused significant labor shortages in other sectors of the economy as they cannot compete with $28/hour wages offered after minimal training requirements for workers in the oil sector.Valuation ImplicationsWe can understand the valuation implications for companies in the Permian Basin by looking at 1) royalty trusts and mineral rights aggregators and 2) E&P companies.Royalty TrustsPositive market sentiment for the Permian region can be viewed in the performance of both operators in the region and publicly traded royalty trusts with exposure to the Permian.  As seen in the following tables, royalty trusts in the Permian have seen far superior two year returns.  Also of note is the average size measured by market cap.  Viper Energy Partners, Black Stone Minerals, and Kimbell Royalty Partners are all aggregators of mineral interests and are not restricted from acquiring new interests like many other royalty trusts.  This causes them to be larger, and it also allows them to gain exposure to new, advantageous regions, which may play a role in all of them having exposure to the Permian. Royalty Trusts typically decline in both production and level of reserves. For the trusts with properties outside of the Permian, they have averaged decline rates of 14% for production and 21% for reserves over the past three years.2  However, trusts in the Permian are increasing at average rates of 13% for production and 7% for reserves.  This indicates the increased activity in the region, though again, it should be noted that some of the trusts that are not restricted from acquiring new properties are likely to be categorized in the Permian group as they would have sought exposure to the region. E&P CompaniesAs seen in the graph below, E&P companies valuation multiples on average remain highest in the Permian, but they have declined 21% in 2018.  Multiples in the Bakken and Eagle Ford meanwhile have cut into the gap, increasing 34% and 25%, respectively since the beginning of the year.  The Marcellus and Utica continue to see the lowest valuation multiples and have declined by 2% in 2018.  Companies in the Permian are generally more profitable than companies in other regions as explained by their lower break-even prices. According to Bloomberg Intelligence, recent break-even prices in the Permian were $38 in both the Delaware and Midland Basins.3  This represents a 6% decline for the Delaware Basin since June 2017, compared to a 28% decline in break-even price for the Midland Basin.  These break-even prices compare favorably to $40 in the Bakken and about $44 in the Eagle Ford. Production in the Permian appears to be full steam ahead. And as they say, if you can’t stand the heat, stay out of the Permian. We have assisted many clients with various valuation needs in the oil and gas space in the Permian region, other conventional and unconventional plays in North America, and around the world.  Contact Mercer Capital to discuss your needs in confidence and learn more about how we can help you succeed. End Notes1 EIA; Calculations based on monthly crude oil and gas production and EIA drilling report by region 2 Capital IQ; Calculations based on production and reserve figures reported in royalty trust 10-K’s 3 Bloomberg Intelligence; County Level Estimate
3 Things All Mineral Owners Should Know
3 Things All Mineral Owners Should Know

Minerals Workshop at the DUG Permian Basin Conference

On May 21, Mercer Capital attended the Minerals Workshop at the DUG Permian Basin Conference in Fort Worth, Texas. The agenda included five presentations and eleven speakers, including royalty brokers, royalty aggregators, and royalty managers. Speakers included: Leslie Haines, Hart EnergyGeorge Soulis, Oil & Gas Asset ClearinghouseDarren Barbee, Oil and Gas InvestorC.H. Scott Rees III, NSAIJames R. Elder, Momentum Minerals LLCNick Varel, Wing Resources LLCWill Cullen, LongPoint Minerals LLCJames Wallis, NGP Energy Capital ManagementJames S. Crain, EnCap Investments LPJohn M. Greer, Latham & Watkins LLPHenry S. May III, Post Oak Energy CapitalMike Allen, Providence Energy Corporation We learned about changes in the royalty market, mineral investor required returns, private equity strategies and due diligence musts for buyers. In light of the information, three themes emerged that mineral owners should know about the royalty market.Growing Universe of Mineral BuyersWith the interest rate environment near all-time lows, many investors are looking for alternative investments to provide higher yields. This has driven private equity money into oil and gas. While part of private equity is targeting returns in operating exploration and production companies, mid-stream assets and refineries, significant money has found its way into the mineral and royalty market. Over the past four years, the mineral business has changed due to a surge in popularity. Minerals provide higher yield investment opportunities in a low yield environment. As a result of the surge, buying minerals is getting more and more competitive. Many of the speakers mentioned the prices for mineral buyers are increasing, and the market is attracting larger and more efficient mineral buyers. One speaker mentioned that prices on the ground have increased 40% to 50% in the last several years. In effect, increased competition is making it tough for the “small guys” to compete. A low yield investment environment is driving more money into the industry, increasing the number of buyers, increasing competition, and driving up prices of mineral interests. The chart below demonstrates the upward trend of the three most discussed mineral "aggregators" at the Minerals Workshop.Target Double-Digit ReturnsInvestments are graded based on the returns of alternatives and their prospective risk. For example, debt issued by the United States Treasury Department is considered “risk-free” (we can discuss the merits of that assumption later). Therefore, the yields for U.S. Treasury bonds and bills provide a measure of risk-free required returns. As of June 11, 2018, the 20 year Treasury bond yields approximately 3.10%, which means nothing without a comparison. For comparison, buyers of mineral rights have target returns upwards of 50% in some cases. While bonds produce low 3% returns, large capitalization equities in the public market return 5% to 8%. An asset class that can produce 50% returns is a significant difference! While part of the delta is due to the incremental risk assumed by the buyer, a significant reason for the delta is due to the negotiating power many mineral buyers have flexed in the industry over the last few years.To put it simply, demand for mineral rights was low in the last quarter of 2014. This is understandable as oil prices collapsed from $100+ to $20’s. Interest was low, oil and gas operators were going bankrupt, and the outlook was uncertain. As a result, the activity level for selling mineral rights was low to non-existent. Therefore, when one of the private equity speakers mentions “in 2015 there were many mineral interests to purchase,” it should come as no surprise. They were buying when there was “blood in the street.” Since that period of time, many operators have recovered, the Permian Basin has become the hottest shale play in North America, and oil prices have reached $60+. Investment capital has taken notice of the higher return opportunity and has created more demand for mineral rights. The interest has been spurred on by the promise of high rates of return.Of the 11 presenters, more than half shared their targeted internal rates of return for their investments. The interesting part of this discussion was not the high double-digit returns, but the range of returns each was targeting. For mineral and royalty interests, target rates of returns were 10% to 50%. It was clear that broad range was based on several factors including: (1) use of leverage; (2) time horizon; and (3) information. One might wonder how mineral buyers are able to create this type of return in an increasingly competitive market. The reason for this: actual and perceived information asymmetry between buyers and sellers.Asset Knowledge & Due DiligenceWhen a mineral buyer approaches a mineral owner, there is a real chance the buyer knows more about the minerals than the owner.Increasingly sophisticated buyers perform the following due diligence on mineral and royalty interests: (1) Analysis of the lease historical production; (2) well spacing analysis; (3) infrastructure analysis; (4) reserve and geological analysis; (5) decline curve analysis; (6) “closeology” analysis which is using public data from operators to assess the activity within an area; and (7) lease detail analysis. All of which, is done before offers are made to the mineral owner. However, buyers don’t stop there. After an offer is made, more due diligence is performed which requires mineral ownership approval. These due diligence steps are focused on cash flow and pricing differential analysis which can be understood from check stubs that royalty owners received each month.Since many mineral rights and royalty rights are passed down from generation to generation, it is not uncommon for the 2nd, 3rd, or 4th generation owners to negotiate from a disadvantaged position, due to lack of information sometimes not transferred from one generation to the other. All of the above due diligence items are available to the mineral owner; however, it takes time and experience to know where to find the information and to understand the data. Information asymmetry is one of the biggest reasons the market for royalty sellers is inefficient. Large, very highly capitalized buyers have invested the time and energy to understand the opportunities in minerals and utilize this advantage in negotiations.We have assisted many clients with various valuation needs in the upstream oil and gas space in the Marcellus and Utica areas, other conventional and unconventional plays in North America and around the world.  Contact Mercer Capital to discuss your needs in confidence and learn more about how we can help you succeed.
Tax Reform and Purchase Price Allocations for Oil & Gas Companies
Tax Reform and Purchase Price Allocations for Oil & Gas Companies
On December 22, 2017, President Trump signed The Tax Cuts and Jobs Act, which resulted in sweeping changes to the U.S. tax code.The Act decreased the corporate tax rate to 21% from 35%, in addition to modifying specific provisions around interest, depreciation, carrybacks, and repatriation taxes.The change in tax rate will have the biggest impact on purchase accounting. In the energy industry, this will manifest itself in several ways.  This blog post explores some of the impacts to valuations performed under fair value accounting in ASC 805 and ASC 820.Cash Flows and ReturnsWhen we evaluate prospective financial information, a lower tax rate will result in higher after-tax earnings.The value of the tax shield created by depreciation and deductions will be influenced by both the lower corporate tax rate (which reduces the tax shield’s value) and accelerated depreciation of qualifying capital equipment purchases (which increases the tax shield’s value).  This could mean incentives for energy-oriented companies to (i) create a more modernized drilling rig fleet sooner that are best suited for today’s multi-frac lateral wells and (ii) accelerated plans to create more infrastructure and pipelines in active basins such as the Permian, Bakken and Eagle Ford.  In addition, it also could drive more refinery and LNG liquefaction plant development.  In most cases, a lower tax rate will increase cash flows, increasing the internal rate of return on acquisitions for a given purchase price.On the other hand, if lower tax rates drive higher purchase prices, internal rates of return may be unchanged.In terms of the weighted average cost of capital (WACC), the lower tax rate actually increases the after-tax cost of debt.Keeping other inputs constant, this modestly increases WACCs.Relief from RoyaltyUnder the relief from royalty method, after-tax royalties avoided increase as the tax rate falls.However, the tax amortization benefit (TAB) component of the intangible value also declines as a result of the lower tax rate, which serves to partially offset the increase in after-tax cash flows.Scenario AnalysisIn a scenario analysis used to value a noncompete agreement, a lower tax rate will again decrease the tax amortization benefit.Since both scenarios under the with and without approach will reflect the same tax rate, the impact of the new lower rate will be muted.As a result, the fair value of noncompete agreements may well be somewhat lower under the new tax rate.Cost ApproachThe cost approach, which is often used to value assets such as the assembled workforce or some technologies, the impact depends on whether a pre-tax or after-tax measurement basis is used.If fair value is measured on a pre-tax basis, the fair value of such assets is unaffected.If measured on an after-tax basis, costs avoided net of tax will be higher under lower tax rates, although this gain will be offset somewhat by the decrease in the TAB. Multi-Period Excess Earnings Method The impact of the tax rate on assets valued under the Multi-Period Excess Earnings Method (MPEEM) is more ambiguous since two key elements will be affected – the contributory asset charges and the tax rate used to derive after-tax cash flows.On the cash flow side of things, the lower tax rate will result in higher cash flow but a lower TAB.As far as contributory assets are concerned:Relief from royalty asset charges will increase under a lower tax rateWith and without scenario analysis with level payments charges will potentially decrease due to the lower base valueCost approach asset charges may increase or decrease depending on the net effect of taxes and TAB calculationsReserves & Goodwill The net impact of a lower tax rate on goodwill will vary by transaction.  Since reserves are typically viewed through a pre-tax lens, the value of reserves could be muted (all else held constant).  However, we note that if tax incentives increase CapEx and drilling plans, then more reserves could move up the category chain (P2 to P1 for example) and thus increase the fair value of reserves.  If the lower tax rate results in a higher transaction price, the aggregate increase in fair value will likely result in a larger allocation to goodwill.  This would apply more to intangible based energy companies.  Upstream companies typically do not book goodwill.  If, instead, the lower tax rate increases the projected IRR on a transaction, the impact on residual goodwill is harder to predict and will depend on the composition of the assets acquired.The changes to corporate taxes under the new bill are wide-ranging.In addition to the effect of lower rates discussed in this post, fair value specialists need to be alert to how other specific provisions of the bill may influence individual energy companies.Impact of Tax Rate Decrease on Valuation MethodCash Flows/Returns Higher after-tax cash flows/impact on returns depends on transaction priceTax Amortization Benefits DecreaseRelief from Royalty Method Increase (potential offset by decrease in TAB)Cost Approach (pre-tax) No ChangeCost Approach (post-tax) Increase (potential offset by decrease in TAB)With and Without Scenario Potentially lower (potential offset by decrease in TAB)MPEEM May Increase or Decrease (depends on magnitude of other changes)
The Permian Boom Causing a Natural Gas Bust
The Permian Boom Causing a Natural Gas Bust
The oil industry is cruising. Producers are flocking to many oil rich plays, most notably the Permian Basin, Bakken, and Eagle Ford. Producers in these areas are all looking to exploit multi-zone payouts and gain significant efficiencies with new deep lateral and horizontal wells.While this strategy is working very well for oil producers, often lost in the oil excitement is the byproduct, additional dry and natural gas liquids. For producers targeting natural gas, this is not good news. The U.S. has significant natural gas. While export demand is approximately 10% to 12% of all domestically produced natural gas, high supply and demand factors have kept prices relatively flat.The Economics of the Current Price EnvironmentThe articles below address the economics of the current price environment:Thank Goodness for Natural Gas Exports (Forbes)Demand for Natural Gas is Surging, but Glut Remains (US News and World Report)Why U.S. Natural Gas Prices Will Remain Low (Forbes) While the low prices are favorable for consumers of natural gas, E&P companies are struggling. Producers of natural gas, specifically those operating in areas where crude oil is minimal, such as the Marcellus and Utica, are getting stretched thin, some beyond their ability to recover. Rex Energy Corporation (Rex) is the latest natural gas producer to file for a Chapter 11 orderly reorganization beginning with the sale of assets. Rex Energy CorporationRex Energy Corporation is an independent E&P company that produces condensate, natural gas liquid (NGL), and natural gas in the Marcellus, Utica, and Burkett Shale. On May 18th, Rex announced that, following its previously announced strategic review, it has decided to begin an orderly sale process for its remaining assets in order to maximize their long-term value and prospects. To facilitate the sale and address its debt obligations, the Company initiated voluntary proceedings under Chapter 11 of the U.S. Bankruptcy Code with support outlined in a Restructuring Support Agreement signed by 100% of its first lien lenders and approximately 72% of its second lien noteholders.A review of their financial performance over the previous five years indicates declining revenues from lower natural gas prices. Revenue increased from 2013 to 2014, then declined during 2015-2017. This behavior is consistent with commodity price fluctuations. Operating income followed a similar trend which put pressure on the company to use debt to fill the gap.  Debt doubled from 2013 through March 2018 and interest expense increased during all years and peaked at $62 million during the LTM March 2018 period. All of this was done hoping natural gas prices would increase to the point Rex could reach profitability. However, Rex ran out of time.Other Marcellus and Utica OperatorsRex is not the only Marcellus and Utica operator with this trend. CNX Resources, Eclipse Resources and EV Energy Partners all have stock charts with similar trends. Diversified Gas and Oil is the only publicly traded Marcellus and Utica focused producer with a stock price trend bucking the macro environment. They are also relatively new to the publicly traded scene, having been publicly traded for less than two year.CNX Resources, Eclipse Resources and EV Energy Partners have seen price declines on the order of 50% to 100% since mid-2014.  Eclipse Resources, for example, experienced a rapid fall in its stock price after raising $818 million in a U.S. initial public offering.  Its stock price has fallen by nearly 100% and last month Eclipse announced that they were evaluating different options to maximize company value such as engaging in accretive acquisitions or sale of the company.The performance of all the E&P companies named above is shown below. Descriptions of each company are included below per their respective 10Ks. CNX Resources Corporation, an independent oil and natural gas company, explores for, develops, and produces natural gas in the Appalachian Basin. As of December 31, 2017, it had 7.6 trillion cubic feet equivalent of proved natural gas reserves. The company also owns, operates, and develops natural gas gathering and other midstream energy assets in the Marcellus Shale in Pennsylvania and West Virginia. The company was formerly known as CONSOL Energy Inc. and changed its name to CNX Resources Corporation in November 2017.Eclipse Resources Corporation, an independent exploration and production company, acquires and develops oil and natural gas properties in the Appalachian Basin. The company holds interests in the Utica Shale and Marcellus Shale areas.EV Energy Partners, L.P., through its subsidiaries, engages in the acquisition, development, and production of oil and natural gas properties in the United States. Its properties are located in the Barnett Shale; the San Juan Basin; the Appalachian Basin; Michigan; Central Texas; the Monroe Field in Northern Louisiana; the Mid–Continent areas in Oklahoma, Texas, Arkansas, Kansas, and Louisiana; and the Permian Basin.Diversified Gas & Oil PLC engages in the production of natural gas and crude oil in the Appalachian Basin of the United States. It has interests in the oil and gas properties in Pennsylvania, Ohio, and West Virginia.  As shown below, it has not experienced the same declines in price as many of the other producers in the region.ConclusionWhile these macro issues have been impacting the industry for years, many investors have expected supply to fall to the point of creating higher prices. As this Wall Street Journal article points out, many investors had to adjust their investment time horizon. Investments made during 2014 and 2015 have not been exited by hedge funds like Fir Tree due to lower than expected public demand. Fir Tree’s energy investment strategy included purchasing the debt of failing companies only to flip it into a controlling equity position in the “emerged from bankruptcy” company. While they have been somewhat successful in this strategy, their holding periods are longer than originally planned. It appears investor’s are salivating for more companies like Amazon and less for companies like Sandridge Energy. While the headlines are focused on Permian Basin winners, the rest of the oil and gas market is not as cheery. The mixed bag of winners and losers makes the industry tricky to operate within.We have assisted many clients with various valuation needs in the upstream oil and gas space in the Marcellus and Utica areas, other conventional and unconventional plays in North America and around the world.  Contact Mercer Capital to discuss your needs in confidence and learn more about how we can help you succeed.
Royalty Interests and the Importance of the Operator
Royalty Interests and the Importance of the Operator
In previous posts, we have discussed the market pricing implications of publicly traded royalty trusts to royalty and mineral owners. We have explained the importance of understanding the specifics underlying those trusts before using them as a pricing benchmark. In this post, we will delve further into market prices of royalty and mineral interests and the important role of operators. We will look into the three publicly traded royalty trusts operated by SandRidge Energy: SandRidge Mississippian Trust I, SandRidge Mississippian Trust II, and SandRidge Permian Trust.Market Observations1Over the previous two years, the performance of the 21 publicly traded royalty trusts has varied widely.  Thirteen have experienced positive market value returns with an average of positive 57% and eight have returned market value losses during the previous two years with an average market value return of negative 39%.Clearly, there are some winners and losers, with more winners than losers. The royalty trust with the highest market value return was Whiting USA Trust II (WHZT) (+330%), which was discussed in a recent blog post.  Mesa Royalty Trust (MRT) (47%) was another big winner covered in a previous blog post.  However, the focus of this blog post will be on some of the underachievers: SandRidge Mississippian Trust I (SDT) (-76%), SandRidge Mississippian Trust II (SDR) (-61%), and the SandRidge Permian Trust (PER) (-21%).For comparison, the chart below shows the returns from PER, SDR, SDT, crude oil, natural gas, and the S&P 500. Why has the value of these SandRidge Trusts depreciated so much over the past two years despite increasing commodity prices? Also, why has the Permian trust fared better than the Mississippian Trusts? Below is a discussion of the assets, underlying properties, and agreements of each Trust. SandRidge Mississippian Trust IThe only asset of the Trust is the conveyance of the Royalty Interests by SandRidge Energy, Inc. The Royalty Interest entitles the Trust to receive:90% of the proceeds from the sale of oil, natural gas, and natural gas liquids ("NGL") production attributable to SandRidge’s net revenue interests in 36 wells producing at December 31, 2010, and one additional well undergoing completion operations at that time (together, the “Initial Wells”).50% of such proceeds from 123 “Trust Development Wells” drilled within an area of mutual interest (“AMI”) Pursuant to a development agreement entered into between the Trust and SandRidge, SandRidge was obligated to drill, or cause to be drilled, the Trust Development Wells by December 31, 2015.  SandRidge fulfilled this obligation in April 2013. SDT’s Royalty Interests are in specified oil and natural gas properties located in the Mississippian formation in Alfalfa, Garfield, Grant, and Woods counties in northern Oklahoma.SandRidge Mississippian Trust IIThe only asset of the Trust is the conveyance of the Royalty Interests by SandRidge Energy, Inc. The Royalty Interest entitles the Trust to receive:80% of the proceeds from the sale of oil, natural gas, and natural gas liquids ("NGL") production attributable to SandRidge’s net revenue interests in 54 wells producing at December 31, 2011, and 13 additional wells awaiting completion at that time70% of such proceeds from 206 horizontal “Trust Development Wells” drilled within an area of mutual interest (“AMI”) Pursuant to a development agreement entered into between the Trust and SandRidge, SandRidge was obligated to drill the Trust Development Wells by December 31, 2016.  SandRidge fulfilled this obligation in March 2015. SDR’s Royalty Interests are in specified oil and natural gas properties also located in the Mississippian formation in Alfalfa, Grant, Kay, Noble and Woods counties in northern Oklahoma, as well as Barber, Comanche, Harper, and Sumner counties in southern Kansas.SandRidge Permian TrustThe only asset of the Trust is the conveyance of the Royalty Interests by SandRidge Energy, Inc. The Royalty Interest entitles the Trust to receive:80% of the proceeds from the sale of oil, natural gas, and natural gas liquids ("NGL") production attributable to SandRidge’s net revenue interests in 517 wells producing at April 1, 2011, and 21 additional wells awaiting completion at that time70% of such proceeds from 888 horizontal “Trust Development Wells” drilled within an area of mutual interest (“AMI”) Pursuant to a development agreement entered into between the Trust and SandRidge, SandRidge was obligated to drill the Trust Development Wells by March 31, 2016.  SandRidge fulfilled this obligation in November 2014. PER’s Royalty Interests are in specified oil and natural gas properties in the Fuhrman-Mascho field in Andrews County, Texas, which is a part of the prolific Permian Basin. It should be noted that this is outside the two main Permian sub-basins (the Delaware Basin and the Midland Basin). Nevertheless, the Permian's attractive location and increased well count likely explains why the Permian Trust outperformed the Mississippian Trusts. The following table shows important production and reserve data for the underlying properties, as well as SandRidge’s ownership in the Trusts’ units and other pertinent data. The Trusts no longer have any hedging derivatives contracts, so they are exposed to oil and natural gas price volatility. Analysis of TrustsDevelopment Wells and Area of Mutual InterestEach of the Trusts receives 80-90% of the proceeds from the sale of oil, natural gas, and NGLs (after deducting post-production costs and any applicable taxes). This is fairly common for publicly traded royalty trusts, but the Trust Development Wells are unique. At the IPO date for each Trust, well counts were relatively low. In fact, the initial wells made up less than 25% of the total well counts for the Mississippian Trusts and about 38% of the Permian Trust. This agreement allowed the Trusts to make distributions from currently producing wells in addition to offering growth opportunities with the future development wells.The “development” aspect of the wells would seem to cast doubt upon the production of each Trust if it did not end up developing the total number of wells required or in a timely manner. The development agreement offered protection to investors. It is important to note that SandRidge fulfilled its development obligation in plenty of time in each case. Investors were further protected with the clause ensuring wells would be drilled in an area of mutual interest (AMI). This means SandRidge could not drill wells in random locations to fulfill its obligation.DistributionsThe Trusts make quarterly cash distributions of substantially all of its cash receipts, after deducting amounts for the Trusts’ administrative expenses and cash reserves withheld by the Trustee. The price for oil peaked in 2014 near $108 per barrel and close to $8 for natural gas before declining sharply in the latter half of the year. The low point was seen in late 2015, early 2016, with prices of approximately $28 and $1.64, for oil and gas.  Prices currently stand around $68 per barrel and $2.80 per MCF, respectively. The steep decline in oil and gas prices in mid-2014 had a crippling effect on distributions.  The following chart tracks the quarterly distributions per share for the Trusts since 2012.Termination of the Trusts The Trusts will dissolve and begin to liquidate on the “Termination Date” (noted in the table above). At the Termination Date, 50% of the Royalty Interests will revert automatically to SandRidge. The remaining 50% of the Royalty Interests will be sold at that time, and the net proceeds of the sale, as well as any remaining Trust cash reserves, will be distributed to the unitholders on a pro rata basis. SandRidge has a right of first refusal to purchase the Royalty Interests retained by the Trust at the Termination Date. There are certain provisions protecting investors in the case the Trust were to dissolve prior to the Termination Date, such as a requirement that cash available for distributions be above a certain threshold, as noted in the table above. The Trusts are highly dependent on its Trustor, SandRidge, for multiple services including the operation of the Trust wells, remittance of net proceeds from the sale of associated production to the Trusts, administrative services such as accounting, tax preparation, bookkeeping, and informational services performed on behalf of the Trusts. For these administrative services, the Trusts pay SandRidge an annual fee (noted in the table above) which is payable in equal quarterly installments and will remain fixed for the life of the Trusts. SandRidge is also entitled to receive reimbursement for its out-of-pocket fees, costs, and expenses incurred in connection with the provision of any of the services under this agreement. SandRidge Energy and the Importance of the OperatorSandRidge Energy (SD) is an oil and natural gas exploration and production company headquartered in Oklahoma City. According to SD's website, its principal focus is on developing high-return, growth-oriented projects in the US Mid-Continent and Niobrara Shale.SandRidge filed for Chapter 11 bankruptcy in May 2016 and emerged from bankruptcy in October 2016, as we discussed in a blog post around that time.  SandRidge was relisted on the NYSE around $19.50 per share. Its performance has been volatile and generally negative since, as seen in the chart below. Activist investor Carl Icahn spent $82 million in October and November 2017 to acquire about 13.5% of SandRidge stock.  Since he became a shareholder, Icahn has had a large impact, causing directors to cancel their planned $746 million purchase of Bonanza Creek Energy and lay off 80 employees including their CEO and CFO. He also played a role in the rejection of an acquisition attempt by Tulsa-based Midstates Petroleum Inc. in February. Icahn recently expressed "grave concerns" with the board, claiming it had “a history of making poor decisions on behalf of stockholders.” Market confidence for SandRidge Energy is very low, after having gone through a bankruptcy-related restructuring recently as well. These concerns are significant to the SandRidge Trusts because operators play a vital role for royalty interests. They are responsible for production, without which, there are no distributions. If an operator is unable to produce or becomes less focused on a particular well or region, the royalty interests attached to them are worth significantly less. In the case of the SandRidge Trusts, turmoil with the operator has put future production into question. The lack of control for the royalty interests means they are tied to the fortunes of the operator. Even for securities with yields above 20%, the unsustainability of these distributions does not inspire confidence in investors. ConclusionThe operator is a key consideration for owners of royalty interests, particularly those interested in selling. As outlined in our post last week, offers received for royalty interests can be heavily dependent on operators and the uncertainty related to a change in operator.Owners of mineral interests typically receive offers as multiples of average monthly revenue received.  These multiples are typically determined by commodity prices, quality of operators, growth opportunities, and market sentiment. While owners of royalty interests do not have much control over these factors, they provide important starting points when considering selling.We have assisted many clients with various valuation and cash flow questions regarding royalty interests.  Contact Mercer Capital to discuss your needs in confidence and learn more about how we can help you succeed.[1] Capital IQ
Royalty Trusts: I’m a Revenue Partner… No, Wait… That Looks Like Equity
Royalty Trusts: I’m a Revenue Partner… No, Wait… That Looks Like Equity
In previous posts, we have discussed the existence of publicly traded royalty trusts & partnerships and their market pricing implications to royalty owners. Before using publicly traded royalty trusts as a pricing reference for your royalty interest, it is important to understand the economic rights and restrictions within those royalty trusts. Many publicly traded trusts have a set number of wells generating royalty income at declining rates for multiple years to come. In contrast, some trusts participate in a number of wells that have not been drilled, which represent upside potential for investors. Future growth and outlook potential for these publicly traded trusts are significantly different. A potential investor would want to know the details. The same is true for a privately held royalty interest.Market Observations1As of April 25, 2018, there are approximately 21 publicly traded oil and gas-focused royalty trusts and partnerships.Figure 1Over the previous two years, the performance of the 21 publicly traded royalty trusts has been a mixed bag.  Eight have returned market value losses during the previous two years with an average market value return of negative 39%. Thirteen have experienced positive market value returns with an average of positive 57%.Contrast this wide return with the price of crude oil and natural gas which have both increased over the same period (Figure 2). Oil has consistently marched from $45 to $68, while dry gas has climbed from $1.88 to $2.79.Figure 2Clearly, there are some winners and losers among the 21 royalty trusts over the previous two years and, noticeably, more winners than losers. As seen in Figure 1, the royalty trust with the highest market value return was Whiting USA Trust II (WHZT) (+330%) over the previous two years, with MV Oil Trust (+69%) and VOC Energy Trust (+59%) coming in second and third, respectively.Why did Whiting USA Trust II outperform all other royalty trusts over the previous two years and what is the nature of its economic rights and restrictions?Whiting USA Trust II (WHZT)Recent Pricing ActivityOver the previous two years, WHZT's stock price has increased from $0.50 to $2.15, an increase of 330% (Figure 3). Much of this increase was a steady climb from $0.50 to $1.50 as of April 5, 2018, which represents an increase of 200%. The last movement of $0.65 occurred in the previous 20 days. WHZT released their most recent 8K and 10K on March 23 and March 22, respectively. It appears it took the market a few weeks to get around to reading it. Additionally, the pricing activity is functioning much more like a working interest versus a royalty interest. Digging deeper will help us learn why.Figure 3Description of Assets Owned by WHZTWHZT assets include “term net profits interest in the oil and gas producing properties located in the Permian Basin, Rocky Mountains, Gulf Coast, and Mid-Continent regions” as described in their latest 10K filing:[The term net profits interest (NPI)] represents the right for the Trust to receive 90% of the net proceeds from Whiting’s interests in certain existing oil, natural gas and natural gas liquid producing properties which are referred to as “the underlying properties”. The underlying properties are located in the Permian Basin, Rocky Mountains, Gulf Coast and Mid- Continent regions of the United States. The underlying properties include interests in 1,312 gross (376.7 net) producing oil and gas wells as of December 31, 2017.Overall, these positions look positive as the Permian Basin is the most popular North American play currently and the Rocky Mountains, Gulf Coast, and Mid-Continent have positive characteristics too.Is an NPI Closer to a Royalty or Working Interest?The NPI represents a 28.7% profits interest in the producing oil and gas wells of Whiting. Net proceeds are calculated in the following manner: (1) Quantity of oil, gas and natural gas liquids times the price of oil, natural gas or natural gas liquids; minus (2) lease operating costs and workover costs; minus (3) production and property taxes; minus (4) development costs, hedge payments and all such production and development costs; minus (5) a maximum reserve of $2 million for future development. If the result of this formula is positive, 90% is distributed to the unitholders of WHZT. If the result is negative, the unitholders of WHZT are not liable currently. Unitholders are quasi-liable with any future net profits as accumulated losses will be zeroed out with future gains until there is a gain greater than zero.It appears an NPI is a fancy term for working interest. If not for the protection of direct capital calls, there is not a significant difference between an NPI and working interest, or any material difference from what we read. Indirectly, the unitholders are making capital calls, in the form of the promise to pay off any accumulated losses with future income before receiving any distributions.On the positive side, the 10K does appear to communicate relief in the form of limited and capital expenditures deducted from the NPI calculation. As of January 2018, capital expenditures included in the net profits calculations were limited. The annual limitation, effective January 1, 2018, is the average annual capital expenditure amount for the previous three years. Therefore, the capital expenditure limitation for 2018 is approximately $4.0 million. This limitation is new for 2018.Based upon the NPI calculation, make whole provision for accumulated losses, and the limited capital expenditure protection, the unitholders of WHZT appear to own a working interest in the oil and gas properties versus a royalty interest.Distributions to UnitholderPerhaps part of the publicly traded price activity can be explained by considering the historical distribution pattern to unitholders (Figure 4). Distributions are based upon the NPI formula discussed above. Since its inception in 2012, distributions have been consistent during Q2 2012 through Q3 2014, at which point distributions decline for the remainder of 2014, 2016 and are non-existent for much of 2016. Based on the data available, future distributions appear to be uncertain, erratic and dependent on oil prices, operating expenses and capital expenditures, to name the large items.Figure 4Specific Time HorizonWHZT also has a specific time horizon before the trust will be terminated and shutdown. WHZT will be shut down when the first occurs:(a) the NPI termination date, which is the later to occur of (1) December 31, 2021, or (2) the time when 11.79 MMBOE have been produced from the underlying properties and sold (which amount is the equivalent of 10.61 MMBOE in respect of the Trust’s right to receive 90% of the net proceeds from such reserves pursuant to the NPI), or;(b) the sale of the net profits interest. The Trust is required to sell the NPI and liquidate if cash proceeds to the Trust from the net profits interest are less than $2.0 million for each of any two consecutive years. During the years ended December 31, 2017 and 2016, the Trust received cash proceeds of $6.7 million and $1.9 million, respectively, from the net profits interest. As of the end of 2017, WHZT has received approximately 75% of the MMBOE attributable to the NPI. As of the latest reserve report (year-end 2017) the NPI is projected to receive 10.61 MMBOE prior to the December 31, 2021 date. A liquidation and termination of the trust appears to be within a four-year horizon.Underlying Property Description2The underlying properties consist of certain oil and natural gas producing properties located in the Permian Basin, Rocky Mountains, Gulf Coast, and Mid-Continent areas. The underlying properties include interests in 1,312 gross (376.7 net) producing oil and natural gas wells located in 47 mature fields with established production profiles.As of December 31, 2017, approximately 98.9% of estimated proved reserves attributable to the trust were classified as proved developed producing reserves and 1.1% were classified as proved developed non-producing reserves. For the year ended December 31, 2017, the net production attributable to the underlying properties was 1,168 MBOE or 3,199 BOE/d. Whiting operates approximately 65% of the underlying properties based on the December 31, 2017 reserve report standardized measure of discounted future net cash flows.Figure 5 summarizes estimated proved reserves and the standardized measure of discounted future net cash flows as of December 31, 2017 attributable to (i) the Trust based on the term of its NPI, and (ii) the underlying properties on a full economic life basis (dollars in thousands):Figure 5Trust Rights and RestrictionsSurprisingly, a unitholder within this trust can have significant power, compared to other comparable entities. The Trustee or a Trust unitholder, holding at least 10%, may call meetings of the unitholders. Each Trust unitholder is entitled to one vote for each unit owned and the majority of unitholders can:Dissolve the trustRemove the trustee or the Delaware trusteeAmend the trust agreementMerge or consolidate with another entityApprove the sale of assets in certain circumstances;Agree to amend or terminate the conveyance;AnalysisAccording to the IPO price on March 28, 2012, the net profits interest was given a market value of $418 million. The same properties are given a current market value of $39.6 million six years later. This change represents a decline of 90%. Furthermore, the current market value is approximately $10 million more than the most recent reserve report present value measures ($29.1 million).It is clear the market anticipates positive factors to push the underlying property cash flows higher compared to the 2017 reserve report. Based upon the latest 10K, we know the additional future cash flow will not come from new wells, as all wells within the property are classified as PDP or PDNP. No PUD’s or other classification of reserves has been identified. Therefore, the increase in cash flows is coming from higher commodity prices, lower operating costs or lower development costs.Either way, with over six years of production history, it appears optimistic that operations will become more efficient in years seven, eight and nine than they have been in years one through six. This leaves future commodity prices as the only logical lever left to base an increase. Additionally, with the market value holding close to $40 million dollars, an investment of approximately 51% or nearly $20 million, would allow for significant powers within the Trust. Given that the market value appears to be higher than the underlying asset value, a strong strategic case would need to be presented for that action to be logical.ConclusionThis discussion is an example of the importance of understanding the details about your royalty interest or in the case of WHZT, your net profits/working interest. Consideration must be given to the underlying assets, current and future wells, outlook for oil and gas prices, rights and restrictions of the mineral rights owner, lease terms, distributions, etc. WHZT is also an example of why some publicly traded royalty trusts are not appropriate to use for comparison. WHZT may best be used for a working interest comparable but definitely not a royalty interest comparable.Mercer Capital is an employee-owned independent financial advisory firm with significant experience (both nationally and internationally) valuing assets and companies in the energy industry (primarily oil and gas, bio fuels and other minerals).  Our oil and gas valuations have been reviewed and relied on by buyers and sellers and Big 4 Auditors. As a disinterested party, we can help you understand the fair market value of your royalty interest and provide confidence that you get a fair price for your interest. Contact anyone on Mercer Capital’s Oil & Gas team to discuss your royalty interest valuation questions in confidence.1 Capital IQ2 WHZT 2017 10K
Eagle Ford – 2017/2018 Acquisition & Divestiture Commentary
Eagle Ford – 2017/2018 Acquisition & Divestiture Commentary
Transaction activity in the Eagle Ford Shale has been fairly steady over the past 12 months, with the majority of transactions in the $100-300 million range.  The seller’s rationale has most often been about balance sheet management and re-allocation to other plays, usually the Permian Basin.  However, the Eagle Ford area has some quality economics of its own, which has been attractive to buyers.  Many argue it has the best shale production economics in the U.S. next to the Permian Basin.  These differing strategy based swaps have been at the heart of transaction flow.  This has also led to consideration that Devon may sell its Eagle Ford division in search of returns elsewhere.  The chart below, drawn from Mercer Capital’s newsletter, shows some details in regards to the transactions including some comparative valuation metrics.Magnolia – Blank Check Company forms a New South Texas ProducerThe largest transaction in the past year was the recent announcement of a special purpose acquisition entity (“SPAC”) coming to an agreement with certain Enervest controlled funds.  The result of the merger is the creation of a pure play Eagle Ford and Austin Chalk company with 360,000 net acres in South Texas.   The majority of that acreage is in what is known as the Giddings field which is an oil play in the Austin Chalk (mostly held by production).Break-evens are claimed to be in the low $30’s per barrel with one year (or less) paybacks in Karnes and Giddings field.  Magnolia1 is led by a former Occidental Petroleum executive, Steve Chazen, who has both short and long-term optimism for the opportunity.  Estimated EBITDA for 2018 is projected at $513 million including approximately $240 million of cash flow after capital expenditures.Highest and Best EconomicsDenver-based Sundance Energy Australia Ltd. struck a deal with Pioneer Natural Resource Co. to buy almost 22,000 acres and 1,800 boe/d of production in the Eagle Ford Shale, bolting on to an existing leasehold in South Texas.The pure-play Eagle Ford player agreed to pay $221.5 million for the leasehold, which runs through McMullen, Atascosa, LaSalle and Live Oak counties. The transaction would give Sundance 56,600 total acres in the play, with an inventory of 716 gross undrilled locations.Meanwhile, Pioneer was exiting to focus on the Permian Basin.  Pioneer announced in February it would put most of its resources going forward into the Permian and planned to sell nearly all “non-Permian” projects, including in the Eagle Ford, Raton Basin, and West Texas Panhandle.  The table below demonstrates why its desire to focus on the Permian was warranted.  However, one thing to note is that purchasing acreage in the Permian is much more expensive than the Eagle Ford, so drilling most likely needs to be based on existing acreage positions. Overall, the Eagle Ford’s economics are improving (Venado – a KKR backed Austin firm, made a $765 million purchase from Cabot that was based on this optimism). About 61,500 net acres of the Venado position, which is located primarily in Frio and Atascosa counties in South Texas, is operated and about 9,400 net acres are non-operated. Production from the properties during third-quarter 2017 was 15,656 barrels of oil equivalent per day. An interesting discussion on this acquisition can be found in this video: ?? Have a great week! Endnote1 In case one was wondering - Chip and Joanna Gaines are not involved.
Capital Structure in 30 Minutes Whitepaper
Capital Structure in 30 Minutes Whitepaper
In this post, we share a recent whitepaper: "Capital Structure in 30 Minutes." Capital structure decisions have long-term consequences for shareholders.  Directors evaluate capital structure with an eye toward identifying the financing mix that minimizes the weighted average cost of capital.  This decision is complicated by the iterative nature of capital costs: the financing mix influences the cost of the different financing sources.  While the nominal cost of debt is always less than the nominal cost of equity, the relevant consideration for directors is the marginal cost of debt and equity, which measures the impact of a given financing decision on the overall cost of capital.  The purpose of this whitepaper is to equip directors and shareholders to contribute to capital structure decisions that promote the financial health and sustainability of the company. This whitepaper is the second in the "Corporate Finance in 30 Minutes Series." Learn more about the whitepaper series below. Corporate Finance in 30 MinutesIn this whitepaper, we distill the fundamental principles of corporate finance into an accessible and non-technical primer.Capital Structure in 30 MinutesThrough this whitepaper, we equip directors and shareholders to contribute to capital structure decisions that promote the financial health and sustainability of their companies.Capital Budgeting in 30 MinutesCapital Budgeting in 30 Minutes assists directors and shareholders evaluate proposed capital projects and contribute to capital budgeting decisions that enhance value.Distribution Policy in 30 MinutesOf the three primary corporate finance decisions, distribution policy is the most transparent to shareholders. This whitepaper helps directors formulate and communicate a distribution policy that contributes to shareholder wealth and satisfaction.
Was 2014 a Lesson Learned?
Was 2014 a Lesson Learned?
Overview of the Macro Oil and Gas Environment at the End of 1Q 2018The oil and gas market continued to show improvement in the first quarter of 2018.  Positive momentum in production growth in the U.S. continued and prices increased from an average of $55 in Q4 2017 to an average of $63 in Q1 2018.   Mercer Capital’s Senior VP, Grant Farrell, at the beginning of the quarter said, “a repeat of 2017 would be a welcomed event” and it appears we are on track. Oil prices are ticking up, domestic production has increased to a 50 year high, and the U.S. is exporting more crude oil than ever before.Too Good to be TrueIf you are like me, you can’t ignore the wary feeling in your gut that makes you ask, “Is it too good to be true?”According to Reuters, global inventories could increase due to the rapid increase in production in the U.S. which “could well outweigh any pick-up in demand.” Rig counts in 2018 were expected to increase to 945 active rigs. [1] However, Baker Hughes reports that we have already met this target and currently have 993 active rigs versus 824 a year ago. Have we already forgotten the lesson we learned in 2014: too much supply, too fast leads to a decline in prices? Additionally, what will happen to demand as transportation becomes more fuel efficient and we shift further away from oil in favor of renewable energy resources? Easing ConcernsThankfully, I am not the only one asking these questions. A survey of oil and gas professionals in the February 2018 Issue of the Oil and Gas Journal showed that 63% of oil and gas senior professionals are optimistic about 2018.  However, this optimism does not stem from a forecasted favorable price environment.  Rather, their confidence is supported by the knowledge that they can now operate profitably in a $55 per barrel price environment.[2]   Oil and gas exploration companies today are more cost-efficient than ever.   The collapse in prices in mid-2014 gave companies two options: adapt to the new price environment or go away.  Today we are left with a more cost-aware sector that has used technology to reduce risks and cut costs.Further, domestic E&P companies today have the ability to quickly adjust their operations in response to price changes.  Jude Clemente, a recent contributor for Forbes recently wrote, “The U.S. has now become the world's swing oil producer and is the main factor that will limit how high prices can go.”BP Chief Economist Spencer Dale recently responded to similar questions asked across the energy industry: “Will oil and gas lose dominance to renewable fuels in the future?”  BP argues that crude oil demand will continue to increase in the foreseeable future but will begin to reach a plateau in the next twenty years.  While renewable energy is the fastest growing energy source, developing nations across the world will drive energy demand in the future.  The mix of crude oil and renewable energy will shift, and crude oil will likely meet 85% of oil demand in 2040 instead of 94% of demand today.  This does not, however, mean demand for crude oil will disappear.OverviewThe forecast for the oil and gas industry in 2018 was positive and we seem to be meeting or even exceeding investor expectations.  The U.S. is expected to give up its title of the largest crude oil importer and exports are expected to continue growing as new pipelines and export terminals allow for increased capacity.The positive momentum in the industry is being reflected in private company valuations both as a result of improved earnings forecasts and reductions in risk.  Growth in production and increases in price are increasing revenue, and more of the top line is flowing down to net income as companies have cut costs.  Earnings improvement is being magnified by the recent tax cuts which have significantly increased net income.  Further, the risk profiles of E&P companies have improved as companies are better equipped to handle price volatility and E&P companies are generally taking on projects with shorter payback periods.Mercer Capital has significant experience valuing assets and companies in the energy industry. Because drilling economics vary by region it is imperative that your valuation specialist understands the local economics faced by your oilfield service company.  Our oil and gas valuations have been reviewed and relied on by buyers and sellers and Big 4 Auditors. These oil and gas related valuations have been utilized to support valuations for IRS Estate and Gift Tax, GAAP accounting, and litigation purposes. Contact a Mercer Capital professional today to discuss your valuation needs in confidence.Endnote[1] US oil, gas industry capital spending to increase in 2018. US Oil and Gas Journal.March 2018. [2] Survey: Oil, gas professionals express optimism for 2018 challenges.  Oil and Gas Journal. February 2018
Before Selling Your Oil and Gas Royalty Interest Read This
Before Selling Your Oil and Gas Royalty Interest Read This
There are many reasons that you may want to sell your oil and gas royalty interest, but a lack of knowledge regarding the worth of your royalty interest could be very costly.  Whether an inflow of cash would help you make ends meet or finance a large purchase; you no longer want to deal with the administrative paperwork or accounting cost of reconciling monthly revenue payments; or you would prefer to diversify your portfolio or move your investments to a less volatile industry, understanding how royalty interests are valued will ensure that you maximize the value.There is a market for royalty interests, making them fairly liquid; therefore, most of the time, the difficulty is not finding a buyer, but determining whether the buyer’s offer is appropriate.Given that many royalty owners have little connection with the oil and gas industry aside from the monthly payments they receive, buyers may bid substantially below a royalty’s fair market value hoping to earn a profit at the expense of an uninformed seller. As such, it is critical that royalty owners looking to liquidate their interest understand its value to ensure that they can identify legitimate bids.Before attempting to sell your mineral interest, understand these issues.Understand What You Are SellingA royalty interest represents a percent ownership in the revenue of an E&P company.  Royalty interest owners have no control over the drilling activity of the operator and do not bear any costs of production. Royalty interest owners only receive revenue checks when their operator is producing minerals but see no monthly payments when production is suspended.1Recognize Production and Price as Value DriversThe value of a royalty interest is based on the present value of expected future cash flows, which are a percentage of an operator’s revenue.An operator’s revenue is dependent upon production and price.  Thus, when determining the value of a royalty interest, it is critical to understand a well’s future potential for production and the market forces that affect price.Production: The Decline Curve’s ImpactAs oil and gas is extracted from a well, its production declines over time.  Every well has a unique decline curve which dictates production. A decline curve graphs crude oil and natural gas production and allows us to determine a well’s Estimated Ultimate Recovery (EUR).   A variety of factors can affect the shape of a well’s decline curve.  For example, decline curves are generally much steeper if the well is drilled using unconventional techniques, like horizontal drilling, or hydraulic fracturing. When determining the value of an oil and gas royalty interest, it is critical to understand a well’s EUR because the value of your royalty interest is dependent upon future production.Price: Local and Global Market ForcesOil and gas prices are affected by both global and local supply and demand factors.  The oil and gas industry is characterized by high price volatility.  The size and global nature of this market mean that these prices are influenced by countless economic – and sometimes political – factors affecting individual producers, consumers, and other entities that comprise the global market.  Most operators, however, sell their oil and gas at a slight discount or premium to the NYMEX because of local surpluses or shortfalls.  Thus, it is important to understand the local market as well.Understand Location’s ImpactDrilling economics vary by region. There are geological differences between oilfields and reserves that make it harder to drill in some places than others. Whereas some wells can be drilled using traditional, conventional techniques like vertical drilling, less permeable shale wells must be drilled using unconventional methods, like horizontal drilling or hydraulic fracturing. These unconventional methods tend to bear higher operating costs. Location also tends to influence drilling and transportation costs, ultimately making breakeven prices and profits vary across and within regions. Although a royalty interest owner is paid before any operating expenses are accrued, an operator considers break-even pricing when determining whether to continue operating a well or suspending operations. Accordingly, the value of any royalty interest is strongly influenced by its location, and it is important to consider geological differences when valuing any mineral interest.Proceed with CautionWhile there are legitimate online brokers who will buy your royalty interest for a fair price, it is important to be on the lookout for those who aim to profit at your expense.Beware of online royalty brokers who only consider rules of thumb such as 4x to 6x annual revenue. While industry benchmarks can be a helpful aid, they should not be relied upon solely to determine value, as they do not consider specific well economics.If the entity valuing your interest is also an interested party, it is critical to remember that they have an incentive to quote a low value.Mercer Capital is an employee-owned independent financial advisory firm with significant experience (both nationally and internationally) valuing assets and companies in the energy industry (primarily oil and gas, bio fuels and other minerals).  Our oil and gas valuations have been reviewed and relied on by buyers and sellers and Big 4 Auditors.As a disinterested party, we can help you understand the fair market value of your royalty interest and ensure that you get a fair price for your interest. Contact anyone on Mercer Capital’s Oil & Gas team to discuss your royalty interest valuation questions in confidence.End Note1 For more information on mineral interests see our post, Three Types of Mineral Interests.
EP Second Quarter 2018 Region Focus Permian Basin
E&P Second Quarter 2018

Region Focus: Permian Basin

Region Focus: Permian Basin // Domestic oil production has increased significantly over the last few years primarily due to the shale boom in the Permian Basin.
Eagle Ford Q1 2018
Eagle Ford Q1 2018

Lower Breakevens Yet Some Plan Fewer Wells

A milestone worth noting:  The EIA recently announced that 2017 marked the first time since 1957 that U.S. natural gas exports exceeded imports.  The economics of the Eagle Ford Shale have been steadily improving for the past year.  While the Permian has been receiving the most attention given its low-cost economics and large well potential, the Eagle Ford (particularly its oil window) has increased well production whilst dropping its costs.  However, based on recent announcements, many companies will be reducing the number of wells drilled in 2018 as compared to 2017.Breakeven PricesAs recently as a year ago, several companies and outlets reported breakeven oil price estimates in the low-to-mid $40s.  Recently, several operators in the Eagle Ford are estimating breakeven as low as $28 and many around $35.  This is a significant drop and points to anticipated efficiencies in drilling and completion costs. This is positive, but the trend is generally moving away from the Eagle Ford relative to other plays.  According to IHS Markit, “only 1,415 new wells were brought online in 2016 compared to 2,717 in 2015 and 4,040 in 2014". IHS also noted "the play’s overall annual base has been decreasing year-over-year as a result of production coming from older wells. The annual base decline in the Eagle Ford in 2016 was 46% compared to 49% and 50% in 2015 and 2014, respectively.” IHS Markit also reported that a key reason for the decline in activity in the Eagle Ford is due to the rising interest in the Permian Basin and STACK/SCOOP plays, which have attracted the interest of key Eagle Ford players, including Pioneer Resources, Devon Energy, and Marathon Oil. TPG AcquisitionIt is notable, and probably not a coincidence, that TPG, the most optimistic company per the Figure above, last week made one of the largest acquisitions in the Eagle Ford in the past few years (we will discuss this acquisition and other recent ones in more detail in a few weeks.  Stay tuned.).2018 PlansTis the season for 2018 guidance and several of the major Eagle Ford shale operators have given theirs.  As mentioned, several companies (Sanchez, Chesapeake, and Carrizo) are decreasing their estimates for new well compared to last year, but are increasing their capex budgets.  Overall,  EOG and Sanchez have increased their rig presence as of last week, but those figures fluctuate even week-to-week.  EOG is leading the way in its activity from well count to acreage.  In terms of new activity planned in 2018, it is the most aggressive of the four companies we follow (see Figure below).  It’s also notable that EOG continues to test its position in the Austin Chalk formation – completing four wells in 4Q2017.Bill Thomas, the company's chairman and CEO, said last year was a success, considering lingering weakness in crude oil prices and headwinds from the series of hurricanes that hammered southern U.S. shale basins in late 2017."EOG emerged from the industry downturn in 2017 with unprecedented levels of efficiency and productivity, driving oil production volumes to record levels with capital expenditures approximately one half the prior peak," he said in a statement. Carrizo’s strategy revolves around “multipads” wherever possible in the Eagle Ford.  In 2018, Carrizo is completing a 16-well multipad utilizing three completion crews.  In addition, Carrizo sees more than 700 remaining PUDs in the core of its Eagle Ford position at a 330-500 foot spacing profile (depending on the geology of the project area). Chesapeake, meanwhile, continues to manage its balance sheet with asset sales and tempered activity which makes its activity profile a little harder to discern. PerformanceWhat does this mean for performance?  Well, the past week has been good to a number of producers, but it comes after a subpar stock price performance for everyone on this list not named EOG.However, if efficiencies compound for Eagle Ford players, this chart could look very different a year from now.  Time will tell.Have a great week!
How to Value an Oil and Gas Refinery
How to Value an Oil and Gas Refinery
Because of the historical popularity of this post, we revisit it this week. Originally published last summer, this post helps you, the reader, understand the issues to consider when valuing an oil and gas refinery, as well as the appropriate valuation approaches. When valuing a business, it is critical to understand the subject company’s position in the market, its operations, and its financial condition. A thorough understanding of the oil and gas industry and the role of refineries is important in establishing a credible value for a business operating in the oil and gas refining space.Oil and Gas Supply ChainThe oil and gas industry is divided into three main sectors:Upstream (Exploration and Production)Midstream (Pipelines)Downstream (Refineries) Exploration and production (E&P) companies search for reserves of hydrocarbons where they can drill wells in order to retrieve crude oil, natural gas, and natural gas liquids.  E&P companies then sell the commodities to midstream companies who use gathering pipelines to transport the oil and gas to refineries.  Refiners convert raw crude and natural gas into products of value, such as transportation fuels.Oil and Gas Refinery OperationsCrude oil itself has little end use.  Refiners create value by converting crude oil into various usable products.  Transportation fuels, such as gasoline, diesel, and jet fuel, are some of the most commonly produced refined products.  Other refined products include heating and lighting fluid, such as kerosene, lubricating oil and waxes, and asphalt.  Refineries are capital intensive and their configuration depends largely on their physical location, available crude oils, product requirements, and environmental standards.Valuing an oil and gas refinery requires the consideration of a wide range of issues (far too many to list in full here), with primary considerations as outlined below.The price of inputs. The price of crude oil fluctuates due to changes in world demand and supply.  Many refiners hold large volumes of crude inventory, but as the price of crude oil fluctuates, refiners face risk associated with the falling value of their inventory. Thus, in order to reduce risk refiners should shorten their timeline from purchasing crude oil to selling the finished product and/or use derivatives to hedge the risk associated with volatile oil prices.The price of refined products. There are four main components to refined product prices: (1) Crude Oil Prices, (2) Wholesale Margins, (3) Retail Distribution Costs, and (4) Taxes.  Generally, input prices and wholesale margins drive fluctuations in product prices as the last two are relatively stable.  However, President Trump has indicated that he hopes to lower corporate taxes.Crack spread. A refiner’s margins are generally determined by the crack spread, which measures the prices of refined products compared to the cost of crude oil.  The price of transportation fuels generally moves in sync with the prices of crude oil, but the price of some refined products such as asphalt and lubricating oils is not as closely correlated with crude oil price changes.Environmental regulation. The refining industry has historically been heavily regulated.  Regulations such as the RTR & NSPS aim to control air pollution from refineries and provide the public with information about refineries’ air pollution.  President Trump is working to establish a more energy friendly environment and has signaled his intention to sign the repeal of many methane emission regulations if the repeal is passed through both Houses of Congress.Heavy vs. light crude. Most U.S. refineries were built to process heavy crude.  However, the onset of U.S. shale drilling has led to a surplus of light sweet crude that U.S. refineries were not originally built to process.  While the refining process of heavy and light crude is generally the same, the refining of light crude is less costly.Oil and Gas Refinery Financial AnalysisWhen valuing a business, it is critical to understand the subject company’s financial condition. A financial analyst has certain diagnostic markers that tell much about the condition of a business.Balance Sheet. The balance sheet of a refinery is dominated by inventory and fixed assets.  According to RMA’s annual statement studies, 16.3% and 32.2% of petroleum refineries’ assets are inventory and fixed assets, respectively.1   Because refining is a capital intensive business, it is important to consider the current operating capacity of a company’s fixed assets in order to determine if future growth will require significant capital expenditures.  If a refinery hopes to expand refinery throughput beyond the current refining capacity, it will have to invest in more equipment.Income Statement.  The development of ongoing earning power is one of the most critical steps in the valuation process, especially for businesses operating in a volatile industry environment.  Cost of goods sold account for approximately 75% of sales according to the RMA data.  Thus it is important to consider possible supplier concentrations when analyzing the income statement because disruptions in the supply chain can have significant income statement impacts to oil refineries.How Does Valuation Work?There are fundamentally three commonly accepted approaches to value: asset-based, market, and income.  Each approach incorporates procedures that may enhance awareness about specific business attributes that may be relevant to determining the final value. Ultimately, the concluded valuation will reflect consideration of one or more of these approaches (and perhaps several underlying methods) as being most indicative of value for the subject interest under consideration.The Asset-Based ApproachThe asset-based approach can be applied in different ways, but in general, it represents the market value of a company’s assets minus the market value of its liabilities. Investors make investments based on perceived required rates of return, and only look at assets as a source of rate of return. Oil and gas refineries are asset intensive businesses. They have distillers, crackers, cokers, and more.  While an asset value consideration can be a meaningful component of the overall valuation of an oil and gas refinery, it is essentially the income generated by these assets that typically drives the value of a business. For this reason, the asset-based approach is typically not the sole (or even primary) indicator of value.The Market ApproachThe market approach utilizes market data from comparable public companies or transactions of similar companies in developing an indication of value. In many ways, this approach goes straight to the heart of value: a company is worth what someone is willing to pay for it.In the downstream oil and gas sector, there are ample comparable public companies that can be relied on to provide meaningful market-based indications of value. Such options are Alon US Energy Inc., CVR Refining, LP, Valero Refining, and Western Refining.  Acquisition data from industry acquisitions (typically a median from a group of transactions) can be utilized to calculate a valuation multiple on the subject company’s performance measure(s). This will often provide a meaningful indication of value as it typically takes into account industry factors (or at least the market participants’ perception of these factors) far more directly than the asset-based approach or income-based approach.   Additionally earnings multiples such as EV/ EBITDA can be used to calculate indication of values.The market-based approach is not a perfect method by any means. For example, industry transaction data may not provide for a direct consideration of specific company characteristics. Say a company is a market leader and operates in a prime geographic market. Since the market and the specific company are relatively more attractive than the average transaction, the appropriate pricing multiple for this company is likely above any median taken from a group of industry transactions. Additionally, many companies in the oil and gas industry are vertically integrated and have significant midstream or marketing operations in addition to their refining operations.  For example, Marathon Petroleum Company is a leading refiner in the US, but is also a marketer of refined products and has significant midstream operations.  Clearly, the more comparable the companies and the transactions are, the more meaningful the indication of value will be.  When comparable companies are available, the market approach can provide a helpful indication of value and should be used in determining the value of a refinery.The Income ApproachThe income approach can be applied in several different ways. Generally, such an approach is applied through the development of an ongoing earnings or cash flow figure and the application of a multiple to those earnings based on market returns. An estimate of ongoing earnings can be capitalized in order to calculate the net present value of an enterprise.  When determining ongoing earnings historical earnings should be analyzed for non-recurring and non-normal income and expenses which will not affect future earnings. The income approach allows for the consideration of characteristics specific to the subject business, such as its level of risk and its growth prospects relative to the market through the use of a capitalization rate.Income is the main driver of value of a business; thus, the income approach should be considered when determining the value of your business.Synthesis of Valuation ApproachesA proper valuation will factor, to varying degrees, the indications of value developed utilizing the three approaches outlined. A valuation, however, is much more than the calculations that result in the final answer. It is the underlying analysis of a business and its unique characteristics that provide relevance and credibility to these calculations. This is why industry “rules-of-thumb” (be they some multiple of revenue, earnings, or other) are dangerous to rely on in any meaningful transaction. Such “rules-of-thumb” fail to consider the specific characteristics of the business and, as such, often fail to deliver insightful indications of value.An owner who is contemplating any kind of transaction or agreement based on value needs to know what their business is worth.  Whether you are selling out or selling in, knowing the fair market value of your business will let you evaluate whether or not an offer for your company is reasonable.  Additionally, many business owners fail to understand the valuation implications of buy-sell agreements. If you have other shareholders in your business who are non-family, and maybe some who are, you probably have some kind of buy-sell agreement between the shareholders that describes how the business (or business interests) will be valued in the event of a shareholder dispute, death, or departure from the business (even on friendly terms). A business owner executing or planning a transition of ownership can enhance confidence in the decisions being made only through reliance on a complete and accurate valuation of the business.Mercer Capital has long promoted the concept of managing your business as if it were being prepared to sell. In this fashion you promote the efficiencies, goals and disciplines that will maximize your value. Despite attempts to homogenize value through the use of simplistic rules of thumb, our experience is that each valuation is truly unique given the purpose for the valuation and the circumstances of the business.Mercer Capital has experience valuing businesses in the oil and gas industry. We hope this information, which admittedly only scratches the surface, helps you better shop for business valuation services and understand valuation mechanics. We encourage you to extend your business planning dialogue to include valuation, because sooner or later, a valuation is going to happen. Proactive planning and valuation services can alleviate the potential for a negative surprise that could complicate an already stressful time in your personal and business life.For more information or to discuss a valuation or transaction issue in confidence, do not hesitate to contact us at 901.685.2120.End Note1 2016-2017 RMA Statement Studies. NAICS #324110. Companies with greater than $25 million in sales
The 2018 Outlook for the Refining Industry
The 2018 Outlook for the Refining Industry
Over the last six months of fiscal 2017, changes in the oil & gas market led to increasing refinery revenues and the expansion of margins.   Earnings in the refining industry increased in fiscal 2017 as refined product prices increased, the crack spread widened, and volumes sold increased as demand rose.  With recent gains in the industry and the effect of the Tax Cuts and Jobs Act of 2017, refiners should sail steadily through 2018.   However, the future impact of many regulations surrounding the oil & gas industry is still uncertain.Factors Providing Positive Momentum in 2018Tax Cuts and Jobs Act of 2017We start with the obvious.  The Tax Cuts and Jobs Act of 2017 will increase net earnings.  Many clients have called to ask, “What is the impact of the tax cuts on my company?  If taxes decrease, will the value of my company increase?”As Travis Harms, Senior VP at Mercer Capital, said in his recent presentation on the tax reform.“Simply put, we can say, yes a lower corporate tax rate will make corporations more valuable, all else equal. Will all else always be equal? No. Appraisers will need to carefully consider the effect of the new tax law not just on rates, but on growth expectations, reinvestment decisions, use of leverage, operating margins, and the like for individual companies.”As noted by George Damiris, CEO and President of Holly Frontier, on HFC’s fourth quarter earnings call, “The reforms to the U.S. tax code encourage capital investments and lower the corporate rate to better enable manufacturers to compete in the global market.”Price of Crude OilEven if OPEC maintains production cuts, rising U.S. shale oil output is thought to temper the results of OPEC’s reduction in supply.   This will likely result in falling or stable oil prices.  Because refined product prices often lag crude oil, the crack spread should widen or at least remain steady in 2018.Gregory Goff, CEO of Andeavor explains, “Last year, primarily because of rising crude prices throughout the year, we didn't have any periods of time where the market was impacted by having a declining crude price and the lag effect of that. So, organically, the growth was muted a little bit by the weaker margin environment.”Analysts polled by Reuters believe that oil prices will not continue to rise past the first quarter of 2019, because U.S. production will offset production declines by OPEC.   We believe that oil price decreases could lead to higher margins in the refining industry over 2018.   Holly Frontier, in their fourth quarter earnings call, provides an outlook of crude spread and product crack improvements in 2018.Friendly Environment for Oil & Gas CompaniesPresident Trump is positioning the U.S. to offer a more energy-friendly environment.  The deregulation of the oil & gas industry was generally applauded on earnings calls at the beginning of 2018 and industry executives believe it will provide a more efficient marketplace for refiners.Factors Providing Negative Momentum in 2018The Future of the RFS is Still UncertainThe final Renewable Fuel Standards (RFS) for 2018 were released on November 30, 2017 and contained a slight reduction in volume requirements. This will provide some relief for refiners. However, refiners have made it clear that a long term solution regarding the RFS is needed.  While large integrated refiners have the capability to blend their own petroleum products with renewable fuels, small and medium sized merchant refiners do not have this capability and are required to purchase RINS, which have significantly increased in price. The cost of RINs has hurt the profits of merchant refiners over the last few years and will continue to do so unless the standards are reworked or repealed.Potential Tariffs Could Hamper Exports and Increase CostsAs noted in the EIA’s Annual Energy Outlook 2018, domestic consumption of petroleum products is expected to decline due to increases in fuel efficiency.  However, refinery utilization is expected to remain stable due to expected increases in petroleum product exports in the future.  The imposition of tariffs on steel and aluminum imports does not directly affect U.S. oil refineries.  However, steel is one of the most wildly used metals in the oil & gas industry.  If the impacts of tariffs are passed onto the consumer, then the oil & gas industry could realize higher costs of steel.Further, there is concern of retaliation and trade wars which could hamper growth in the industry if tariffs on U.S. products are imposed by retaliating countries.  Over 33% of U.S. exports of refined products are sent to Mexico and Canada, who are currently except from the tariffs.  However, growth in demand from other countries could be dampened by the soon-to-be enforced tariff.What Does This Mean for Refinery Valuations?Consistent with the view that markets are generally efficient, the new lower corporate tax rates seem to have been priced into the market shortly after election day. Thus when the tax plan passed, the expected increase in after-tax earnings did not come as a surprise to the market.  Additionally, there has been talk of crude price decreases since U.S. production broke a production record 10 million bpd in November 2017. This was the first time the U.S. broke this record in 48 years.   Since then it has been thought that the U.S. is on track to surpass Saudi Arabia and Russia in crude oil production, making OPEC’s production cuts less impactful.Much of the positive momentum in the refining industry was expected by industry analysts.  Valuation multiples have remained relatively stable over the last six months.  EV multiples are trending between 7.5x to 8.5x EBITDA.  According to Moody’s, “Outlook for the refining and marketing sector is stable, with earnings likely to increase 5-7% in 2018.”  As earnings increase, company valuations will likely increase.  However, refiner’s profit margins are highly dependent on management decisions.  The degree of the effects of the new tax plan on your business depends on many company-specific decisions, such as the use of operating leverage.  Further, management decisions regarding inventory management and price hedging can be the “make or break” in unexpected downturns.  In order to understand the impact of these factors on the value of your refinery, you should contact an industry valuation specialist.A Plug for Mercer CapitalMercer Capital has significant experience valuing assets and companies in the energy industry. Our oil & gas valuations have been reviewed and relied on by buyers and sellers and Big 4 Auditors. These oil & gas related valuations have been utilized to support valuations for IRS Estate and Gift Tax, GAAP accounting, and litigation purposes. We have performed oil & gas valuations and associated oil & gas reserves domestically throughout the United States and in foreign countries. Contact a Mercer Capital professional today to discuss your valuation needs in confidence.
What Is a Reserve Report? (Part II)
What Is a Reserve Report? (Part II)
This is the second of multiple posts discussing the most important information contained in a reserve report, the assumptions used to create it, and what factors should be changed to arrive at Fair Value[1] or Fair Market Value[2].In our first post, we discussed the purpose of a reserve report, why they are important, how they are prepared and what is contained in the report. In this post, we discuss two of the most important inputs that go into every reserve report: production and pricing and why it may be appropriate to make adjustments to these inputs for purposes of Fair Value or Fair Market Value.What Is a Reserve Report?To recap, a reserve report is a reporting of remaining quantities of minerals which can be recoverable over a period of time. The current rules define these remaining quantities of mineral as reserves. The calculation of reserves can be very subjective, therefore the SEC has provided, among these rules, the following definitions, rules and guidance for estimating oil and gas reserves:Reserves are “the estimated remaining quantities of oil and gas and related substances anticipated to be economically producible.The estimate is “as of a given date.”The reserve “is formed by application of development projects to known accumulations.” In other words, production must exist in or around the current project.“In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production of oil and gas.”There must also be “installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.”Therefore, a reserve report details the information and assumptions used to calculate a company’s cash flow from specific projects which extract minerals from the ground and deliver to the market in a legal manner. In short, for an E&P company, a reserve report is a project-specific forecast. If the project is large enough, it can, for all intents and purposes, become a company forecast.ProductionIn our first post, we summarized 12 significant assumptions made in a reserve report. Production is an important input that goes into every reserve report. Production revolves around the estimate of current and future oil and gas removed from the resource play. To organize the certainty of future production forecasts, the SEC requires the use of three categories: (1) Proved, (2) Probable, and (3) Possible. These categories have the following definition:Proved: An estimate that is reasonably certain. There must be at least a 90% probability that the actual quantities recovered will equal or exceed the estimate. Therefore, economic producibility: proved oil and gas reserves are those quantities which can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs and under existing economic conditions, operating methods and government regulations. Economic producibility must be based on existing economic conditions.Probable: An estimate that is as likely as not to be achieved and when using a probabilistic method, there must be at least a 50% probability that the actual quantities recovered will equal or exceed the estimate.Possible: An estimate that might be achieved, but only under more favorable circumstances than are likely and, when using a probabilistic method, there must be at least a 10% probability that the actual quantities recovered will equal or exceed the estimate. The production assumptions might be the most important assumption within the reserve calculation. Careful attention should be utilized in the estimation of future production. Use of a certified reserve engineer is highly encouraged for this assumption. If the production and decline curves are prepared in an appropriate manner, no adjustment to this input is needed for Fair Value or Fair Market Value, unless hypothetical conditions are to be applied. In which case, adjustments need to be made for matching the valuation date with the production forecast date.PricingReserve reports allow for two types of pricing assumptions for the future estimate at which the minerals are assumed to be sold in the market place. The first SEC rule states (1) companies should use the average of the first day of the month price for the previous 12 months; therefore, an average of the previous year (historical pricing); and (2) the SEC also allows for use of contract prices if future production is contractually guaranteed at certain pricing. This type is forward-looking.For the most part, reserve reports use historical prices in their analysis. This assumption should be challenged for possible replacement in Fair Value or Fair Market Value analysis.In these types of situations, future expectation is appropriate to utilize in the reserve calculation. Therefore, a forward-looking price assumption, frequently called a “price deck,” should be considered.Forward-looking price assumptions come in the form of futures contracts which are based on certain amounts of crude oil/natural gas delivered in certain future months. These types of futures contracts are traded daily on various exchanges[3] and include contracts for delivery as far out as 60 months or longer in some instances.Therefore, with the available information and forward-looking purpose of Fair Value and Fair Market Value analyses, strong consideration should be made to replace a historical price deck with a forward-contract price deck. Additionally, incorporation of differentials and local pricing should also be considered when using a price deck based on futures contracts.A Plug for Mercer CapitalMercer Capital has significant experience valuing assets and companies in the energy industry. Because drilling economics vary by region it is imperative that your valuation specialist understands the local economics faced by your E&P company.  Our oil and gas valuations have been reviewed and relied on by buyers and sellers and Big 4 Auditors. These oil and gas related valuations have been utilized to support valuations for IRS Estate and Gift Tax, GAAP accounting, and litigation purposes. We have performed oil and gas valuations and associated oil and gas reserves domestically throughout the United States and in foreign countries. Contact a Mercer Capital professional today to discuss your valuation needs in confidence.Endnotes[1] “The price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.” – FASB Glossary[2] “The price at which the property would change hands between a willing buyer and a willing seller, neither being under any compulsion to buy or to sell and both having reasonable knowledge of relevant facts” – U.S. Treasury regulations 26 C.F.R. sec. 20.2031-1(b)[3] Chicago Mercantile Exchange, New York Mercantile Exchange, Intercontinental Exchange
Valuing Oil & Gas Reserves (Part II)
Valuing Oil & Gas Reserves (Part II)
Don Erickson, Managing Director of Mercer Capital, educates the public on valuation methodologies and trends impacting various industries. One such industry is Oil & Gas. In the second part of this two-part slide deck, he discusses the basics of how to value oil & gas reserves. Structured in two parts, this slide deck was originally presented to notable professionals in the valuation industry and is designed as a high level overview of the technological and production method changes currently employed by the oil and gas industry. Mercer Capital’s goal with this slide deck is to give the public a vocabulary and conceptual framework for thinking about valuation issues and challenges within the industry given it is prone to volatile swings in commodity prices. Mercer Capital has significant experience valuing assets and companies in the oil and gas industry, primarily oil and gas, bio fuels and other minerals. We also provide financial education services to family businesses.  We help family ownership groups, boards, and management teams align their perspectives on the financial realities, needs, and opportunities of the business. Contact a Mercer Capital professional today to discuss your needs in confidence.
Valuing Oil & Gas Reserves (Part I)
Valuing Oil & Gas Reserves (Part I)
Don Erickson, Managing Director of Mercer Capital, educates the public on valuation methodologies and trends impacting various industries. One such industry is Oil & Gas. In this slide deck, he discusses the main drivers impacting the oil and gas pricing environment over the previous decade and the implications to valuing reserves. Structured in two parts, this slide deck was originally presented to notable professionals in the valuation industry and is designed as a high level overview of the technological and production method changes currently employed by the oil and gas industry. Mercer Capital’s goal with this slide deck is to give the public a vocabulary and conceptual framework for thinking about valuation issues and challenges within the industry given it is prone to volatile swings in commodity prices. Mercer Capital has significant experience valuing assets and companies in the oil and gas industry, primarily oil and gas, bio fuels and other minerals. We also provide financial education services to family businesses.  We help family ownership groups, boards, and management teams align their perspectives on the financial realities, needs, and opportunities of the business. Contact a Mercer Capital professional today to discuss your needs in confidence.
2018 NAPE Expo Observations & Thoughts
2018 NAPE Expo Observations & Thoughts
Mercer Capital again attended the NAPE Expo in Houston this past week.  People, information, and ideas abounded with over 11,000 participants and 800 exhibitors.We met and had numerous discussions with company representatives, dealmakers, and service providers alike.  The marketplace remains excited about the potential for 2018.A recurring theme of the Wednesday conference was restructuring and bankruptcy in light of the continuing bankruptcy activity in 2017.  The ramp up in M&A activity in 2017 was also discussed. We summarize that information here.Restructuring & BankruptciesSuccess stories were presented, such as Samson Resources’ CEO Joseph Mills discussing their successful emergence from Chapter 11 bankruptcy whereby approximately $4 billion of debt and $300 million in interest expense was discharged.A panel discussion on navigating the distressed oil and gas world was thought-provoking.  The panel participants provided an overview of the 2017 bankruptcy environment as well as where we are headed in 2018 (including statistics and commentary).  From 2015 through October 2017, there were a total of 116 U.S. producer bankruptcies representing $80 billion of secured and unsecured debt. Because some of these bankruptcies were very large and complicated, the panel discussed the cost/benefit factors of various restructuring and bankruptcy scenarios. Cautionary commentary acknowledged that it’s expensive to file bankruptcy (sort of an oxymoron) and that even the best laid plans can fall apart when various creditors and equity holders come into contact in a bankruptcy court.  One panelist (Jason Binford) noted that it’s also expensive and potentially fatal to wait to file bankruptcy. Many times there’s a lot at stake as the table below demonstrates. Strategies to avoid bankruptcy were categorized between internal & external options.  Internal options included (i) operational improvements, (ii) portfolio management, and (iii) liquidity management. External solutions included (i) capital markets/M&A, and (ii) liability management – including Chapter 11 bankruptcy, in which the audience was reminded that a company does not have to be insolvent to enter into Chapter 11. 3rd Party Valuations Can Be Critically Important in BankruptciesThe importance and contentiousness of valuations was emphasized, particularly when equity committees believe that there is more value to the company than what other participants may think.  In those situations, a quality and persuasive valuation can be critical and be the difference between the court wiping out prior equity holders and replacing them with new equity holders.The panel also advised not letting short-term price movements overly dictate strategy in this volatile priced industry.Increasing M&A Activity Pace in 2017Upstream M&A activity accelerated quickly in 2017; however, deal activity declined as commodity prices increased during the year.  There were 224 deals in 2017 (a 13% increase over 2016) totaling $181.97 billion (a 10% decrease).Of the 224 deals, 106 were shale deals valued at $66.55 billion.  The most active basins were the Permian (unsurprisingly), followed by the Marcellus and then Eagle Ford.From our standpoint, it was notable that on the Expo floor, away from the conference where shale plays took precedence, there was an incredible array of conventional, offshore, and international prospects that were still attractive and receiving attention.Our Takeaways from 2018 NAPE ExpoAgain, the marketplace remains excited about the potential for 2018.  The rise in commodity prices will likely not last through the year given the potential supply that is available to come online – whether through OPEC policy changes, reduction of DUC well inventory, or another means of changing supply and demand dynamics.The U.S. upstream segment is well-positioned to continue to have positive economics due to increasingly efficient operations, technology, and innovation.Thanks again to everyone we connected with this week.  The conversations were terrific, and we enjoyed getting to know all of you.  If you were there, let us know your thoughts and comments about NAPE.  We would love to hear them.  Have a great Valentine’s Day!
The Oilfield Services Industry Is Still Struggling and What This Means to Valuation
The Oilfield Services Industry Is Still Struggling and What This Means to Valuation
Lately, talk of the domestic oil and gas market has been especially positive. But the oilfield services industry is still struggling to recover from the collapse of oil prices in mid-2014 and the subsequent reduction in capital spending by upstream companies.We look at how the downturn in crude prices in 2014 still affects the oilfield service industry and consider the impact on company valuations.What Happens to Oilfield Services Companies When Oil Prices Are LowOilfield service companies provide support services to oil and gas production companies – leasing drilling rigs, repairing wells, manufacturing drilling equipment, processing seismic data, and more.When oilfield production companies cut capital expenditures and delayed drilling projects after oil prices fell in mid-2014, demand for oilfield service companies plummeted. They were no longer needed to drill new wells because new drilling activity essentially stopped when prices fell, and they were not needed to perform routine maintenance as many companies delayed repairs in order to cut costs.When oil prices fell, some regions were deemed uneconomical by many players, while other regions, such as the Permian Basin, experienced a rush to grab land while it was still available. While oilfield service companies operating in the Permian were better off than others, even these companies struggled as oil producers played the game of survival of the fittest where only those who could cut costs and increase efficiency could win.In order for drilling to remain economical in the new low oil price environment of 2015 and 2016, production companies invested in cost savings measures. Technological advancements, like multiwell pad drilling, reduced costs for the oil producers which in turn decreased revenue for oilfield service companies. As Dan Eberhart, contributor to Forbes wrote recently in “Revenge Of The Oil Services Sector in 2018”:"Make no mistake, when producers boast of 'efficiency gains' made to outlast low prices, they are primarily referring to cost-cutting achieved by squeezing contractors for lower day rates on services like drilling and well completions, providing fracking sand and connecting new wells to pipeline systems."Where Do Oilfield Companies Stand Today?Although earnings in the E&P sector have improved over the last year, earnings in the oilfield service industry have taken a beating over the last few years. Three of the top four players had negative LTM EBITDAs until mid-year 2017.Per the chart below, EBITDA has varied as compared to 4Q12. Of the four companies that released 2017 year-end financials (most oilfield service companies have not yet released 4Q17 data), EBITDA for two is significantly down from the previous quarter, one is stable, and one is up. EBITDA at 4Q17 has stabilized around 80% to 100% lower than EBITDA in 4Q12. Making matters worse, the oilfield service industry is highly capital intensive. The RMA average capital intensity ratios for companies that drill oil and gas wells (NAICS 213111) and companies that support activities for oil and gas operations (NAICS 213112) are $1.67 and $0.91, respectively.[1] To fund the massive amounts of capital needed, oilfield service companies can either use debt or cash. After the downturn in price, over 150 oilfield service companies filed for bankruptcy. The high number of bankruptcies in the industry has demonstrated that oilfield service companies may not be able to rely on debt as heavily as they have in the past in order to fund future capital expenditures. While bankruptcies in the E&P sector slowed in 2017, bankruptcies continued in the oilfield service industry. What Are the Appropriate Approaches to Value Oilfield Service Companies Today?In down cycles such as this, valuations are hard to understand because earnings alone cease to become particularly reliable indicators of value.Public multiples provide less insight as negative earnings multiples make little sense. Reliance on the multiples of companies that are currently profitable is questionable because the low profitability can artificially inflate the multiples and not provide a holistic view of value.Instead of using current earnings as indicators of value, the use of forward earnings and their associated forward multiples is considered. This is consistent with a forward-looking discounted cash flow method, but the valuation is then heavily dependent upon the reasonableness of the projections. The oilfield service industry is not expected to see a full recovery in 2018 so forward multiples may appear inflated even for fiscal 2018.During down cycles of asset intensive industries, such as oilfield services, investors often rely on an asset-based approaches. The net asset value method is an asset-based approach that develops a valuation indication in the context of a going concern by adjusting the reported book values of a subject company’s assets to their market values and subtracting its liabilities (adjusted to market value, if appropriate).Valuations Remain Challenging to InterpretUnderstanding the value of your oilfield services company in the context of the broader oil and gas marketplace can be difficult during times like these.Many think that the industry has recovered, or at least is on the way, but the oilfield service sector still appears to have a ways further to go.Until rates and/or utilization for services companies begin increasing and E&P companies begin sharing the gains they have made since oil prices have recovered, valuations could remain challenging to interpret.Mercer Capital has significant experience valuing assets and companies in the energy industry. Because drilling economics vary by region it is imperative that your valuation specialist understands the local economics faced by your oilfield service company.  Our oil and gas valuations have been reviewed and relied on by buyers and sellers and Big 4 Auditors. These oil and gas related valuations have been utilized to support valuations for IRS Estate and Gift Tax, GAAP accounting, and litigation purposes. Contact a Mercer Capital professional today to discuss your valuation needs in confidence.Endnote[1] Ratios provided for companies with over $25 million in Sales per RMA 2017-2018 Annual Statement Studies
What Is a Reserve Report?
What Is a Reserve Report?
This is the first of multiple posts discussing the most important information contained in a reserve report, the assumptions used to create it, and what factors should be changed to arrive at Fair Value[1] or Fair Market Value[2].Why Is a Reserve Report Important?A reserve report is a fascinating disclosure of information. This is, in part, because the disclosures reveal the strategies and financial confidence an E&P company believes about itself in the near future. Strategies include capital budgeting decisions, future investment decisions, and cash flow expectations.For investors, these disclosures assist in comparing projects across different reserve plays and perhaps where the economics are better for returns on investment than others.However, not all the information in a reserve report is forward-looking, nor is it representative of Fair Value  or Fair Market Value. For a public company, disclosures are made under a certain set of reporting parameters to promote comparability across different reserve reports. Disclosures do not take into account certain important future expectations that many investors would consider to estimate Fair Value or Fair Market Value.What Is a Reserve Report?Simply put, a reserve report is a reporting of remaining quantities of minerals which can be recoverable over a period of time. The current rules define these remaining quantities of mineral as reserves. The calculation of reserves can be very subjective, therefore the SEC has provided, among these rules, the following definitions, rules and guidance for estimating oil and gas reserves:Reserves are “the estimated remaining quantities of oil and gas and related substances anticipated to be economically producible;The estimate is “as of a given date”; andThe reserve “is formed by application of development projects to known accumulations”. In other words, production must exist in or around the current project.“In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production of oil and gas”There also must be “installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.”Therefore, a reserve report details the information and assumptions used to calculate a company’s cash flow from specific projects which extract minerals from the ground and deliver to the market in a legal manner. In short, for an E&P company, a reserve report is a project-specific forecast. If the project is large enough, it can, for all intents and purposes, become a company forecast.What Is the Purpose of a Reserve Report?Many companies create forecasts. Forecasts create an internal vision, a plan for the near future and a goal for employees to strive to obtain. Internal reserve reports are no different from forecasts in most respects, except they are focused on specific projects.Externally, reserve reports are primarily done to satisfy disclosure requirements related to financial transactions. These would include capital financing, due diligence requirements, public disclosure requirements, etc.Publicly traded companies generally hire an independent petroleum engineering firm to update their reserve reports each year and are generally included as part of an annual report. Like an audit report for GAAP financial statements, independent petroleum engineers provide certification reserve reports.Investors can learn much about the outlook for the future production and development plans based upon the details contained in reserve reports. Remember, these reserve reports are project-specific forecasts. Forecasts are used to plan and encourage a company goal.How Are Reserve Reports Prepared?Reserve reports can be prepared many different ways. However, for the reports to be deemed certified, they must be prepared in a certain manner. Similar to generally accepted accounting principles (GAAP) for financial statements, the SEC has prepared reporting guidance for reserve reports with the intended purpose of providing “investors with a more meaningful and comprehensive understanding of oil and gas reserves, which should help investors evaluate the relative value of oil and gas companies." Therefore, the purpose of SEC reporting guidelines is to assist with project comparability between oil and gas companies.What Is in a Reserve Report?Reserve reports contain the predictable and reasonably estimable revenue, expense, and capital investment factors that impact cash flow for a given project. This includes the following:Current well production: Wells currently producing reserves.Future well production: Wells that will be drilled and have a high degree of certainty that they will be producing within five years.Working interest assumption: The ownership percentage the Company has within each well and project.Royalty interest assumptions: The royalty interest paid to the land owner to produce on their property.Five-year production plan: All the wells the Company plans to drill and have the financial capacity to drill in the next five years.Production decline rates: The rate of decline in producing minerals as time passes. Minerals are a depleting asset when producing them and over time the production rate declines without reinvestment to stimulate more production. This is also known as a decline curve.Mineral price deck: The price at which the minerals are assumed to be sold in the market place. SEC rules state companies should use the average of the first day of the month price for the previous 12 months. Essentially, reserve reports use historical prices to project future revenue.Production taxes: Some states charge taxes for the production of minerals. The rates vary based on the state and county, as well as the type of mineral produced.Operating expenses for the wells: This includes all expenses anticipated to operate the project. This does not include corporate overhead expenses. Generally, this is asset-specific operating expenses.Capital expenditures: Cash that will be needed to fund new wells, stimulate or repair existing wells, infrastructure builds to move minerals to market and cost of plugging and abandoning wells that are not economical.Pre-tax cash flow: After calculating the projected revenues and subtracting the projected expenses and capital expenditures, the result is a pre-tax cash flow, by year, for the project.Present value factor: The annual pre-tax cash flows are then adjusted to present dollars through a present value calculation. The discount rate used in the calculation is 10%. This discount rate is an SEC rule, commonly known as PV 10. The overall assumption in preparing a reserve report is that the company has the financial ability to execute the plan presented in the reserve report. They have the approval of company executives, they have secured the talent and capabilities to operate the project, and have the financial capacity to complete it. Without the existence of these expectations, a reserve report could not be certified by an independent reserve engineer.A Plug for Mercer CapitalMercer Capital has significant experience valuing assets and companies in the energy industry. Because drilling economics vary by region it is imperative that your valuation specialist understands the local economics faced by your E&P company.  Our oil and gas valuations have been reviewed and relied on by buyers and sellers and Big 4 Auditors. These oil and gas related valuations have been utilized to support valuations for IRS Estate and Gift Tax, GAAP accounting, and litigation purposes. We have performed oil and gas valuations and associated oil and gas reserves domestically throughout the United States and in foreign countries. Contact a Mercer Capital professional today to discuss your valuation needs in confidence.Endnotes[1] “The price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.” – FASB Glossary[2] “The price at which the property would change hands between a willing buyer and a willing seller, neither being under any compulsion to buy or to sell and both having reasonable knowledge of relevant facts” – U.S. Treasury regulations 26 C.F.R. sec. 20.2031-1(b)
M&A in Appalachia: Moving Day in the Neighborhood
M&A in Appalachia: Moving Day in the Neighborhood
This week we look back at transaction activity and trends in the Marcellus & Utica plays in 2017. When I reflect about what happened, for whatever reason, images resembling something out of an episode of Desperate Housewives come to mind whereby the prying eyes of the marketplace peer out of their windows, surveilling old competitors that pack up and leave whilst new, and sometimes mysterious, neighbors move in.But first, we point out recent articles that forecast that the U.S. may challenge Saudi Arabia and Russia in total oil production sometime in the next two years. For someone who has followed and worked within energy markets for many years, including before the shale fracking revolution, this is something I wasn’t sure I’d ever read.  Of course it is likely a temporary surge once the OPEC/non-OPEC agreement expires, but it's still fascinating to contemplate.The Appalachian BasinOK, now back to the subject at hand.  Transaction activity in the Marcellus & Utica shale was generally steady throughout the year and individual transactions were typically smaller in size.  Rationale for these deals were varied, from bankruptcy sales, to consolidation of acreage, strategy changes to more liquid rich plays, leverage reduction, and more. The chart below, drawn from Mercer Capital's forthcoming 4Q17 Marcellus & Utica-focused newsletter, provides transaction detail and comparative valuation metrics.Back Up the Truck, Dear! We're Moving onto Bigger and Better Things.In one of the few large transactions last year, Noble Energy exited the Marcellus in order to focus on more liquid rich regions with its $1.2 billion sale to HG Energy.  David L. Stover, Noble Energy's Chairman, President and CEO, commented, "The Marcellus has been a strong performer for Noble Energy over the last few years, which is a direct result of the success of our employees' efforts. During the same time period, we have also significantly expanded the inventory of investment opportunities in our liquids-rich, higher-margin onshore assets, which has led us to now divest our Marcellus position."In a similar vein, Carrizo Energy, a Houston-based producer, exited the play, utilizing the familiar "non-core" term to describe its position in the Appalachia region.  S.P. "Chip" Johnson, IV, Carrizo's President and CEO, commented, "With the announced sale of our Marcellus package, we have continued to execute on the divestiture program we outlined earlier this year. We expect to close the sale of both of our Appalachian packages during the fourth quarter and remain on track to reach our divestiture program goals." Carrizo has stated its desire to focus on liquid plays and reduce leverage which these sales went towards achieving.Look Honey, Those Folks Are Moving Out … and Their Wells Are Just Perfect for Us!Looking at the other end of the rationale spectrum, there were a number of buyers that were enthusiastic about the opportunities that companies like Noble & Carrizo left behind. Kalnin Ventures, a Thai-based coal and power generation company, made their 5th acquisition in the play in the past two years by buying positions from Carrizo's and Reliance Marcellus II, LLC. They also made a 6th in December by taking out Warren Resource's entire Northeast Marcellus position for $105 million. In strategic contrast to Carrizo's sentiment, Kalnin thinks these assets fit within their strategy of acquiring profitable, consolidated, low-risk assets that provide strong cash flow yields.Believe it or not, Kalnin's activity actually did not top the acquisition charts in 2017.  That distinction belonged to EQT, beginning with EQT's $527 million bankruptcy auction bid of Stone Energy's Marcellus and Utica acreage in February 2017. EQT, who made nearly $9 billion of Marcellus & Utica acquisitions in 2017, went on to highlight the year by its merger with Rice Energy in June 2017. Steve Schlotterbeck, EQT's president and chief executive officer said, "This transaction complements our production and midstream businesses and will deliver significant operational synergies to help us maintain our status as one of the lowest-cost operators in the United States." For a more in-­depth valuation oriented discussion on the Rice Energy transaction, a prior Mercer Capital blog post breaks down the deal.Are You Watching This, Sweetie?  So, What Kind of Deal Did They Get?Valuations for these transactions were relatively spread out depending on the metric observed, but were within an observable range.  Kalnin appeared to pay more than other buyers in a few deals from a $/Acre perspective (over $19,500/Acre), but it can be argued that they baked in economies of scale in light of their overlapping positions and infrastructure. EQT appeared to buy in a very tight range from a $/Mcfe/Day perspective ($6,300-$6,600). That said, due to the steady activity and universe of buyers and sellers, pricing and values appeared to be fairly consistent. We shall see if that continues in 2018, and speaking of that - we wish you all a happy 2018!A Plug for Mercer CapitalMercer Capital has significant experience valuing assets and companies in the energy industry. Because drilling economics vary by region it is imperative that your valuation specialist understands the local economics faced by your E&P company.  Our oil and gas valuations have been reviewed and relied on by buyers and sellers and Big 4 Auditors. These oil and gas related valuations have been utilized to support valuations for IRS Estate and Gift Tax, GAAP accounting, and litigation purposes. We have performed oil and gas valuations and associated oil and gas reserves domestically throughout the United States and in foreign countries. Contact a Mercer Capital professional today to discuss your valuation needs in confidence.
Economics of Drilling in the Marcellus & Utica
Economics of Drilling in the Marcellus & Utica
The economics of oil and gas production vary by region. Mercer Capital focuses on trends in the Eagle Ford, Permian, Bakken, and Marcellus and Utica plays. The cost of producing oil and gas depends on the geological makeup of the reserve, depth of reserve, and cost to transport the raw crude to market.Appalachian BasinThe Marcellus formation and the underlying Utica are two large shale layers in the Appalachian basin. The Utica is the larger and denser of the two layers and rests a few thousand feet below the Marcellus. Producers must use techniques such as hydraulic fracturing, horizontal drilling, and pad drilling to make wells economically viable.As shown in the chart below, the region produces more than 2.5x as much natural gas as any other region in the U.S. The Marcellus is already the second most prolific natural gas producer in the world after the Pars/North Dome field in Iran. Additionally, since the productivity of both plays is newly discovered, most of the recoverable gas is still in the ground. It appears as though the region will remain the center of natural gas production in coming years. As production in the region multiplied, however, regional well-head prices fell. The amount of natural gas being produced in the Northeast far exceeded the infrastructure available to move supplies across the U.S. resulting in a supply surplus. This supply surplus caused the price of natural gas in the region to fall below the already depressed price of natural gas across the U.S. Midstream oil and gas companies recognized the need for pipeline capacity in the Northeast, and many companies are in various stages of completion of new pipelines and/or existing pipeline reversals. These projects have already proven successful at transporting low-cost Marcellus shale gas out of the region. The EIA reported in August 2017 that the difference between the price of Henry Hub (the national benchmark for natural gas) and the price at hubs in Appalachia has narrowed as new pipeline projects and expansions are completed. Further, the lack of refining and cracking capacity in the region has kept prices low and hampered growth. In June 2016, Shell announced that it would invest $3-$4 billion building an ethane cracker plant and petrochemical complex in Beaver County. Shell estimates that 70% of North American polyethylene consumers are within 700 miles of this facility. They began construction in late September 2017 and have signed 10-20 year supply agreements with 10 natural gas producers in Appalachia. According to a presentation by the United States Department of Energy (USDE) at the NARO Appalachia conference, there have been four crackers announced to date in the region, bringing a combined capacity of 4.0 million metric tons to the region. Natural gas producers have been dealing with low prices for over ten years. However, there is now hope of some relief in the next few years as new infrastructure in the region helps to reduce the supply glut. Additionally, demand for natural gas has been increasing as electricity generation fueled by coal has decreased and natural gas has taken its place. Valuation ImplicationsOver the past few years valuation multiples have been falling in the region as enterprise values have remained relatively constant and production has been increasing. As infrastructure projects near completion and the possibility of higher regional natural gas prices starts to materialize, we expect valuation multiples in the Marcellus and Utica to increase. Mercer Capital has significant experience valuing assets and companies in the energy industry. Because drilling economics vary by region it is imperative that your valuation specialist understands the local economics faced by your E&P company. Our oil and gas valuations have been reviewed and relied on by buyers and sellers and Big 4 Auditors. These oil and gas related valuations have been utilized to support valuations for IRS Estate and Gift Tax, GAAP accounting, and litigation purposes. We have performed oil and gas valuations and associated oil and gas reserves domestically throughout the United States and in foreign countries. Contact a Mercer Capital professional today to discuss your valuation needs in confidence.
What a Steady Oil and Gas Industry in 2017 Points to in 2018
What a Steady Oil and Gas Industry in 2017 Points to in 2018
“Steady as she goes.” At least that is what I think captains of most vessels say…except maybe a car. For captains navigating the 2018 oil and gas industry, a repeat of 2017’s relatively calm waters is vocal wish. 2017 in ReviewOil prices closed the year reaching $60 per barrel, WTI futures prices returned to backwardation, and oil price volatility was relatively calm as the price moved within an $18 band all year ($42 - $60). Natural gas, on the other hand, continued its woes of declining prices, transportation constraints, and oversupply. Hope remains that increased natural gas exports will change the narrative, but that is still undetermined. For the oil industry, a repeat of 2017 would be a welcomed event, making the theme for the year ahead – “Steady as she goes.” Before projecting trends of 2018, let’s review 2017, starting with oil and gas commodity prices.Oil and Gas Commodity PricesIf bottom needs to be found before rebound can happen, 2015 and 2016 provided a solid foundation for the oil and gas price gains in 2017. This past year brought about the feeling of stability for oil prices and continued woes for natural gas. For the year, WTI increased 11% and Henry Hub natural gas decreased 20%. This is the second consecutive year-over-year increase for WTI.Additional PerspectiveIn a commodity-focused industry, commodity prices set the overall framework. With last year’s oil and gas prices as the framework, here are a few posts that provide additional color to the 2017 oil and gas industry.Are S&P Energy Stock Valuations Really Crazy Right Now? The Wall Street Journal published an article discussing what the author described as “crazy” stock valuations, and in particular the inflated valuations of oil and gas stocks from the perspective of operating earnings ratios. While we certainly are believers that value is driven by future operating earnings, and that earnings in the energy sector have fallen precipitously since 2014, is this all that determines the market’s pricing of the S&P 500 energy sector? As we reflect on this for a moment, a few additional considerations came to mind that may explain these “crazy” valuations more fully.Are Oil and Gas Bankruptcies a Thing of the Past? The worst of bankruptcies are over. Since the start of the oil downturn, more than 120 upstream and oilfield service companies declared bankruptcy. However, the decision to file for bankruptcy did not always signal the demise of the business. Now more prepared, many E&P companies who reorganized are looking to grow.Oil and Gas Investors Note Move Away From Contango The movement in the future spread away from a contango environment and toward backwardation is positive from a supply and demand perspective. Expectations are a backwardation environment will move crude oil prices higher. However, the exact cause of this change is unknown. While this shift is good news for the industry, company specific risk and investor's fickle attitudes create volatile equity markets.Current Regulatory Environment Affecting the Oil and Gas Industry As business valuation experts, we have to consider the outlook for the economy, industry, and business in every valuation; therefore, we pay attention to the oil and gas regulatory environment to assess what it means for our clients.  Given the new administration, there is much to consider.WTI Futures and Inventories U.S. oil inventories decline as oil exports surge. In this post we address why the shift in oil futures from contango pricing to backwardation is a bearish sign for those in crude oil storage.Outlook for 2018The positive momentum for the oil industry should continue as long as prices hold steady or increase. With the futures curve currently in backwardation and the backwardation spread getting stronger, the upward trend in price should continue. Other resource plays, like the Bakken, Eagle Ford, and Canadian Oil Sands will become more attractive and active as the price of oil inches higher. Natural gas, on the other hand, continues to sort out its oversupply and distribution constraints which have continued to push prices down. Reorganization, consolidation, and operational efficiency in the Marcellus and Utica players are anticipated going forward. This focus will continue until gas price relief is a reality, at which point the companies still operating will be well positioned to thrive.Mercer Capital has significant experience valuing assets and companies in the energy industry, primarily oil and gas, bio fuels and other minerals.  Our oil and gas valuations have been reviewed and relied on by buyers and sellers and Big 4 Auditors. These oil and gas related valuations have been utilized to support valuations for IRS Estate and Gift Tax, GAAP accounting, and litigation purposes. We have performed oil and gas valuations and associated oil and gas reserves domestically throughout the United States and in foreign countries. Contact a Mercer Capital professional today to discuss your valuation needs in confidence.
EP First Quarter 2018 Region Focus Eagle Ford
E&P First Quarter 2018

Region Focus: Eagle Ford

Region Focus: Eagle Ford The oil and gas market has been steadily improving.e volatility was relatively calm as the price stayed within an $18 band all year ($42 – $60).
A Tale of Two Bakkens: Cashing Out or Doubling Down
A Tale of Two Bakkens: Cashing Out or Doubling Down
Transaction activity in the Bakken shale was both busy and revealing in the second half of 2017.  Many of these deals marked the departure of a number of companies that were known to be active in the play, particularly Halcon Resources. Other companies, however, have remained. The table below, drawn from Mercer Capital’s 3Q17 Bakken-focused newsletter, shows some details in regards to recent transactions, including some comparative valuation metrics.Cashing OutThe first major transaction was Halcon’s $1.4 billion sale of the majority of its North Dakota operations to Bruin E&P Partners LLC (a private company).  Through this sale, as expected while resurfacing from bankruptcy, Halcon shifted focus to the Permian Basin.  In addition, the Company cited the possibility of an outright sale as well.  Two months later, Halcon sold its remaining Bakken assets (about 2,300 boe/day of production) for $110 million.In addition Earthstone Energy, and more notably, Linn Energy exited the Bakken in the past several weeks. Linn entered the Bakken play in 2011 by buying out a position previously held primarily by Concho Energy for $434 million. They exited for $285 million which was approximately a 1.5x multiple of the PDP value of $186 million as of YE 2016.  It appears that Linn struggled with maximizing its production profile in light of the major price shift in 2014.  Earthstone Energy also left, with a small $27 million non-operating sale.  They, too, are shifting their focus to the Permian Basin.Valuations for these transactions were relatively tight. The Linn and larger Halcon sales were priced around approximately $14,000 per acre. The Earthstone deal was much smaller, and its valuation on a per acre basis was much smaller as well at around $1,100 per acre.Doubling DownHowever, amid the struggles of these other operators, Whiting and Continental demonstrated signs of commitment and improvement in the Williston Basin.  Whiting sold its acreage position in Dunn County, North Dakota for $500 million. This amounted to a pricing of around $17,000 per acre, a premium to the Linn and Halcon sales.  This, of course, is a relative bargain on a per acre basis compared to the pricing in the Permian these days. Then again, the economics between the two basins at current pricing is also a far cry from each other, with the Permian having clearly superior characteristics.  Nonetheless, this did not signal an exit for Whiting, but was a signal to reduce leverage and give it balance sheet flexibility for its remaining Bakken acreage.  Whiting is optimistic that recent improvements in oil pricing differentials and improved enhanced completion techniques will press to its advantage going forward in the play.While Whiting has not yet been able to scale its optimism, Continental has surprised many in the past year with its recent performance.  In light of the challenges of the play, Continental has continued to improve its drilling and completion techniques, while elements they can’t control (such as oil prices) begin to swing back in their favor.  As such, they have dropped LOE's and G&A to the lower end of their peer range, while netbacks are rising.  All of this has happened, while many peers (as demonstrated above) have struggled or are leaving the area. Not all is the same.  Performance and valuations in the Bakken appear to be mixed and right now it appears that the operator’s skill and knowledge is as important a value driver as the acreage they drill on. Mercer Capital has significant experience valuing assets and companies in the oil and gas industry, primarily oil and gas, bio fuels, and other minerals. Our oil and gas valuations have been reviewed and relied on by buyers and sellers and Big 4 auditors. These oil and gas-related valuations have been utilized to support valuations for IRS estate and gift tax, GAAP accounting, and litigation purposes. We have performed oil and gas valuations and associated oil and gas reserves domestically throughout the United States and in foreign countries. Contact a Mercer Capital professional today to discuss your valuation needs in confidence.
WTI Futures and Inventories
WTI Futures and Inventories
Back in August 2017, we discussed the significant and bullish shift in the oil futures market from contango pricing to backwardation. This shift marked the first time backwardation would enter the market since 2014 and oil and gas investors were taking note. This was a bullish sign for many, including producers and oil field services, but a bearish sign for those in crude oil storage. Possible reasons for this include the following.Crude Oil ExportsThe U.S. has never exported more crude oil than right now. Latest data from EIA indicates the export of 1.4 million barrels per day in the month of September; nearly double the August daily export figures. Since the unrefined crude oil export ban was lifted in early 2016, the total average daily export figures have exploded. The average number of barrels exported in 2015 was 465,000 while 2017's average is  960,000 barrels per day.The top five nations receiving U.S. crude oil include 1) Canada; 2) China; 3) Korea; 4) United Kingdom; and 5) India. This group represents 65% of total exports in the month of September, with Canada leading the way with 23% of all U.S. exports while China is a close second at 17%.Interestingly, South Korea has surged its imports of U.S. crude. For reference, the average daily oil exports to Korea between June 2000 and August 2016 was 6,200 barrels per day. In the last 12 months, that number has surged to 50,000 barrels per day (more than 8x the average for the 2000's).Crude Oil Exports Takeaway: With the export ban rescinded, crude oil exports are increasing overall and specifically to eastern Asia.2017 Hurricane Season ImpactAs we wrote in our September 25, 2017 post, Hurricane Harvey, which made landfall in Houston, Texas, shut down more than 20% of the oil production from the Gulf of Mexico with additional onshore volumes shut-in.  Four terminals in Corpus Christi were closed to tanker traffic. Nearly 50% of the nation’s refining capacity is located along the Gulf Coast and at least 10 refineries were shut down before the storm’s arrival.In response to the impact of hurricanes during 2017, U.S. refineries have been processing record seasonal volumes of crude to rebuild stocks of gasoline and especially diesel which were depleted by hurricanes and strong consumption at home and in export markets.As a result, crude stocks along the East, West, and Gulf Coasts have all fallen since the summer and are well below last year's levels and appear tight. Hurricane Season Takeaway: Refiners are running hard trying to replenish the stock lost during demand surge and shutdowns caused by the 2017 hurricane season. This results in higher demand for crude oil in the current market. Much of this demand is immediately filled by crude oil in storage.US Oil Inventories – Weekly Petroleum Status Report, EIACrude storage inventories hit their highest level ever in March 2017 with 1.2 trillion barrels of crude oil. Since that time, inventories have declined by 117 million barrels, according to information available from the EIA. Storage levels play a significant role in futures prices. U.S. crude futures, such as West Texas Intermediate (WTI), are based on crude delivered into the tank and pipeline system around Cushing, Oklahoma.Futures prices are, therefore, very sensitive to anything that affects the regional supply-demand balance in the Midwest (PADD 2) as Cushing's falls under the Midwest reporting region.Overall, commercial crude oil storage inventory levels across the U.S. are down 8% year-over-year. The largest single storage facility of commercial crude in the U.S. is stored in Cushing, Oklahoma. Cushing's inventory is down (15%) year-over-year, while the largest PADD area for crude oil storage (the Gulf Coast – PADD 3) was down (12%) year-over-year.Crude Oil Inventory Takeaway: The inventory levels of crude oil are falling all across the nation in response to higher exports of crude oil, the impact from 2017 hurricane season, and the backwardation trend in WTI future prices which encourages selling rather than storage of crude oil.Trend in WTI Future CurveThe table shows the future contract spread for the previous 12 months. The most recent data (December 1, 2017) returns the third month in a row of backwardation spreads since 2014. In addition, the trend movement from contango to backwardation can be seen while watching the shrinking spread from August 2016, when the market had a wider contango spread of ($5.72), to backwardation in October 2017 to a significantly wider backwardation spread in December 2017. ConclusionThe movement in the future spread toward backwardation is positive from an economic supply and demand perspective. Expectations are a backwardation environment will move crude oil prices higher, leading to more exploration and production activity, more active selling to refiners and the broader market, and less demand for storage. While this shift is good news for the overall industry, company specific risk and investors' fickle growth and risk attitudes create volatile public equity markets.Mercer Capital has significant experience valuing assets and companies in the oil and gas industry, primarily oil and gas, bio fuels, and other minerals.  Our oil and gas valuations have been reviewed and relied on by buyers and sellers and Big 4 auditors. These oil and gas-related valuations have been utilized to support valuations for IRS estate and gift tax, GAAP accounting, and litigation purposes. We have performed oil and gas valuations and associated oil and gas reserves domestically throughout the United States and in foreign countries. Contact a Mercer Capital professional today to discuss your valuation needs in confidence.
Current Regulatory Environment Affecting the Oil and Gas Industry
Current Regulatory Environment Affecting the Oil and Gas Industry
The oil and gas industry is heavily regulated by the Environmental Protection Agency (EPA), the Federal Energy Regulatory Commission (FERC), Bureau of Land Management (BLM), and the Department of the Interior (DOI).As business valuation experts, we have to consider the outlook for the economy, industry, and business in every valuation; therefore, we pay attention to the regulatory environment to assess what it means for our clients.  Given the new administration, there is much to consider.Review of Recent Regulatory ReformStreamlining Federal ReviewsOn August 15, President Trump signed an executive order which aims to speed up the process for federal environmental reviews of energy and other infrastructure projects and holds agencies accountable if they fail to do so. Jack Gerard, President of the American Petroleum Institute (API), praised the order for its focus on speeding up projects, saying “We also look forward to President Trump as he signs an executive order aimed at streamlining the permitting process for infrastructure projects.” The API had previously called for significant improvements to be made to the permitting process.Federal Energy Regulatory CommissionsIn August, the Senate confirmed two appointees to the Federal Energy Regulatory Commission, which is an independent agency that regulates the interstate transmission of electricity, natural gas, and oil, among other things. Prior to the appointments, the commission did not have quorum (the first time in its 40-year history), holding up projects worth $50 billion in private capital according to the Electric Reliability Coordinating Council. FECR is now ready to address the backlog of projects.North American Free Trade Agreement (NAFTA)Negotiations of NAFTA began in the third quarter of 2017 and remain unresolved. President Trump has indicated on multiple occasions that the U.S. could simply pull out of the agreement, which worries many in the oil and gas industry. The API, CAPP, and AMEXHI are the top trade groups in the United States, Canada, and Mexico, respectively, and they issued a joint position paper on August 2 hoping to keep current policies intact and “Do No Harm.” As early as 2020, North America could achieve energy self-sufficiency and has made significant strides since the agreement was signed 23 years ago. The paper goes on to claim that a change in trade that reduces investment protections or increases tariffs or trade barriers could have a significant negative impact on the industry and risk tens of millions of jobs that depend on trade in North America.Tax ReformTowards the end of the third quarter 2017, Congressional Republicans introduced the outlines of their plans for tax reform. On December 2, the Senate passed the tax reform bill. The next step is for the House and Senate to agree on the same version of the bill.  In general the bill has the goal of reducing the corporate tax rate and simplifying the overall tax code.  The energy industry will likely see aspects that are both good and bad. A corporate income tax rate decrease from 35% to 20% would be great news for the oil and gas industry. On the other hand simplifying the tax code will likely lead to a decrease in tax exemptions of over $4 billion for the industry. The biggest of these, “intangible drilling costs,” or IDCs, could actually be expanded, with a provision in the reform that allows for the immediate expensing of new investments.Renewable Fuels Standards Program (RFS)The Renewable Fuels Standards Program continues to have a significant impact on the refining industry.   Each November, the EPA issues rules increasing Renewable Fuel Volume Targets for the next year. Renewable Identification Numbers (RINs) are used to implement the Renewable Fuel Standards.  At the end of the year, producers and importers use RINs to demonstrate their compliance with the RFS.  Refiners and producers without blending capabilities can either purchase renewable fuels with RINs attached or they can purchase RINs through the EPA's Moderated Transaction System. While large integrated refiners have the capability to blend their own petroleum products with renewable fuels, small and medium sized merchant refiners do not have this capability and are required to purchase RINS, which have significantly increased in price.The new RFS for 2018, which were released in mid-July, displayed a slight reduction in the volume requirements.  A public hearing was held on August 1 and on October 17. The EPA provided a public notice and an opportunity to comment on potential reductions in the 2018/2019 biomass-based diesel, advanced biofuel, and total renewable fuel volumes.  The final rule should be available in December.  A coalition of independent refiners and marketers has urged President Trump to move forward with this review.  According to the November issue of the Oil and Gas Journal, the Fueling American Jobs Coalition (FAJC) said, “The need for significant reform has only grown over the last year as the cost of purchasing Renewable Identification Numbers (RIN) to comply with the RFS has skyrocketed, threatening some refiners’ survival.”RTR & NSPSIn December of 2015 the Petroleum Refinery Sector Risk and Technology Review (RTR) and the New Source Performance Standards (NSPS) rule was passed in order to control air pollution from refineries and provide the public with information about refineries’ air pollution. These regulations ranged from fence line and storage tank monitoring to more complex requirements for key refinery processing units.  The EIA estimates the rule will cost refineries a total of $40 million per year, while the American Petroleum Institute (API) argued that the annual cost would exceed $100 million.  The rule was expected to be fully implemented in 2018 however President Trump’s attention to the needs of deregulation of the oil and gas sector makes us to question the future implementation of the rules.SummaryThese are just a few of the regulations that affect the day-to-day operations of companies in the oil and gas industry.  Changes in the regulatory environment have led to increased uncertainty in the oil and gas sector. Overall, however, outlooks for the industry appear favorable.  While this post mainly outlines domestic oil and gas policy, it is important to remember that the domestic oil and gas market is affected by global oil supply and demand.  On Thursday November 30, OPEC decided to extend production cuts through December 2018.  This decision came one year after OPEC originally decided to make across the board production cuts in order to realize more stable oil prices around $50 per barrel.Mercer Capital has significant experience valuing assets and companies in the energy and construction industries. Our valuations have been reviewed and relied on by buyers and sellers and Big 4 Auditors. These valuations have been utilized to support valuations for IRS Estate and Gift Tax, GAAP accounting, and litigation purposes. Contact a Mercer Capital professional today to discuss your valuation needs in confidence.
How to Value an Oil & Gas Mineral Royalty Interest
How to Value an Oil & Gas Mineral Royalty Interest
Well-informed buyers and sellers are critical to an efficient market for royalty interests because there is a specialized and relatively complex body of knowledge to consider in the transfer of these types of assets.Often called a net revenue interest (NRI), royalty interests do not bear the costs of production and only participate in the potential upside of a resource.  The value of a royalty interest, however, is often difficult to observe because they are typically closely held.  In addition, once discovered and drilled, the natural resources are physically depleted, resulting in a declining asset as opposed to a growing one.A lack of knowledge regarding the worth of a royalty interest can be very costly. A shrewd buyer may offer a bid far below the interest’s fair market value, opportunities for successful liquidity may be missed, or estate planning could be incorrectly implemented based on misunderstandings about value.Understanding how royalty interests are properly appraised will ensure that you maximize the value of your royalty, whenever and however you decide to transfer it.This blog post summarizes our whitepaper – providing an informative overview of the valuation of mineral royalty interests within the oil and gas industry.  While there are a myriad of factors (mostly out of a royalty holder’s control) impacting the economics of a royalty interest, this blog post focuses on valuation methodology.What Does the Valuation Process Entail?Valuation approaches refer to the basis upon which value is measured.There are three commonly accepted approaches to determining value:Asset-based ApproachMarket ApproachIncome Approach In the realm of business valuation, each approach incorporates procedures that may enhance awareness about specific economic attributes that may be relevant to determining the final value of a given entity. Ultimately, the concluded valuation will reflect consideration of one or more of these approaches (and perhaps several underlying methods) as being most indicative of value for the subject interest under consideration. However, due to fundamental structural differences between businesses and assets, the available valuation methodologies tend to be utilized differently when valuing royalty interests. (1)The Asset-Based ApproachThe asset-based approach can be applied in different ways, but the general idea is that the enterprise value of a business is given by subtracting the market value of liabilities from the market value of assets. While the asset-based approach can be useful when valuing companies operating within the oil and gas industry, this approach is not typically employed to determine the value of a royalty interest.Oftentimes a mineral royalty owner purchased land which included the mineral rights and an allocation of surface vs mineral rights was not performed. Additionally, considerable time may have passed between the time the surface and mineral rights were purchased and the valuation date. Adding to the ambiguity of the cost basis of the asset, mineral royalty interests are often family assets that are handed down for generations. For this reason, the asset-approach is rarely used to determine the market value of mineral royalty interests unless the mineral rights were recently purchased.The Market ApproachThe market approach utilizes transaction pricing from guideline transaction data or valuation multiples from a group of publically held companies to determine the value of a privately held enterprise or asset. To develop an indication of mineral royalty interest value using the market approach, you can utilize data from market transactions of mineral interests in similar plays. This data can be derived from direct transactions of mineral royalty interests or from publically traded royalty trusts and partnerships.Direct comparable transactions of mineral royalty interests are often the best indication of fair market value.  However, the data with which to benchmark a subject mineral royalty interest against is often unavailable.  If it is available, a careful comparative analysis must be made.  Royalty trusts and partnerships hold various mineral royalty interests in wells operated by large exploration and production companies. Royalty trusts and partnerships tend to have very low, if any, operating expenses and can be an investment to provide exposure to oil and gas prices.Acquisition data from these trusts can be utilized to calculate valuation multiples on the subject royalty’s performance measure(s). This will often provide a meaningful indication of value as it takes into account industry factors (or at least the market participants’ perception of these factors) far more directly than the asset-based approach or income-based approach.Traditional oil and gas earnings multiples, such as EV/ EBITDAX, should not be used to calculate indication of values because royalty trusts do not have high operating costs and operational earnings margins are not a necessarily meaningful indication of performance for a royalty owner. Rather, a royalty trust's performance can be better understood by its distribution yield and potential for future revenue streams from new, undrilled wells.In many ways, this approach goes straight to the heart of value: a mineral royalty is worth what someone is willing to pay for it. However, the market approach is not a perfect method by any means for businesses or for mineral royalties.Royalty trust transaction data may not provide for a direct consideration of specific mineral royalty characteristics; it is imperative that the value conclusion be adjusted for differences in value level and in well economics, potential future drilling locations, among other factors. In any valuation, the more comparable the transactions are, the more meaningful the indication of value will be.The Income ApproachThe income approach can be applied in several different ways. Generally, such an approach is applied through the development of a cash flow or ongoing earnings figure and the application of a multiple to those earnings based on market returns. For mineral royalty interests, however, we oftentimes perform a discounted cash flow analysis. This approach allows for the consideration of characteristics specific to the subject mineral royalty, such as its well economics making it the most commonly used approach for mineral royalty interest valuations.To perform a royalty’s DCF analysis, production levels must be projected over the well’s useful life. Given that well production decreases at a decreasing rate, these projections can be calculated through deriving a decline rate from historical production. Revenue is a function of both production and price; as such, after developing a legitimate prediction of production volumes, analysts must predict future price values. The stream of revenue is then discounted back to present value using a discount rate that accounts for risk in the industry.Because revenue cash flows are the main driver of mineral royalty values, the income approach is the most reasonable and supportable valuation approach when determining the value of a mineral royalty interest.ConclusionA proper valuation of a mineral royalty interest will factor, to varying degrees, the indications of value developed utilizing the market-based and income-based approaches outlined above. A valuation, however, is much more than the calculations that result in the final answer. It is the underlying analysis of the mineral royalty and its unique characteristics that provide relevance and credibility to these calculations. This is why industry "rules-of-thumb" are dangerous to rely on in any meaningful transaction.Such "rules-of-thumb" fail to consider the specific characteristics of an interest and, as such, often fail to deliver insightful indications of value. A mineral royalty owner executing or planning a transition of ownership can enhance confidence in the decisions being made only through reliance on a complete and accurate valuation of the interest.Mercer Capital's Oil & Gas team has extensive experience valuing mineral royalty interests. Despite attempts to homogenize value through the use of simplistic rules of thumb, our experience is that each valuation is truly unique given the purpose for the valuation and the circumstances of the interest. We hope this information, which admittedly only scratches the surface, helps you better shop for royalty valuation services and understand valuation mechanics.We encourage you to extend your wealth planning dialogue to include valuation of any mineral interests because, sooner or later, a valuation is going to happen. Proactive planning and valuation services can alleviate the potential for a negative surprise that could complicate an already stressful time in your personal life.For more information or to discuss a valuation or transaction issue in confidence, do not hesitate to contact us at (901) 685-2120 or (214) 468-8400.End Note(1) Treasury Regulations 1.611-2(d) asserts that the income approach will not be used if the value of a mineral property can be determined using the cost-approach (under the asset approach) or the market approach.  However, those circumstances are rare and not consistent with industry norms.  The income approach is most often employed to estimate the fair market value of mineral properties such as this.Mercer Capital's Energy Valuation Insights BlogThe Energy Valuation Insights Blog presents a weekly update on issues important to the Energy Industry. Follow us on Twitter @MercerEnergy.
Underpayments, Overpayments, Lost Opportunities and Bankruptcies: Trends and Happenings in Energy Litigation
Underpayments, Overpayments, Lost Opportunities and Bankruptcies: Trends and Happenings in Energy Litigation
At recent conferences, dialogue on trends and notable cases in litigation were an integral part of several presentations and discussions.  Although not typically a preferable option for litigants, these cases can bring light and insight to a number of areas.  Our experiences as expert witnesses can attest that these cases can have a broad-reaching impact for the litigants involved as well as for interested observers and even the community at large.Over the last five years, or so, there has been an overall uptick in cases.  New royalty disputes, while rising steadily overall since 2012 took a big jump in 2015 and then came back down somewhat in 2016 and this year.  Cases having to do with land and lease rights have also risen overall in the past several years.  A recent notable case in this area has been Escondido Resources II, LLC v. Justapor Ranch Company, LLC (Webb County Trial Court 2013-CV7-0011396-D1).Lastly, as we have written about in the past, bankruptcy cases also rose in 2015 and 2016, as the price of oil fell and many operators were unable to pay off large sums of debt.  While the number of oil and gas bankruptcies has since dropped, there are a number of companies that could still be described as distressed that have been unable to solve their balance sheet issues.Three Main Royalty Dispute IssuesIn regards to royalty disputes, there are generally three kinds of issues: (i) failure to pay, (ii) underpayment, and (iii) overpayment.The trend in recent years has been centered mainly on underpayment issues.  Underpayment issues have often times revolved around disputes with post production costs in various lease clauses.  Historically, some notable cases here include Heritage Resources v. Nations Bank (939 S.W. 2nd), Hyder v. Chesapeake (04-12-0769-CV), and French v. Oxy (11-10-00282-CV).In addition, there have been lost opportunity cases that are of note.One such case is Spring Creek et al. v. Hess Bakken IV (14-CV-00134-PAB-KMT).  Both underpayment and lost opportunity issues are present in that case.  In that case Hess Bakken (and later Statoil) was required to pay ORRI’s to Spring Creek, but there were several disputes as to the Defendants’ requirements to pursue new leases and drill additional wells in the area (known as the “Tomahawk Prospect”) which would be subject to payments made to the Plaintiff.  Plaintiffs claimed damages in two areas: (i) the discounted present value of overriding royalty interest on areas of mutual interest (damages ranging between $24.2 million and $59.3 million), and (ii) the potential working interest in the same area ($182-403 million). The court granted a partial summary judgment for the defense denying working interest damages.ConclusionRoyalty underpayment cases are anticipated to remain steady in the current pricing environment.  There is an understandable tension between mineral owners' concern over shrinking payments and operators' concern over profitability and favorable drilling economics.Mercer Capital’s professionals have consulted and testified in a wide variety of energy litigation matters.  We have extensive experience in damages and valuation-related litigation support and assist our clients through the entire dispute process by providing initial consultation and analysis, as well as testimony and trial support.  To discuss a matter in confidence, please call one of our team members.
Do You Know What is in Your Royalty Trust?
Do You Know What is in Your Royalty Trust?
In previous posts, we have discussed the existence of royalty trusts & partnerships and their market pricing implications to royalty owners. To summarize our previous posts, it is important to understand the economic rights and restrictions within the publicly traded royalty trust being used as a “benchmark” before using it as a pricing reference for a royalty interest.For example, many of these publicly traded trusts have a set number of wells generating royalty income at declining rates for multiple years to come. In contrast, some of these trusts participate in a number of wells that have not been drilled, which represent upside potential for investors. The future growth and outlook potential for each of these two example publicly traded trusts is significantly different and a potential investor would want to know the details. The same is true for a privately held royalty interest.Market Observations1There are approximately 21 oil and gas-focused royalty trusts and partnerships publicly traded, as of October 31, 2017. Over the previous two years, the performance of the 21 publicly traded royalty trusts has been a mixed bag.  Fourteen have returned market value losses during the previous two years with an average market value return of negative 31%, six have experienced positive market value returns with an average of positive 33% and one has been flat. Contrast this wide return with the price of crude oil and natural gas which have both increased over the same period. Clearly, there were some winners and losers among the 21 royalty trusts over the previous two years and, noticeably, more losers than winners. Of the winners, the royalty trust with the highest market value return was Mesa Royalty Trust (MRT) (+49%) over the previous two years, with ECA Marcellus Trust I (+36%) and Permian Basin Royalty Trust (+33%) coming in second and third, respectively. Why did Mesa Royalty Trust outperform all other royalty trusts over the previous two years and what is the nature of its economic rights and restrictions? Mesa Royalty Trust (MRT)Description of Assets Owned by MRTThe only asset of MRT includes an overriding royalty interest (ORRI) as described in their latest 10K filing:[MRT owns] an overriding royalty interest (the "Royalty") equal to 90% of the Net Proceeds (as defined in the Conveyance and described below) attributable to the specified interests in properties conveyed by the assignor on that date (the "Subject Interests"). The Subject Interests consisted of interests in certain oil and gas properties located in the Hugoton field of Kansas, the San Juan Basin field of New Mexico and Colorado, and the Yellow Creek field of Wyoming (collectively, the "Royalty Properties")As the 10-K refers, MRT’s asset is an overriding royalty interest in three oil and gas fields within the United States. [For more information on overriding royalty interests, see our post]. These properties are primarily natural gas and natural gas liquid plays in the San Juan Basin2 of New Mexico/Colorado, and the Hugoton Field of Kansas, Oklahoma and Texas3. The Yellow Creek field in Wyoming is not described further in the documents and is assumed to be immaterial in comparison to the San Juan Basin and Hugoton Field assets.Commodity PricesThe price for oil peaked in 2014 near $108 per barrel and close to $8 for natural gas before the collapse of both commodity prices during the 2nd half of the year. The nadir of the decline was during 4Q2015 and 1Q2016 for both oil and gas.  Prices currently stand around $53 per barrel and $3.60 per mcf.Asset ProductionThe following charts tracks the quarterly production for MRT since 2010, as well as a rolling latest twelve month (LTM) production figure. Each chart shows increasing production through 3Q2014 and subsequent decline in production from 4Q2014 through 1Q2016. Quarterly production increased 174% from 1Q2016 to 2Q2017. Much of the increase in market value could be due to the increase in MCFE volume produced by the properties over the previous five quarters. We note that the production decline in MRT followed the commodity price decline. Additionally, the subsequent ramp up in production during 2Q2016 through 2Q2017 followed the stability and increase in commodity prices. The combination of production and commodity price increases during the previous five quarters resulted in increases of distributions to unit holders in MRT by approximately 375% from 1Q2016 to 2Q2017. This type of activity is rare for an overriding royalty interest. While commodity prices can be very volatile, production is normally a steady decline except for improvements from existing well workovers. It is not normal to see ORRI’s impacted by the addition of new wells. Judging by the significant increase in production, more research is needed to understand exactly what is impacting the ORRI owned by MRT. To do that, first consider the details within 10K regarding the ORRI owned by MRT and the economic rights and restrictions afforded. Economic Rights and Restrictions for a Unit Holder in MRTThe following is excerpted from the 2016 Annual Report.The Trust was created on November 1, 1979. On that date, Mesa Petroleum Co., predecessor to Mesa Limited Partnership ("MLP"), which was the predecessor to MESA Inc., conveyed to the Trust an overriding royalty interest (the "Royalty") equal to 90% of the Net Proceeds (as defined in the Conveyance and described below) attributable to the specified interests in properties conveyed by the assignor on that date (the "Subject Interests"). …Under the Conveyance, the Trust is entitled to payment of 90% of the Net Proceeds (as defined in the Conveyance), realized from Subject Minerals (as defined in the Conveyance), if and when produced from the Royalty Properties…The Conveyance provides for a monthly computation of Net Proceeds. "Net Proceeds" is defined in the Conveyance as the excess of Gross Proceeds, received by the working interest owners during a particular period over operating and capital costs for such period. "Gross Proceeds" is defined in the Conveyance as the amount received by the working interest owners from the sale of Subject Minerals, subject to certain adjustments. Subject Minerals mean all oil, gas and other minerals, whether similar or dissimilar, in and under, and which may be produced, saved and sold from, and which accrue and are attributable to, the Subject Interests from and after November 1, 1979. Operating costs mean, generally, costs incurred on an accrual basis by the working interest owners in operating the Royalty Properties, including capital and non-capital costs. If operating and capital costs exceed Gross Proceeds for any month, the excess plus interest thereon at 120% of the prime rate of Bank of America is recovered out of future Gross Proceeds prior to the making of further payment to the Trust. The Trust, however, is generally not liable for any operating costs or other costs or liabilities attributable to the Royalty Properties or minerals produced therefrom. The Trust is not obligated to return any royalty income received in any period.To chart the above narrative, here is the “waterfall” from mineral production to MRT Income. In addition to the above “waterfall,” MRT is not obligated to return any royalty income received in any period for any purpose, including losses incurred in future periods. Based on the “waterfall” analysis and the limited liability of future losses, it appears the asset owned by MRT functions more closely with a “profits interest” and less like an ORRI. ORRI’s typically participate at the revenue level and take a percentage off the top. They function much like royalty interests except for certain restrictions on the length of time they can receive royalties and a defined set of wells to which they have rights to production. In contrast, a “profits interest” is defined thusly: The award consists of receiving a percentage of profits from a partnership without having to contribute capital to the partnership.As the revenues available to MRT must go through several layers of cost for operations, capital expenditures and adjustments for losses incurred in prior periods before flowing through to MRT, the similarities are more akin to a profits interest versus an interest in the revenues (i.e. ORRI).ConclusionThe discussion above is the first of several key differences to understand before using MRT as a comparable company for royalty interest holders. We will discuss the other differences related to MRT in a later blog post, most notably the full reason for the increase in production over the previous five quarters.We have assisted many clients with various valuation and cash flow issues regarding royalty interests.  Contact Mercer Capital to discuss your needs in confidence and learn more about how we can help you succeed.End Notes1 Capital IQ 2 http://durangoherald.com/articles/1773963 http://www.bizjournals.com/houston/print-edition/2014/08/08/linn-energy-snatches-up-hugoton-basin-assets-for.html
How to Value Overriding Royalty Interests (1)
How to Value Overriding Royalty Interests
Given that our own Taryn Burgess is attending the 7th Annual National Association of Royalty Owners (NARO) Appalachia Conference in West Virginia today, we decided to revisit this post (originally published in April 2017). Enjoy!What is a Royalty Interest?Ownership of a percentage of production or production revenues, produced from leased acreage. The owner of this share of production does not bear any of the cost of exploration, drilling, producing, operating, marketing or any other expense associated with drilling and producing an oil and gas well.What is an Overriding Royalty Interest (ORRI)?A percentage share of production, or the value derived from production, which is free of all costs of drilling and producing, and is created by the lessee or working interest owner and paid by the lessee or working interest owner.ORRI’s typically do not own a perpetual interest in the mineral rights. Typically they are structured to have rights to royalties for the term of the lease period. Royalty interests, on the other hand, generally have mineral ownership into perpetuity, even after a lease expires. Thus the main difference between royalty interests and ORRI’s is that royalty interests are tied to the ownership of the mineral rights below the surface, and ORRI’s are tied to the lease agreement and ceases to exist once the lease expires.Some may find it surprising that the popular publicly traded Permian Basin Royalty Trust (PBT) only owns ORRI’s, not royalties, in various oil and gas properties in the United States. PBT owns a 75% net ORRI in the Waddell Ranch properties comprising Dune, Judkins, McKnight, Tubb, University-Waddell, and Waddell fields located in Crane County, Texas. As of December 31, 2016, its Waddell Ranch properties contained 349 net productive oil wells, 64 net productive gas wells, and 102 net injection wells.The company also holds a 95% net overriding royalty in the Texas Royalty properties that consist of various producing oil fields, such as Yates, Wasson, Sand Hills, East Texas, Kelly-Snyder, Panhandle Regular, N. Cowden, Todd, Keystone, Kermit, McElroy, Howard-Glasscock, Seminole, and others located in 33 counties in Texas. Its Texas Royalty properties consist of approximately 125 separate ORRI’s containing approximately 51,000 net producing acres.Over the past four years, crude oil and gas prices have fluctuated significantly. While this is creating significant volatility on the E&P side of the industry on both an operational and investment decision level, many look at royalty trusts as a way to bypass the complexities of an operating E&P and attempt to “pure play” the price of oil and gas. Based on this assumption, we will analyze the changes PBT has endured over the past four years.Production PBT derives revenue from ORRI’s which cover approximately 382,000 gross acres (85,205 net acres) in west Texas. Since the ORRI’s that PBT owns were not derived from a 100% working interest, their gross acreage differs from their net acreage. Net acreage is calculated as the company’s percentage interest multiplied by its gross acreage. Over the past four years, the amount of acreage has not changed. Production, on the other hand, has changed significantly as shown in the table below. Comparing the production levels to the price levels of oil and gas indicates that even after the decline in oil and gas prices during 2014, production increased during 2015. Oil production increased 3% while gas production increased 44%. The increased production was in part due to the 3 new wells drilled during 2014, 3 workovers completed during 2014 and 29 wells completed during 2014 and 2015. During 2016, investment activity was significantly different which resulted in a 28% decline in oil production and 33% decline in gas production. No wells were drilled and completed during 2016. Only 1 workover was performed. Clearly, the operators were holding back capital as they waited for more price certainty in the future. Reserves The change in reserves tells the same story. After investing in the drilling and completion of new wells, and workover wells, the proved reserves increased from 2014 to 2015 for both oil and gas. The increase is significant as reserves are impacted by (1) investment in new/existing wells and (2) future prices of oil and gas. The price utilized in the 2015 reserves was significantly lower than what was used in the 2014 reserves. Therefore, the increase in reserves is significant as the additional proved reserves more than countered the reduction in the commodity prices in the reserve model. For 2016, the reserves declined due to the lack of investment in current and future wells. And while pricing stayed relatively the same from 2015 to 2016, the loss in proved reserves was directly attributed to the lack of investment in new and existing wells. Distributions PBT is at its lowest yield in the last four years. While the price was lower at the end of 2015, the dividend as a percentage of price was higher in 2015 relative to 2016. The above chart shows the impact of (1) changes in oil and gas prices; as well as (2) changes in production levels. These two areas are directly related to the dividend per share. The price, however, is directly related to the movement of buyers and sellers of PBT securities. While the dividend is “trailing” information, because it is the result of the previous 12 months of activity, the price factors in forward-looking information. For example, as of 2013, buyers and sellers of PBT were expecting higher dividends in 2014 due to the high price of oil and gas, PBT’s investment in wells and increasing proved reserves1. When commodity prices declined during 2014, the price quickly reflected the new pricing environment, the impact on reserves, and the shift in management’s investment attitude for new and existing wells. All of these factors pressured prices downward while the trailing dividends showed strength, resulting in a higher than normal yield. During 2015 and 2016, the price, dividend, and yield settled to relatively tempered levels. All data points above have had enough time to reflect the current environment and as such, are communicating a similar story. Finishing ThoughtWhen valuing a royalty interest or ORRI, here are a few items to keep in mind:Understand the rights and restrictions of the subject royalty interest: Royalty interests may have value into perpetuity as it is a direct ownership in the minerals;ORRI’s typically only have value for the life of the lease;Understand the differences between the subject ORRI and a publicly traded security that owns ORRI’s and make adjustments for the differences;Understand the historical, current and future outlook for commodity prices relating to the subject ORRI;Understand the historical, current and future outlook for reserves;Utilize publicly traded yields to assess the market's attitude for investments in similar securities; andAdjust for the differences between a publicly traded security and a non-marketable security. When comparing a royalty interest to an ORRI, it is critical to understand the subtle nuances of the rights and restrictions between the two. Owners of royalty interests utilizing PBT as a valuation gauge should adjust for such differences as well as other differences between publicly traded and non-marketable securities.  Contact Mercer Capital to discuss your needs in confidence and learn more about how we can help you succeed. End Note1 Although not shown in the above chart, proved reserves increased 32% between 2012 and 2013 for PBT
Trends in the Refining Industry Display Cautious Optimism
Trends in the Refining Industry Display Cautious Optimism
A general theme across refiners' earnings calls and updates over the last few months was a story of cautious optimism. In this blog post, we outline prevalent general themes in the downstream oil market that have given refiners hope for 2018 as well as those that cause skepticism about the future.Sweet & Sour DifferentialThe price differential between light, sweet crude and heavy, sour crude has been shrinking since the fall of oil prices in 2014.  From a max differential of $42.50 in December 2012, the differential has fallen to an average of $11 over the last month."OPEC cuts have impacted the available supply of medium and heavy sour grades resulting in narrow feedstock differentials which is a challenge to our complex refining system." – Thomas J. Nimbley, Chairman and CEO at PBF Energy on Second Quarter Earnings Call The differential has been shrinking as the global supply of oil has remained high causing crude benchmark prices to converge.  Since the price of light, sweet U.S. crude has fallen, the cost savings that companies used to realize when purchasing heavy feedstock cannot make up for the higher costs of cracking it.Retrofitting RefineriesAs explained by Canada Oil Sands Magazine, "Refineries typically blend different grades of crude with varying quality specifications. Depending on the configuration of the refinery, each facility has a limited ability to handle heavy grades of crude and Sulphur."  U.S. refineries were traditionally retrofitted to handle heavy crude because it allowed for higher refining margins.  The U.S. traditionally has more complex refineries than Europe and Canada, which allows them to better crack heavy molecules into light, value-add products, such as jet fuel.However, starting in mid-2014, US refiners began struggling to keep up with the amount of light sweet crude available for sale in the US markets since most refineries were not built to handle such light crude.  It was thought that the initial relaxation and eventual elimination of the crude oil export ban would relieve US refiners from this pressure.  But the over-supply of oil across the globe dampened this effect.Because the price of light, sweet crude and heavy, sour crude has started to converge, there is potential for higher margins from light crude.  Even if refiners have to pay the upfront investment costs to retrofit their facilities to handle lighter crude, they can face lower operating expenses going forward as it is easier to refine light crude than heavy crude into higher margin products."We expect to see improved margin capture as we are now able to upgrade components of our gasoline pool into higher octane, low sulfur finished product." -Thomas J. Nimbley, Chairman and CEO at PBF Energy on Second Quarter Earnings CallWidened Crack SpreadThe crack spread is the price differential between crude oil and its refined oil products.  The 3-2-1 crack spread approximates refinery yield using the industry average for refinery production.  For every three barrels of crude oil the refinery processes, it makes two barrels of gasoline and one barrel of distillate fuel. The crack spread is a good indication of refiners' profit margins.  As shown in the chart above, the WTI crack spread increased over the first half of the year giving the downstream markets optimism about the rest of the year to come.  The crack spread peaked at the end of August as many refiners were forced to shut down due to damage caused by Hurricane Harvey and the price of refined products spiked. The spread has since fallen to approximately $17 per barrel of WTI. "The decrease to refining margin was primarily driven by the higher RINs cost, which were partially offset by the increase in the Group 3 2-1-1 crack spread." – Susan M. Ball, CFO & Treasure of CVR Refining GP LLC on CVRR’s Second Quarter Earnings CallHigher RIN CostsThe Renewable Fuels Standards (RFS) Program has continued to have a significant impact on the refining sector over the last year.  The RFS were signed into law by President George W. Bush in order to reduce greenhouse gas emissions and boost rural farm economies.  Each November, the EPA issues rules increasing Renewable Fuel Volume Targets for the next year. RINs (Renewable Identification Numbers) are used to implement the Renewable Fuel Standards.  At the end of the year, producers and importers use RINs to demonstrate their compliance with the RFS.  Refiners and producers without blending capabilities can either purchase renewable fuels with RINs attached or they can purchase RINs through the EPA’s Moderated Transaction System. While large, integrated refiners have the capability to blend their petroleum products with renewable fuels, small- and medium-sized merchant refiners do not have this capability and are required to purchase RINS, which have significantly increased in price.RIN expenses have remained high and although President Trump promised to help small- and medium-sized merchant refiners who were disadvantaged by RFS, he also spoke fondly of the RFS program during his campaign.On July 5, 2017, the EPA issued proposed volume requirements under the Renewable Fuel Standard program, which are summarized below. A public hearing was held on August 1, 2017, and on October 17, 2017, the EPA provided a public notice and an opportunity to comment on potential reductions in the 2018/ 2019 biomass-based diesel, advanced biofuel, and total renewable fuel volumes.  The final rule should be available in December. ConclusionRefiners were generally optimistic about their performance over the first six months of 2017. Higher crack spreads have allowed margins to increase and many believe that the Trump administration will help relieve some of the pressure caused by the RFS. Additionally, it is possible that the RFS volume requirements could be reduced further which would relieve margin pressure for merchant refiners.The quote below from HollyFrontier’s second-quarter earnings call appropriately summarizes the current state of the industry."Our refining outlook for 2017 remains cautiously optimistic. We anticipate solid economic growth will continue to support refined product demand and sustained growth in domestic crude oil production will lead to improved crude differentials. We are also optimistic that a more favorable regulatory environment could provide a tailwind for both the refining industry and the economy as a whole. With a large portion of our scheduled maintenance behind us, we are poised for strong financial and operational performance for the remainder of the year." – George J. Damiris, CEO, President, & Director at HollyFrontier – on Second Quarter Earnings CallMercer Capital has significant experience valuing assets and companies in the energy industry, throughout the upstream, midstream, and downstream sectors.  Our oil and gas valuations have been reviewed and relied on by buyers and sellers and Big 4 Auditors. These oil and gas related valuations have been utilized to support valuations for IRS Estate and Gift Tax, GAAP accounting, and litigation purposes. We have performed oil and gas valuations and associated oil and gas reserves domestically throughout the United States and in foreign countries. Contact a Mercer Capital professional today to discuss your valuation needs in confidence.
Held (or Held Up?) by Production
Held (or Held Up?) by Production
Oftentimes differences are a matter of perspective.  Put another way – one person’s loss can be another person’s gain.  One of the thematic differences between producers and mineral owners is their perspective on "Held By Production."  It elicits very different reactions depending on what side of the term one is on, and has a leverageable impact on value.  In this post, we decided to spend some time exploring this concept and its impact on the energy industry.What Is "Held By Production"?Held By Production ("HBP") is a mineral lease provision that extends the right to operate a lease as long as the property produces a minimum quantity of oil and gas. The definition of HBP varies contractually by every lease it governs which is often misunderstood.  We have had discussions with a number people, including peers (as well as knowledgeable industry participants) who did not have a clear grasp of HBP and its exact meaning.  Some people thought HBP was governed by state law, regulatory agencies, or even accounting rules.  However, the truth is that the facts and circumstances that shape a lease as it pertains to HBP are all negotiable.  Therefore, by extension, the outcome of lease negotiations can have a spectrum of results: from being deemed balanced, to favoring the lessor (i.e., the mineral owner) or the lessee (i.e., the producer). When we attended the NAPE Expo this summer, presenters from Wood Mackenzie pointed out that a trend on recent analyst calls was for management teams of operators to highlight the percentage of their leases that were HBP  (they mentioned that the Permian Basin was about 95% HBP due to decades of prior drilling).  Operators want investors to note this and (hopefully) be more attracted to their stock. Why might someone be more attracted to an operator’s stock that has a large percentage of leases HBP?  Investopedia puts it this way:The "held by production" provision enables energy companies to avoid renegotiating leases upon expiry of the initial term. This results in considerable savings to them, particularly in geographical areas that have become "hot" due to prolific output from oil and gas wells. With property prices in such areas generally on an upward trend, leaseholders would demand significantly higher prices to renegotiate leases.What Does "Held By Production" Mean to Mineral Owners (Lessors)?Mineral owners should have an understanding of how their lease terms impact drilling activity (and by extension – royalty payments) on their properties (a thematic element of the summer NARO conference). Lessors are challenging operators’ decisions not to drill on their land, even if prospects appear to be good. As a result, mineral owners are more interested in how certain clauses and term structures function in their leases.  A session at the NARO conference centered on how mineral owners could legally terminate their lease in order to re-lease their property to a more "motivated" or even "competent" operator.Therefore, it is important for mineral owners to understand two lynchpin concepts as they pertain to defining HBP: the Pugh Clause and the Implied Covenant to Develop.Pugh ClauseThe Pugh Clause is named after Lawrence Pugh, a Crowley, Louisiana attorney who developed the clause in 1947, apparently in response to the Hunter v. Shell Oil Co., 211 La. 893 (1947). In this case the Louisiana Supreme Court held that production from a unit, including a portion of a leased tract, will maintain the lease in force as to all lands covered by the lease even if they are not contiguous. This clause is most often cited in today in pooling for horizontal wells. There have been situations (depending on the clause’s language) whereby one well might maintain a large area (thousands of acres) defined as HBP. This is to an operator’s advantage and a mineral holder’s chagrin. However, this can be negotiated to the mineral holder’s favor – particularly in active markets and basins. For example, we had a client that had a large tract of land in the Eagle Ford shale and was being courted by a number of eager operators. Ultimately, they negotiated a lease with an operator who contractually obligated the company to drill three wells per year on the property for the duration of the lease. Not too long after the lease was negotiated, the price of oil dropped in half and the operator was much less enthusiastic about having to drill three wells per year. There are a number of nuances and factors to Pugh clauses (and similar lease clauses) that we won’t explore here, but suffice to say, it is a critical factor to defining a property as HBP or not.Implied Covenant to DevelopAnother aspect of lease law is centered around the concept called "Implied Covenant to Develop."  Sometimes a lessors' alternative is to attempt to find remedy through the implied obligation that the lessee failed to develop and operate the property as a reasonably prudent operator.  Forcing an implied obligation generally occurs through a lawsuit and is difficult to prove.  However, implied covenants have been addressed by courts from all producing states as well as the Supreme Court of the United States.There are several potential examples  One example is discussed on a Gas & Oil Law blog:Consider an oil and gas lease taken on 200 acres. Let’s say that thirty years ago one well was drilled on the 200 acre lease, and that this well unit only included 40 acres.  Under the implied covenant to reasonably develop, a judge may very well cancel the lease to the remaining, unused 160 acres (200 acres – 40 acres = 160 acres).  How could a judge do that?  The basic question that needs to be answered is whether or not the oil and gas producer has behaved as a reasonable oil and gas producer would in similar circumstances.  If any reasonable producer would have drilled more than one well on the 200-acre lease, then a reviewing judge might void the lease to the remaining 160 acres.  However, if the existing well was not a very good well, then it might be that the producer did behave reasonably when they decided not to drill additional wells.ConclusionDepending on which side of the negotiation one is on, HBP can be a favorable (or unfavorable) contributor to value. As such, it's crucial to have an analyst who possesses knowledge from all sides of industry negotiations.Mercer Capital has over 20 years of experience valuing assets and companies in the oil and gas industry. We have valued companies and minority interests in companies servicing the E&P industry and assisted clients with various valuation and cash flow issues regarding royalty interests. Contact one of our oil and gas professionals today to discuss your needs in confidence.
How Do Post-Production Deductions Affect the Value of Your Oil and Gas Royalty Interest?
How Do Post-Production Deductions Affect the Value of Your Oil and Gas Royalty Interest?
I recently attended the National Association of Royalty Owners (NARO) National Convention in Dallas, Texas.  The seminars on lease negotiations, mineral management, shale drilling, and more were all interesting and informative, but there was one topic that was brought up in almost every session: Post-Production Deductions (PPDs).From the first Board Meeting to the last session of the conference, post-production deductions were discussed in great detail.  Why were these deductions brought up time and time again? Because post-production deductions affect the value of a mineral owner’s interest yet the regulations surrounding them is somewhat unclear and exists mainly on a contractual basis.What are Post-Production Deductions?The Marcellus Shale Coalition defines post-production deductions (PPDs) as “the expenses incurred in order to get the gas from the wellhead to market.”  These costs include gathering, compression, processing, marketing, dehydrating, transportation, and more.  PPDs vary significantly between operators and between oil fields because the quality of the products and the distance to market differ.In its raw form, natural gas has little value.  In order to make it more marketable, the gas has to be processed so that it is ready to be transported and sold.   When an operator markets the product so that it can be sold at a higher price, the royalty owner also benefits if the new net price is greater than the price they would have received.Are PPDs legal?Royalty interests represent a share of net revenue, which means that royalty owners get their share of gross revenue and their share of appropriate expenses. “But,” you say, “I thought royalty owners don’t share in the costs of production!”  That is true.  Royalty owners are not responsible for costs associated with research, exploration, drilling, or any other aspects of production; but they can be liable for their share of expenses generated post-production.In December 2016, the West Virginia Supreme Court decided that EQT (and therefore other operators) can “not deduct from that (royalty) amount any expenses that have been incurred in gathering, transporting or treating the oil or gas after it has been initially extracted, any sums attributable to a loss or beneficial use of volume beyond that initially measured or any other costs that may be characterized as post-production”.  However, in May of this year, the West Virginia Supreme Court reversed its previous decision from last year, allowing post-production deductions for gathering, transporting, or treating gas after extracted.  As summarized in WV Supreme Court Reverses Itself, Post-Production Deductions OK, the court said that, “oil and gas companies may use “net-back” or “work-back” methods to calculate royalties owed but that the “reasonableness” of those expenses in specific instances may be decided by future court cases.”In general, the matter of post-production deductions is generally a contractual one between the lessee and lessor.   The Louisiana law review says that in general there are three kinds of royalty clauses: (1) the proceeds clause, (2) the market value clause, and (3) the market price clause.  The proceeds clause requires that royalty owners be paid a percentage of the actual amount of proceeds, net proceeds, or gross proceeds that the company received. Unless otherwise specified the owner should be paid proceeds determined at the well not at the place of sale.  According to Louisiana state law the market value clause allows the owner to determine the hypothetical price that a willing buyer would pay a willing seller for the product while the market price clause requires the operator to pay the royalty owner the actual price received at market.  Both, however, allow the royalty owner to be charged for transportation and marketing costs.Future court cases will likely better define the level of post-production deductions that are considered to be fair to both the royalty owner and the operator. But it is important that royalty owners familiarize themselves with the current laws surrounding mineral rights and post-production deductions in the states in which they own mineral rights.How Do PPDs Affect the Value of Your Royalty Interest?The effect that PPDs have on royalty interests can be explained by one of the fundamental concepts of business valuation: value is a factor of cash flow, growth, and risk. PPDs directly reduce cash flow which reduces the value of a royalty interest as shown by the equation above.  Additionally, the lack of a “no-deducts” clause in a lease agreement increase the risk associated with an interest.  Even if a royalty owner does not currently pay post-production deductions, there is the possibility that the operator could charge PPDs in the future which increases risk.  In our white paper titled, “How to Value an Oil and Gas Royalty Interest,” we explain how market and the income approach together can give a complete picture of value. ConclusionThe National NARO convention had educated speakers who talked on a broad range of topics.  The organization encourages royalty owners to ask questions and continue learning no matter how long they have worked in the industry.  The convention reminded me why industry expertise is so important in the field of business valuation.  In order to fully understand the operations of a business, an analyst must have knowledge of all aspects of the industry.  Mercer Capital has over 20 years of experience valuing assets and companies in the oil and gas industry. We have valued companies and minority interests in companies servicing the E&P industry and assisted clients with various valuation and cash flow issues regarding royalty interests. Contact one of our oil and gas professionals today to discuss your needs in confidence.
EP Fourth Quarter 2017 Region Focus Marcellus Utica
E&P Fourth Quarter 2017

Region Focus: Marcellus & Utica

Region Focus: Marcellus & Utica Oil prices closed the year reaching $60 per barrel, WTI futures prices returned to backwardation, and oil price volatility was relatively calm as the price stayed within an $18 band all year ($42 – $60).
Impact and Perspective on Hurricane Harvey’s Aftermath: Transforming
Impact and Perspective on Hurricane Harvey’s Aftermath: Transforming
Some friends and neighbors of ours drove down to Houston this past weekend to assist with the recovery and cleanup effort in the wake of Hurricane Harvey (we were left with the much easier job of watching one of their children for a few days).They used to live in Houston and were moved to go down and help in relief efforts.  They, along with a group from their church, came back yesterday with stories and photos of mold from floor to ceiling, throwing housefuls of furniture to the curb, and dead fish that managed to find their way through the floodwaters into people’s living rooms.  To add to the loss, the majority of people affected were not covered by flood insurance.However, one thing that was not lost was unyielding dignity, hope, and courage that pulsated throughout the city.  This was the most uplifting news to emerge out of the wreckage.  As our friends described it, the experience was “transforming” on many levels.The Immediate and Residual Impact of HarveyDon Stowers – Chief Editor of the Oil & Gas Financial Journal recently wrote an editorial on the impact of Hurricane Harvey from an industry perspective. It too was transforming.According to the editorial - companies now are only beginning to assess the damages.  More than 20% of the oil production from the Gulf of Mexico was taken offline with additional onshore volumes shut-in.  Four terminals in Corpus Christi were closed to tanker traffic.  Nearly 50% of the nation’s refining capacity is located along the Gulf Coast and at least 10 refineries were shut down before the storm’s arrival.  This was felt here in Dallas as long lines and gas shortages were common for some days after the storm.  However, this is anticipated to be more widespread.  NYMEX gasoline contracts spiked to their highest levels in two years.  Analysts say this will continue for months following the storm.The good news is that the industry will recover in a matter of months.  Terminals will re-open.  Shipping will resume and gas prices will likely return to lower levels.  However, it will take longer for a number of other people to recover.Yet we remain encouraged by the resilient spirit of the people affected and the scores of inspiring people who are continuing to demonstrate the transformative power of the golden rule: Do to others what you would wish for them to do to you.  Have a great week.
How to Value an Oil & Gas Royalty Interest
How to Value an Oil & Gas Royalty Interest
A lack of knowledge regarding the worth of a royalty interest could be very costly. This can manifest itself in a number of ways. A shrewd buyer may offer a bid far below the interest’s fair market value; opportunities for successful liquidity may be missed; or estate planning could be incorrectly implemented based on misunderstandings about value. Understanding how royalty interests are properly appraised will ensure that you maximize the value of your royalty, whenever and however you decide to transfer it.The purpose of this whitepaper is to provide an informative overview regarding the valuation of mineral royalty interests within the oil and gas industry.
How to Value Your Exploration and Production Company
How to Value Your Exploration and Production Company
A lack of knowledge regarding the value of your business could be very costly. Opportunities for successful liquidity may be missed or estate planning could be incorrectly implemented based on misunderstandings about value. In addition, understanding how exploration and production companies are valued may help you understand how to grow the value of your business and maximize your return when it comes time to sell.The purpose of this whitepaper is to provide an informative overview regarding the valuation of exploration and production (E&P) companies operating in the oil and gas industry.
How to Value Your Exploration and Production Company
WHITEPAPER | How to Value Your Exploration and Production Company
A lack of knowledge regarding the value of your business could be very costly. Opportunities for successful liquidity may be missed or estate planning could be incorrectly implemented based on misunderstandings about value. In addition, understanding how exploration and production companies are valued may help you understand how to grow the value of your business and maximize your return when it comes time to sell.The purpose of this whitepaper is to provide an informative overview regarding the valuation of exploration and production (E&P) companies operating in the oil and gas industry.
How to Use Reserve Reports When Determining Fair Market Value
How to Use Reserve Reports When Determining Fair Market Value
Last week, Lucas Paris analyzed the SEC’s $6.2 million settlement with a Big 4 audit firm relating to auditing failures associated with Miller Energy Resources, an oil and gas company with activities in the Appalachian region of Tennessee and in Alaska. In late 2009, Miller acquired certain Alaskan oil and gas interests for an amount the company estimated at $4.5 million. The company subsequently assigned a value of $480 million to the acquired assets, resulting in a one-time after-tax bargain purchase gain of $277 million. Following the deal, the newly acquired assets comprised more than 95% of Miller’s total reported assets.The SEC order determines that the Big 4 audit firm did not properly use the reserve reports conclusion of PV-10 (present value at 10%).This post considers the proper use of reserve reports and risk adjustment factors when determining fair market value.What Is Fair Market Value?The American Society of Appraisers defines the fair market value as:The price, expressed in terms of cash equivalents, at which property would change hands between a hypothetical willing and able buyer and a hypothetical willing and able seller, acting at arm’s length in an open and unrestricted market, when neither is under compulsion to buy or sell and when both have reasonable knowledge of the relevant facts.1Treasury Regulation Section 1.611-1(d)(2) provides guidance in determining the fair market value of oil and gas properties.  It similarly provides that “the fair market value of an [oil and gas] property is the amount which would induce a willing seller to sell and a willing buyer to purchase.”  Additionally, Section 1.611-2(g) outlines some considerations that a valuation of mineral properties must include for tax-oriented appraisals.  A summary of these considerations is shown in the chart below.A review of Treasury Regulations 1.611-2(g) clearly demonstrates that an analyst must do more than rely on reserve reports when determining fair market value.What Is a Reserve Report?The SEC defines reserves as “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.”A reserve report is prepared by a petroleum engineer who estimates the remaining quantities of oil and gas and categorizes them based on the likelihood that they will be produced.  There are three main categories of proved reserves (P1) which are distinguished in a reserve report. Proven reserves are defined to have at least a 90% probability of being recovered.Proved Developed Producing (PDP) reserves are defined by the OJFG as “the estimated remaining quantities of oil and gas anticipated to be economically producible, as of a given date, by application of development projects to known accumulations under existing economic and operating conditions.”Proved Developed Non-Producing (PDNP) reserves are proven reserves “that can be expected to be recovered through existing wells and existing equipment and operating methods.”Proved Undeveloped (PUDs) reserves are proven reserves “that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for completion.” Other reserve categories include probable (P2) and possible (P3) reserves, which must exceed 50% and 10% probability of recovery, respectively. Reserve reports estimate future production of all proved reserves. From this, they predict future revenue and future expenses and discount the net income using a 10% standard discount rate.  PV-10 is the resulting estimate of the present value of the company’s cash flow from proved oil and gas reserves. It is standardized value which provides consistency across public companies filings.  However, PV-10 is not necessarily an accurate representation of fair market value. PV-10 assumes that all categories or proved reserves are equally risky.  In reality, a potential buyer would not pay as much for an interest in PUD acreage as they would for PDP acreage because there is substantially more risk associated with the PUD acreage. If a valuation expert had been hired to do a purchase price allocation for Miller Energy’s acquisition of oil and gas interest in Alaska, PV-10 would not have been used as the fair market value.  Rather, a valuation specialist with industry expertise would have performed a discounted cash flow analysis and evaluated how certain risks that pertain to each asset affect the value.How to Use a Reserve ReportThe income approach is generally accepted among industry professionals as the most accurate representation of fair market value of oil and gas interests, and the reserve report can be used as one of the main sources of information for the inputs of the discounted cash flow.  Treasury Reg 1.611-2(e)(4) provides a straightforward outline of how the approach should be used.  In general, a discounted cash flow analysis is the method of choice.In practice, the income approach requires that:The appraiser project income, expense, and net income on an annual basisThus, revenue and expense projections used in the income approach can be directly harvested from this report.Each year’s net income is discounted for interest at the “going rate” to determine the present worth of the future income on an annual and total basisThis is where a reserve report and a calculation of fair market value differ.  While a reserve report uses a standard 10% discount rate, when determining fair market value a discount rate which considers potential risk factors should be developed.  An analyst could add a risk premium for each reserve category to adjust a baseline WACC or they could account for this risk in a separate adjustment. The total present worth of future income is then discounted further, a percentage based on market conditions, to determine the fair market value.PV-10 treats PDP, PDNP, and PUDs the same. However, there are uncertainties and opportunities associated with PUDs that are not captured in the discount rate used for all proved reserves.  A risk adjustment factor could be used to the discounted present value of cash flows according to the category of the reserves being valued to account for PUDs upside and uncertainty by reducing expected returns from an industry weighted average cost of capital (WACC).  What About Probable and Possible Reserves?Reserve reports only account for proven reserves; they do not estimate the value of possible and probably reserves which are less likely to be recovered.  While less certain, there is still some potential upside of the Probable and Possible reserve categories.  In order to estimate the value of probable and possible reserves the market approach can be used.The market approach is a general way of determining a value indication of an asset by using one or more methods that compare the subject to similar assets that have been sold.  Because reserve values vary between oil and gas plays and even within a single play, finding comparable transactions is difficult. A comparable sale must have occurred at a similar time due to the volatile nature of oil and gas prices.  A comparable sale should be for a property that is located within the same play and within a field of similar maturity.If transactions show premiums over the value of proven reserves, then the buyer likely was paying for something else in addition to the proved reserves; he was likely paying for the less certain upside potential of probable and possible reserves.  Through these transactions, the value of these reserves can be understood as they vary by basin and between fields.  In many basins probable and possible reserves may currently be worthless because the price of oil may not rebound to a point where it would be economical to explore for and drill these reserves; however, in fields such as the Delaware and Midland Basins in the Permian recent transactions tell a different story.The valuation implications of reserves and acreage rights can swing dramatically in resource plays. While a reserve report is helpful, it does not measure fair market value or fair value.  Utilizing an experienced oil and gas reserve appraiser can help to understand how location impacts valuation issues in this current environment. Contact Mercer Capital to discuss your needs and learn more about how we can help you succeed.End Notes1 American Society of Appraisers, ASA Business Valuation Standards© (Revision published November 2009), “Definitions,” p. 27.
How to Value an Oil & Gas Royalty Interest
WHITEPAPER | How to Value an Oil & Gas Royalty Interest
A lack of knowledge regarding the worth of a royalty interest could be very costly. This can manifest itself in a number of ways. A shrewd buyer may offer a bid far below the interest’s fair market value; opportunities for successful liquidity may be missed; or estate planning could be incorrectly implemented based on misunderstandings about value. Understanding how royalty interests are properly appraised will ensure that you maximize the value of your royalty, whenever and however you decide to transfer it.The purpose of this whitepaper is to provide an informative overview regarding the valuation of mineral royalty interests within the oil and gas industry.
$475 Million Bargain Purchase Leads to a SEC Settlement
$475 Million Bargain Purchase Leads to a SEC Settlement
Originally published on Mercer Capital's Financial Reporting Blog, Lucas Parris analyzed the SEC’s $6.2 million settlement with a Big 4 audit firm relating to auditing failures associated with Miller Energy Resources, an oil and gas company with activities in the Appalachian region of Tennessee and in Alaska.In late 2009, Miller acquired certain Alaskan oil and gas interests for an amount the company estimated at $4.5 million. The company subsequently assigned a value of $480 million to the acquired assets, resulting in a one-time after-tax bargain purchase gain of $277 million. Following the deal, the newly acquired assets comprised more than 95% of Miller’s total reported assets. Was it a bargain purchase or not?Paris’ post examines the particulars of the case and provides some observations on fair value accounting that can be gleaned from the SEC settlement order.Bargain Purchase BackgroundA bargain purchase results when the fair value of the assets acquired exceeds the purchase price. If a transaction is determined to be a bargain purchase, the acquirer must recognize a gain on its income statement. Bargain purchases can be the result of a distressed seller or the lack of recognition of a contingent liability. In practice, bargain purchases are uncommon, and typically require a reassessment of the identifiable assets acquired, liabilities assumed, and consideration transferred to confirm that such a transaction has occurred.Miller’s Acquisition of the AssetsAccording to the SEC Order, Miller went public via a reverse merger in 1996. Between 2002 and 2009, its stock price regularly traded below one dollar per share and the firm reported net losses in all years. In late 2009, Miller learned that certain oil and gas interests located in Alaska (the “Alaska Assets”) were in the process of being legally “abandoned” in connection with a bankruptcy proceeding. The Alaska Assets included leases covering 602,000 acres of mostly unproven exploratory oil and gas prospects, five operative oil and gas wells located mainly on two fields, two major facilities, and an offshore platform.The prior owner had marketed the assets for nearly a year, culminating in a court-sponsored auction that produced bids of $7.0 million and $8.1 million. However, neither bidder closed on the bids. A second competitive auction occurred, in which Miller outbid a competing entity whose parent company was, at the time, the largest land drilling contractor in the world. Miller’s winning bid was $2.25 million in cash plus the assumption of $2.2 million in liabilities. The transaction closed December 10, 2009.Accounting for the AcquisitionIn its quarterly SEC filing following the transaction, Miller assigned a fair value of $480 million to the acquired assets. The primary assets were the oil and gas properties ($368 million) and fixed assets ($110 million).Oil and Gas Properties – To establish the fair value of the oil and gas assets, Miller relied upon a reserve report prepared by a third-party petroleum engineering firm under the guidelines for supplemental oil and gas disclosures (ASC 932). The SEC Order stipulated that this was improper because the report itself expressly disclaimed that any of its estimates were estimates of fair value. In other words, the report was prepared for another purpose and with a different accounting/valuation premise than is required under the fair value guidance of ASC 820 and ASC 805. The SEC Order noted that the reserve report estimates were improper from a fair value perspective because the report failed to incorporate an appropriate discount rate and risk adjustments for certain speculative reserve categories. The report was also alleged to contain understated and unsubstantiated cost forecasts, which had been originally provided to the engineering firm by Miller.Fixed Assets – Miller valued the acquired fixed assets (facilities and ancillary pipelines) at $110 million. However, the SEC Order noted that the basis for the $110 million figure was an insurance report that actually contained no third-party analysis – the figure was actually provided to the insurance broker by Miller and then referenced as if it was independently derived by the broker. Furthermore, the SEC indicated that the recording of a separate $110 million fixed asset was double-counting, because these assets were necessary to produce the oil and gas reserves and were already included in the $368 million reserve report value.Role of the Audit FirmMiller Energy replaced its prior independent audit firm in February 2011 (about a year after the acquisition of the Alaska Assets). The new Big 4 firm provided audit reports for Miller, with unqualified opinions, for fiscal 2011 through 2014. The SEC Order states that the firm failed to comply with certain auditing standards, including the requirement to analyze the impact of Miller’s opening account balances (including the value of its oil and gas properties) on the current year financial statements.The SEC Order alleges that the auditors failed to obtain sufficient competent evidence regarding the impact of the opening balances on the current year financial statements, despite knowing that no proper fair value assessment had been performed by management in the prior year. While the audit firm did undertake some audit procedures, it failed to appropriately consider the facts leading up to the acquisition including the competitive bidding process and the “abandonment” of the assets by the prior owner. The SEC Order also noted that the auditor failed to detect the double-counting of fixed assets in the opening balances.Fair Value ObservationsThe SEC Order contains extensive discussion of the auditing and review process as it relates to Miller’s Alaska Assets, which we will not attempt to summarize here. Instead, we will discuss a few of the key themes that emerge from our reading.Bargain Purchases Should Require Additional Scrutiny – It should go without saying, but if a $4.5 million purchase results in a $472 million gain on the income statement (over 100x), there should be a healthy dose of professional skepticism from all sides (management, auditors, and valuation specialists). Every transaction is unique, and perhaps the facts and circumstances support it, but one should be wary if the magnitude of the bargain is large. As an aside, one would think that potential investors would be wary of such an accounting treatment as well, without adequate and supportable disclosures.Proper use of valuation reports – The reserve reports relied upon by Miller management did not contain fair value measurements. Perhaps they were entirely appropriate for the purpose for which they were prepared, but that purpose was not fair value for ASC 805 compliance.Industry Expertise – The partner-in-charge and senior manager on the Miller engagement had no prior experience with oil and gas companies, which the SEC Order indicates resulted in departures from professional standards during the audit process. The SEC Order, citing an AICPA Auditing & Accounting Guide, states that when a client’s business involves unique and complex accounting, as in the case of the oil and gas industry, the need for the engagement partner to understand the client’s industry is even more important. In our opinion, the importance and benefit of industry expertise extends to the valuation specialist as well. Mercer Capital has performed purchase price allocations for clients across a variety of industries and transaction structures, including those giving rise to bargain purchases. We also have significant experience valuing assets and companies in the energy industry, primarily oil and gas, bio fuels and other minerals. Contact a Mercer Capital professional today to discuss your valuation needs in confidence.Related LinksA Buyer’s Market: Accounting for Bargain PurchasesIn the Eye of the Beholder: Increasing SEC Scrutiny of Public Company Fair Value MarksMisleading Purchase Accounting Results in SEC Complaint and Fines for CVSSEC Signals Increased Focus on Financial ReportingThe Fair Market Value of Oil and Gas Reserves
Summer NAPE Expo: Observations & Thoughts
Summer NAPE Expo: Observations & Thoughts
Mercer Capital attended the Summer NAPE Expo in Houston this month.  Founded in 1993 by AAPL, with the addition of IPAA, SEG, and AAPG as partners over the next several years, NAPE is a well-known venue for oil and gas professionals to meet, network, and do business; it was a terrific event.  The Expo also included a conference covering various industry issues.  The session speakers were mostly a mix of company executives and industry analysts, including Wood Mackenzie.  The presentations covered a number of supply and demand issues including:Market efficiencies in light of the low-cost environmentComments on various basins (Permian, Eagle Ford, Haynesville)Continued growth of drilled uncompleted wells (“DUC’s”)Market EfficienciesThere continues to be a relative market oversupply in both oil and gas.  According to Wood Mackenzie, there may be approximately 1700 TCF of natural gas that could breakeven at $3.00/mcf.  That’s a 20-year supply for the U.S.  LNG is oversupplied because the U.S. is putting a ceiling on LNG prices.  However, there are signs of a move towards more of a balance; for example, we are starting to see some slight inventory drawdowns and the market may find creative ways to create demand for some of these plentiful resources. All of this is being accomplished in light of significant industry capex drops since 2014. However, we are starting to witness growth again in 2017 for spending. This is corresponding with the increase of rig counts. Basin CommentaryAnalysts from Wood Mackenzie noted that the breakeven for new wells in the Permian Basin was at the bottom of the global cost curve.  Some areas of the Permian are at a $35 per barrel breakeven level.  In addition, it was mentioned that the Permian could match the Marcellus shale in natural gas production (to say nothing of oil and liquids) in the future.  This significantly differentiates the Permian Basin in comparison to other plays.However, the Permian is not the only basin with favorable economics.  Technology and innovation have pushed other areas along.  For example, the Eagle Ford shale play is sustainable at today’s prices and the Haynesville Shale has had a “roller coaster” of activity lately.  Some areas of the Haynesville can model gas as low as $2.40/mcf and still have a profitable well.  BP, Exxon, and Exco all have activity in the Haynesville area.Continued Growth of DUC’sDUC’s are growing quickly and the market continues to pay more attention to them.  In fact, the EIA this month included the Anadarko basin for the first time in its DUC data and drilling report. Two years ago this metric caught the industry’s attention.  However, there are questions as to exactly how much potential inventory these DUC’s represent.  It was noted that DUC wells may be comprised of lower estimated ultimate recovery (EUR) and may not have as much excess inventory as otherwise thought. In addition, completion crews are taking longer to perform jobs than before (6-7 days as opposed to 4-5).  With drilling times going down and completion times going up, we are seeing a higher DUC count. One other interesting drilling related note from the conference was that an emerging theme (previously rarely, if ever, discussed) on analyst calls for publicly traded companies has to do with the percentage of acreage controlled by companies that is held by production (HBP).  In fact, most of the Permian is 95% HBP – due to decades of prior drilling.  It appears companies want investors to know that there isn’t as much of a requirement for companies to drill going forward. TakeawaysThe marketplace remains excited about the potential for the Permian Basin.  Although there continues to be a supply glut, the U.S. is well positioned to continue to have positive economics due to increasingly efficient operations, technology, and innovation.  More and more basins are beginning to catch up to the Permian in terms of efficiency and rig counts reflect this.However, our biggest takeaway was meeting and getting to know a plethora of new people.  The conversations were terrific, and we enjoyed getting to know all of you.  We look forward to seeing you at future NAPE events as well.If you were there, let us know your thoughts and comments about NAPE.  We would love to hear them.  Have a great week!
How to Value Proven Undeveloped Reserves (PUDs)
How to Value Proven Undeveloped Reserves (PUDs)
One of the primary challenges for industry participants when valuing and pricing oil and gas reserves is addressing proven undeveloped reserves (PUDs) and unproven reserves.  While the market approach can sometimes be used to understand the value of PUDs and unproven reserves, every transaction is unique.  Additionally, many transactions that we see today are still a result of the crash in oil prices in 2014; and in some sales of non-core assets, PUDs and unproven reserves have been deemed worthless.  Why then, and under what circumstances, might the PUDs and unproven reserves have significant value?Optionality ValueThe answer lies within the optionality of a property’s future DCF values.  In particular, if the acquirer has a long time to drill, one of two forces come into play: either the PUDs potential for development can be altered by fluctuations in the current price outlook for a resource, or, as seen with the rise of hydraulic fracturing, drilling technology can change driving significant increases in the DCF value of the unproven reserves.This optionality premium or valuation increment is often most pronounced in unconventional resource play reserves, such as coal bed methane gas, heavy oil, or foreign reserves. This is additionally pronounced when the PUDs and unproven reserves are held by production. These types of reserves do not require investment within a fixed short timeframe.PUDs are typically valued using the same discounted cash flow (DCF) model as proven producing reserves after adding in an estimate for the capital costs (capital expenditures) to drill. Then the pricing level is adjusted for the incremental risk and the uncertainty of drilling “success,” i.e., commercial volumes, life and risk of excessive water volumes, etc. This incremental risk could be accounted for with either a higher discount rate in the DCF, a RAF or a haircut.  Historically, in lower oil price environments like we face today, a raw DCF would suggest little to no value for PUDs or unproven reserves in a number of plays and basins.In practice, undeveloped acreage ownership functions as an option for reserve owners; they can hold the asset and wait until the market improves to start production. Therefore an option pricing model can be a realistic way to guide a prospective acquirer or valuation expert to the appropriate segment of market pricing for undeveloped acreage.Adaptation of Black Scholes Option ModelThe PUD and unproved valuation model is typically seen as an adaptation of the Black Scholes option model.  The Black Scholes option model is a widely used model used to develop the value of European-style options. The adaptation is most accurate and useful when the owners of the PUDs have the opportunity, but not the requirement, to drill the PUD and unproven wells and the time periods are long, (i.e. five to 10 years).  The value of the PUDs thus includes both a DCF value, if applicable, plus the optionality of the upside driven by potentially higher future commodity prices and other factors.  The comparative inputs, viewed as a real option, are shown in the table below. When these inputs are used in an option pricing model the resulting value of the PUDs reflects the unpredictable nature of the oil and gas market.  This application of option modeling becomes most relevant near the lower end of historic cycles for a commodity.  In a high oil price environment, adding this consideration to a DCF will have little impact as development is scheduled for the near future and the chances for future fluctuations have little impact on the timing of cash flows.  At low points, on the other hand, PUDs and unproved reserves may not generate positive returns and, thus, will not be exploited immediately. If the right to drill can  be postponed for an extended period of time, (i.e. five to ten years), those reserves still have value based on the likelihood they will become positive investments when the market shifts at some point in the future.  In the language of options, the time value of the out-of-the-money drilling opportunities can have significant worth.  This worth is not strictly theoretical either, or only applicable to reorganization negotiations.  Market transactions with little or no proven producing reserves have demonstrated significant value attributable to non-producing reserves, demonstrating the recognition by the pool of buyers of this optionality upside. ConclusionWe caution, however, that there can be limitations in the model’s effectiveness, as we describe in Bridging Valuation Gaps, Part 3.   Specific and careful applications of assumptions are needed, and even then Black Sholes’ inputs do not always capture some of the inherent risks that must be considered in proper valuation efforts.  Nevertheless, option pricing can be a valuable tool if wielded with knowledge, skill, and good information, providing an additional lens to peer into a sometimes murky marketplace.Today’s marketplace is particularly murky, and a quality appraisal is extremely valuable, since establishing reasonable and supportable evidence for PUD, probable and possible reserve values may assist in a reorganization process that determines the survival of a company, or the return profile for a potential investment, or simply standing up to third-party scrutiny.  Given these conditions we feel that the benefits of using option pricing far outweigh its challenges.Mercer Capital has significant experience valuing assets and companies in the energy industry, primarily oil and gas, bio fuels and other minerals. Contact a Mercer Capital professional today to discuss your valuation needs in confidence.
Oil and Gas Investors Note Move Away From Contango
Oil and Gas Investors Note Move Away From Contango
The Wall Street Journal recently published an encouraging article, “Oil Prices Flash a Buy Signal,” explaining that futures contracts are trending to a flat curve.  Ever since the fall in crude oil prices in mid-2014, the market has remained in contango, signaling that the industry still faced rough times ahead.  The current movement away from contango and toward backwardation is the first positive forward price estimate since 2014 and oil and gas investors are taking note.  Before we jump into the details, let’s review the possible commodity market conditions. What is Contango/ Backwardation?ContangoF < E(S)A contango market simply means that the futures contracts are trading at a premium to the spot price.  Contango is the result of an “oversupplied market with abundant inventories.”  For example, if crude oil is trading at $45 per barrel right now, and the six month contract is trading at $50, the market is said to be in contango.   For the last three years, we have been operating in a contango market.BackwardationF > E(S)Backwardation (or normal backwardation), on the other hand, is a symptom of an “undersupplied market with tight stockpiles.” If crude oil is trading at $45 per barrel right now, and the six month contract is trading at $40 per barrel, then that market would be said to be in a backwardation.It currently appears that pricing in the future contracts are moving closer to backwardation. The table below shows the future contract spread for the previous 13 months. The most recent data returns the narrowest spread since 2014 of ($0.73) compared to one year ago when the market had a wider contango spread of ($5.72). To break down the significant change over the previous three years, the chart below shows the 2014, 2016, and 2017 WTI futures curve for 24 months and the spread between Month 1 and Month 24. Positive spread indicates backwardation, while negative spread indicates contango. What is not clear, however, is the cause for the flattening curve. Is the cause on the supply side or demand side? Barron’s recently highlighted the improved economic outlook for the industry.  Their investment strategists pointed at two factors which are helping keep crude oil prices steady and may lead to increases in the future.  First, inventories are lower at this year than they were last year at this time. Second, the value of the dollar is falling which could cause the price of crude to rise. However, their optimism was accompanied by cautiousness.  After Pioneer’s recent losses, we are reminded that even the Permian Basin is not protected from difficulties. Many investors have started to worry about the fate of the Permian Basin.  Some companies have reported that they are producing more natural gas and natural gas liquids than previously expected and as oil wells age, they tend to produce more natural gas. ConclusionThe movement in the future spread away from a contango environment and toward backwardation is positive from a supply and demand perspective. Expectations are a backwardation environment will move crude oil prices higher. However, the exact cause of this change is unknown.  While this shift is good news for the industry, company specific risk and investor's fickle attitudes create volatile equity markets.Mercer Capital has significant experience valuing assets and companies in the oil and gas industry, primarily oil and gas, bio fuels, and other minerals.  Our oil and gas valuations have been reviewed and relied on by buyers and sellers and Big 4 auditors. These oil and gas-related valuations have been utilized to support valuations for IRS estate and gift tax, GAAP accounting, and litigation purposes. We have performed oil and gas valuations and associated oil and gas reserves domestically throughout the United States and in foreign countries. Contact a Mercer Capital professional today to discuss your valuation needs in confidence.
3 Things to Know Before Selling Your Oil and Gas Royalty Interest
3 Things to Know Before Selling Your Oil and Gas Royalty Interest
There are many reasons that you may want to sell your oil and gas royalty interest, but a lack of knowledge regarding the worth of your royalty interest could be very costly.  Whether an inflow of cash would help you make ends meet or finance a large purchase; you no longer want to deal with the administrative paperwork or accounting cost of reconciling monthly revenue payments; or you would prefer to diversify your portfolio or move your investments to a less volatile industry, understanding how royalty interests are valued will ensure that you maximize the value.There is a market for royalty interests, making them fairly liquid; therefore, most of the time, the difficulty is not finding a buyer, but determining whether the buyer’s offer is appropriate.Given that many royalty owners have little connection with the oil and gas industry aside from the monthly payments they receive, buyers may bid substantially below a royalty’s fair market value hoping to earn a profit at the expense of an uninformed seller. As such, it is critical that royalty owners looking to liquidate their interest understand its value to ensure that they can identify legitimate bids.We believe there are three points you need to understand before attempting to sell your mineral interest.1. Understand What You Are SellingA royalty interest represents a percent ownership in the revenue of an E&P company.  Royalty interest owners have no control over the drilling activity of the operator and do not bear any costs of production. Royalty interest owners only receive revenue checks when their operator is producing minerals but see no monthly payments when production is suspended.12. Recognize Production and Price as Value driversThe value of a royalty interest is based on the present value of expected future cash flows, which are a percentage of an operator’s revenue.An operator’s revenue is dependent upon production and price.  Thus, when determining the value of a royalty interest, it is critical to understand a well’s future potential for production and the market forces that affect price.Production: The Decline Curve’s ImpactAs oil and gas is extracted from a well, its production declines over time.  Every well has a unique decline curve which dictates production. A decline curve graphs crude oil and natural gas production and allows us to determine a well’s Estimated Ultimate Recovery (EUR).   A variety of factors can affect the shape of a well’s decline curve.  For example, decline curves are generally much steeper if the well is drilled using unconventional techniques, like horizontal drilling, or hydraulic fracturing. When determining the value of an oil and gas royalty interest, it is critical to understand a well’s EUR because the value of your royalty interest is dependent upon future production.Price: Local and Global Market ForcesOil and gas prices are affected by both global and local supply and demand factors.  The oil and gas industry is characterized by high price volatility.  The size and global nature of this market mean that these prices are influenced by countless economic – and sometimes political – factors affecting individual producers, consumers, and other entities that comprise the global market.  Most operators, however, sell their oil and gas at a slight discount or premium to the NYMEX because of local surpluses or shortfalls.  Thus, it is important to understand the local market as well. For example, natural gas in the Marcellus and Utica sells at a substantial discount to the NYMEX due to the lack of infrastructure carrying gas out of the region.3. Understand Location’s ImpactDrilling economics vary by region. There are geological differences between oilfields and reserves that make it harder to drill in some places than others. Whereas some wells can be drilled using traditional, conventional techniques like vertical drilling, less permeable shale wells must be drilled using unconventional methods, like horizontal drilling or hydraulic fracturing. These unconventional methods tend to bear higher operating costs. Location also tends to influence drilling and transportation costs, ultimately making breakeven prices and profits vary across and within regions. Although a royalty interest owner is paid before any operating expenses are accrued, an operator considers break-even pricing when determining whether to continue operating a well or suspending operations. Accordingly, the value of any royalty interest is strongly influenced by its location, and it is important to consider geological differences when valuing any mineral interest.What to Look Out ForWhile there are legitimate online brokers who will buy your royalty interest for a fair price, it is important to be on the lookout for those who aim to profit at your expense.Since the crash in oil prices, many royalty owners stopped receiving royalty checks; however, this does not mean your royalty interests are worthless.   One warning sign to be aware of is online royalty brokers who only consider rules of thumb such as 4x to 6x annual revenue.While industry benchmarks can be a helpful aid, they should not be relied upon solely to determine value, as they do not consider specific well economics.If the entity valuing your interest is also an interested party, it is critical to remember that they have an incentive to quote a low value.Mercer Capital is an employee-owned independent financial advisory firm with significant experience (both nationally and internationally) valuing assets and companies in the energy industry (primarily oil and gas, bio fuels and other minerals).  Our oil and gas valuations have been reviewed and relied on by buyers and sellers and Big 4 Auditors.As a disinterested party, we can help you understand the fair market value of your royalty interest and ensure that you get a fair price for your interest. Contact anyone on Mercer Capital’s Oil & Gas team to discuss your royalty interest valuation questions in confidence.End Note1 For more information on mineral interests see our recent post, Three Types of Mineral Interests.
Corporate Finance in 30 Minutes Whitepaper
Corporate Finance in 30 Minutes Whitepaper
Travis W. Harms, senior vice president of Mercer Capital, wrote a series of whitepapers that focused on demystifying corporate finance for board members and shareholders. In this whitepaper, he has distilled the fundamental principles of corporate finance into an accessible and non-technical primer. Structured around the three key decisions of capital structure, capital budgeting, and dividend policy, this whitepaper is designed to assist directors and shareholders without a finance background to make relevant and meaningful contributions to the most consequential financial decisions all companies must make. Mercer Capital’s goal with this whitepaper is to give directors and shareholders a vocabulary and conceptual framework for thinking about strategic corporate finance decisions, allowing them to bring their perspectives and expertise to the discussion.Mercer Capital has significant experience valuing assets and companies in the oil and gas industry, primarily oil and gas, bio fuels and other minerals.  We also provide financial education services to family businesses.  We help family ownership groups, boards, and management teams align their perspectives on the financial realities, needs, and opportunities of the business.   Contact a Mercer Capital professional today to discuss your needs in confidence.Click here to read Corporate Finance in 30 Minutes.
Trends in the Oil and Gas Industry
Trends in the Oil and Gas Industry

Then & Now

You don’t need an expert to tell you that the oil and gas industry has significantly changed over the past three years. Simply looking at crude oil and natural gas prices from 2014 versus today can confirm this.  However, understanding how the change in oil prices has affected the value of your oil and gas business is a little more difficult.Looking Back at the Price TrendIn early 2014, a barrel of oil cost more than twice what it does today. Three years ago the oil and gas industry appeared to be on an upward trend. Industry revenues were expected to increase over the next several years, oil prices (which were holding around $100/barrel) were expected to rise, and futures prices had already jumped, indicating that oil would become more expensive.  Some analysts even believed that if the Iraq crisis escalated, crude oil prices could surpass $120/bbl.  U.S. production increased, and for the first time in four years, demand in developed nations was expected to increase as well. Although there was concern about political instability in Iraq, due in large part to Al Qaeda activity, many saw 2014 as a “great entry point” into the energy industry.   In the Fortune article “Energy Bulls Are Ready for a Run,” Craig Hodges, CEO of Hodges Capital said, “The opportunities are fantastic, and we’re in the very early innings of a renaissance in the energy industry.”Looking back, we know that the oil and gas narrative strongly deviated from expectations. After peaking at $107.95/barrel on June 22, 2014 oil prices began to spiral downward, ultimately reaching record lows in the first quarter of 2016 at just over $26/barrel. As a result of this price crash, more than 120 upstream and oilfield companies were forced into bankruptcy over the next two years.Looking Beyond PriceAs exemplified by the collapse of oil prices in mid-2014, market shifts can be hard to anticipate.  Our professionals closely track trends and events affecting the oil and gas markets, analyzing their value implications. Many focus only on the decline in prices, but countless other factors have also fundamentally changed the industry over the past three years affecting oil and gas valuations. While there are far too many to list in full here, some highlights are included below.The Export BanIn December 2015, Congress lifted an export ban that kept all domestic crude oil within the U.S. for the past 40 years (with the exception of exports to Canada). In January 2016, the first shipments of oil left U.S. ports for Europe. Many analysts saw this as “symbolic of the country’s newfound role as a lead producer of oil,” and noted that the U.S. could now serve as a stable supplier in an energy market where many suppliers are located in regions fraught with unrest. This trend has continued by supplying China with significant quantities of crude oil in recent months.Improved Drilling TechnologyAdoption of innovative drilling techniques, such as horizontal drilling and hydraulic fracturing, has made production quicker, easier, and cheaper, while also unlocking reserves that were previously regarded as unattainable. Due in large part to technological advances, U.S. crude oil production has risen 10% since prices began to recover in late 2016. By cutting producer costs, technology allowed producers to continue operations in low price environments, which would have previously forced them to shut down. According to Rystad Energy analysis, “Since 2013, the average wellhead breakeven price (BEP) for key shale plays has dropped from US$80/barrel to US$35/barrel. This represents a decrease of over 55%, on average.”U.S. ShaleLargely as a result of improved technology, the U.S. Shale Revolution greatly impacted the oil and gas industry. As mentioned above, various drilling technologies unlocked shale plays throughout the U.S., particularly in the Bakken and Marcellus regions. Increased shale production significantly added to the U.S. oil supply, which is expected to be 800 mb/d greater in 2017 than it was in 2016. U.S. shale survived the 2014 oil price crash with cost cuts and lower breakeven prices and emerged more resilient from the downturn. On a global scale, U.S. production gains have essentially counteracted OPEC’s production cuts. Because the breakeven price for many U.S. shale plays has dropped, uncertainty looms regarding how low commodity prices must drop before U.S. producers will scale back production. The following graph shows U.S. oil and gas production over the past ten years.Political InstabilityMany oil and gas suppliers are located in regions fraught with civil and political unrest. In 2014, analysts focused on what impact potential disruptions in Iraqi oil supply, due to Al Qaeda activity, may have on the global market. While no longer centered on Iraq, concerns about political instability persist within the industry. Today, analysts are looking to the Persian Gulf to determine if unrest, particularly in Qatar, will alter the industry’s trajectory.The simultaneous impact of each of the events discussed here (among countless others) has flipped the oil and gas industry on its head, allowing the U.S. to become more energy independent and to grow its market share. While this is great news for the U.S. from an economic, security, and defense perspective, it is threatening to other countries – notably to historically influential producers like Saudi Arabia and Russia. As the U.S. continues to garner market share, political relationships are due to shift, likely impacting the oil and gas industry.Implications on Oil and Gas ValuationsMercer Capital tracks the performance of exploration and production companies across different mineral reserves in order to understand how the current pricing environment affects operators in each region. The dramatic drop in price, by itself, materially impacted the value of all companies operating within the oil and gas industry – upstream, midstream, or downstream.  Of 60 companies Mercer Capital tracks in the E&P oil and gas industry, 81% saw their market cap decrease over the past three years, by an average of 26.63% and a median of 46.85%. The graph below shows different regions stock performance over the past three years. As shown above, as a result of the myriad of changes within the oil and gas industry, company values today are not what they were three years ago. Like many industries, the oil and gas industry not only changes quickly but it also changes dramatically. In order to set a proper context for the valuation, it is crucial to understand the industry climate as of your valuation date. Over the past three years, opening U.S. oil to exports, increasing driller productivity due to gains in technology, and the shale revolution have created an oversupply of oil, which has driven the price of oil down. While our analysts cannot say for certain what’s coming next for this industry, we invite you to follow these trends with us. Mercer Capital has significant experience valuing assets and companies in the oil and gas industry, primarily oil and gas, bio fuels and other minerals.  Our oil and gas valuations have been reviewed and relied on by buyers and sellers and Big 4 Auditors. These oil and gas related valuations have been utilized to support valuations for IRS Estate and Gift Tax, GAAP accounting, and litigation purposes. We have performed oil and gas valuations and associated oil and gas reserves domestically throughout the United States and in foreign countries. Contact a Mercer Capital professional today to discuss your valuation needs in confidence. Our thanks to Paige Klump who drafted and did much of the research for this post in collaboration with our Energy Group.
The Fair Market Value of Oil and Gas Reserves
The Fair Market Value of Oil and Gas Reserves
Oil and gas assets represent the majority of value of an E&P company. The Oil and Gas Financial Journal describes reserves as “a measurable value of a company's worth and a basic measure of its life span.”  Thus, understanding the fair market value of a company’s PDP, PDNP, and PUDs is key to understanding the fair market value of the Company.  As we discussed before, the FASB and SEC offer reporting guidelines regarding the disclosure of proved reserves, but none of these represent the actual market price.  It is especially important to understand the price one can receive for reserves as many companies have recently sold “non-core” assets to generate cash to pay off debt and fund operations.  It is especially important to understand the price one can receive for reserves as many companies have recently sold “non-core” assets to generate cash to pay off debt and fund operations.The American Society of Appraisers defines the Fair market value as:The price, expressed in terms of cash equivalents, at which property would change hands between a hypothetical willing and able buyer and a hypothetical willing and able seller, acting at arm’s length in an open and unrestricted market, when neither is under compulsion to buy or sell and when both have reasonable knowledge of the relevant facts.1The American Society of Appraisers recognizes three general approaches to valuation: (1) The Cost Approach, (2) The Income Approach, and (3) The Market Approach.  The IRS provides guidance in determining the fair market value of an oil and gas producing property.  Treasury Reg. 1.611–2(d) offers that if possible the cost approach or comparative sale approach should be used before a discounted cash flow analysis (DCF).  When valuing acreage rights comparable transactions do provide the best indication of value.  However, when valuing reserves, a DCF is often the best way to allocate value to different reserve categories because comparable transactions are very rare as the details needed to compare these specific characteristics of reserves are rarely disclosed.Cost ApproachThe cost approach determines a value indication of an asset by considering the cost to replicate the existing operations of an asset. The cost approach is used when reserves have not been proved up and there have been no historical transactions, yet a participant has spent significant time, talents, and investments into exploratory data on an oil and gas prospect project.Market ApproachThe market approach is a general way of determining a value indication of an asset by using one or more methods that compare the subject to similar assets that have been sold.Because reserve values vary between oil and gas plays and even within a single play, finding comparable transactions is difficult. A comparable sale must have occurred at a similar time due to the volatile nature of oil and gas prices.  A comparable sale should be for a property that is located within the same play and within a field of similar maturity.  Additionally, comparable transactions must be thoroughly analyzed to make sure that they were not transacted at a premium or discount due to external factors.  Thus, the market approach is often difficult to perform because true comparable transactions are rare. However, the transaction method generally provides the best indication of fair market value for acreage and lease rights.Income ApproachThe income approach estimates a value indication of an asset by converting anticipated economic benefits into a present single amount.  Treasury Reg 1.611 – 2(e)(4) provides a straightforward outline of how the approach should be used.In practice, this method requires that: The appraiser project income, expense, and net income on an annual basisEach year's net income is discounted for interest at the "going rate" to determine the present worth of the future income on an annual and total basisThe total present worth of future income is then discounted further, a percentage based on market conditions, to determine the fair market value. The costs of any expected additional equipment necessary to realize the profits are included in the annual expense, and the proceeds of any expected salvaged of equipment is included in the appropriate annual income. Although the income approach is the least preferred method of the IRS, these techniques are generally accepted and understood in oil and gas circles to provide reasonable and accurate appraisals of hydrocarbon reserves, and most closely resembles the financial statement reporting requirements discussed in our previous post.  This method is the best indication of value when a seismic survey has been performed and reliable reserve estimates are available.  In order to properly account for risk, we divide the reserves by PDP, PDNP, PUD, Probable, and Possible reserves.  We will review the key inputs in a DCF analysis of oil and gas reserves below.Cash InflowsIn order to estimate revenue generated by an oil and gas reserve, we must have an estimate of production volume and price.  Estimates of production are collected from Reserve reports which are produced by geological engineers.The forward price curve provides monthly price estimates for 84 months from the current date.  Generally, the price a producer receives varies with the price of benchmark crude such as WTI or Brent. Thus, it is important to carefully consider a producers contract with distributors. For example a company may sell raw crude to the distributor at 65% of Brent.Cash OutflowsMany E&P companies do not own the land on which they produce. Instead they pay royalty payments to the land owner as a form of a lease payment.  Royalty payments are generally negotiated as a percentage of the gross or net revenues derived from the use of the property.  Besides royalty payments and daily operating costs, it is important to have conversations with management to understand future infrastructure maintenance and capital expenditures.DiscountOil and gas reserves can be based on pre-tax or after-tax cash flows.  Pre-tax cash flows make reserve values more comparable as tax rates vary by location.  When using pre-tax cash flows, we use a pre-tax cost of debt and pre-tax cost of equity to develop a WACC.Risk Adjustment FactorsWhile DCF techniques are generally reliable for proven developed reserves (PDPs), they do not always capture the uncertainties and opportunities associated with the proven undeveloped reserves (PUDs) and particularly are not representative of the less certain upside of the Probable and Possible reserve categories.  A risk adjustment factor could be used to the discounted present value of cash flows according to the category of the reserves being valued to account for PUDs upside and uncertainty by reducing expected returns from an industry weighted average cost of capital (WACC).  You could also add a risk premium for each reserve category to adjust a baseline WACC, or keep the same WACC for all reserves but discount the present value of the cash flows accordingly with comparable discounts to those shown below. The low oil price environment forced many companies to sell acreage and proved reserves in order to generate cash to pay off debt.  In order to create a new business models in the face of low oil prices, it is critical for companies to understand the value of their assets.  The valuation implications of reserves and acreage rights can swing dramatically in resource plays. Utilizing an experienced oil and gas reserve appraiser can help to understand how location impacts valuation issues in this current environment. Contact Mercer Capital to discuss your needs and learn more about how we can help you succeed. End Notes1 American Society of Appraisers, ASA Business Valuation Standards© (Revision published November 2009), “Definitions,” p. 27.
How to Value an Oil and Gas Refinery
How to Value an Oil and Gas Refinery
When valuing a business, it is critical to understand the subject company’s position in the market, its operations, and its financial condition. A thorough understanding of the oil and gas industry and the role of refineries is important in establishing a credible value for a business operating in the oil and gas refining space.Oil and Gas Supply ChainThe oil and gas industry is divided into three main sectors:Upstream (Exploration and Production)Midstream (Pipelines)Downstream (Refineries) Exploration and production (E&P) companies search for reserves of hydrocarbons where they can drill wells in order to retrieve crude oil, natural gas, and natural gas liquids.  E&P companies then sell the commodities to midstream companies who use gathering pipelines to transport the oil and gas to refineries.  Refiners convert raw crude and natural gas into products of value, such as transportation fuels.Oil and Gas Refinery OperationsCrude oil itself has little end use.  Refiners create value by converting crude oil into various usable products.  Transportation fuels, such as gasoline, diesel, and jet fuel, are some of the most commonly produced refined products.  Other refined products include heating and lighting fluid, such as kerosene, lubricating oil and waxes, and asphalt.  Refineries are capital intensive and their configuration depends largely on their physical location, available crude oils, product requirements, and environmental standards.Valuing an oil and gas refinery requires the consideration of a wide range of issues (far too many to list in full here), with primary considerations as outlined below.The price of inputs. The price of crude oil fluctuates due to changes in world demand and supply.  Many refiners hold large volumes of crude inventory, but as the price of crude oil fluctuates, refiners face risk associated with the falling value of their inventory. Thus, in order to reduce risk refiners should shorten their timeline from purchasing crude oil to selling the finished product and/or use derivatives to hedge the risk associated with volatile oil prices.The price of refined products. There are four main components to refined product prices: (1) Crude Oil Prices, (2) Wholesale Margins, (3) Retail Distribution Costs, and (4) Taxes.  Generally, input prices and wholesale margins drive fluctuations in product prices as the last two are relatively stable.  However, President Trump has indicated that he hopes to lower corporate taxes.Crack spread. A refiner’s margins are generally determined by the crack spread, which measures the prices of refined products compared to the cost of crude oil.  The price of transportation fuels generally moves in sync with the prices of crude oil, but the price of some refined products such as asphalt and lubricating oils is not as closely correlated with crude oil price changes.Environmental regulation. The refining industry has historically been heavily regulated.  Regulations such as the RTR & NSPS aim to control air pollution from refineries and provide the public with information about refineries’ air pollution.  President Trump is working to establish a more energy friendly environment and has signaled his intention to sign the repeal of many methane emission regulations if the repeal is passed through both Houses of Congress.Heavy vs. light crude. Most U.S. refineries were built to process heavy crude.  However, the onset of U.S. shale drilling has led to a surplus of light sweet crude that U.S. refineries were not originally built to process.  While the refining process of heavy and light crude is generally the same, the refining of light crude is less costly.Oil and Gas Refinery Financial AnalysisWhen valuing a business, it is critical to understand the subject company’s financial condition. A financial analyst has certain diagnostic markers that tell much about the condition of a business.Balance Sheet. The balance sheet of a refinery is dominated by inventory and fixed assets.  According to RMA’s annual statement studies, 16.3% and 32.2% of petroleum refineries’ assets are inventory and fixed assets, respectively.1   Because refining is a capital intensive business, it is important to consider the current operating capacity of a company’s fixed assets in order to determine if future growth will require significant capital expenditures.  If a refinery hopes to expand refinery throughput beyond the current refining capacity, it will have to invest in more equipment.Income Statement.  The development of ongoing earning power is one of the most critical steps in the valuation process, especially for businesses operating in a volatile industry environment.  Cost of goods sold account for approximately 75% of sales according to the RMA data.  Thus it is important to consider possible supplier concentrations when analyzing the income statement because disruptions in the supply chain can have significant income statement impacts to oil refineries.How Does Valuation Work?There are fundamentally three commonly accepted approaches to value: asset-based, market, and income.  Each approach incorporates procedures that may enhance awareness about specific business attributes that may be relevant to determining the final value. Ultimately, the concluded valuation will reflect consideration of one or more of these approaches (and perhaps several underlying methods) as being most indicative of value for the subject interest under consideration.The Asset-Based ApproachThe asset-based approach can be applied in different ways, but in general, it represents the market value of a company’s assets minus the market value of its liabilities. Investors make investments based on perceived required rates of return, and only look at assets as a source of rate of return. Oil and gas refineries are asset intensive businesses. They have distillers, crackers, cokers, and more.  While an asset value consideration can be a meaningful component of the overall valuation of an oil and gas refinery, it is essentially the income generated by these assets that typically drives the value of a business. For this reason, the asset-based approach is typically not the sole (or even primary) indicator of value.The Market ApproachThe market approach utilizes market data from comparable public companies or transactions of similar companies in developing an indication of value. In many ways, this approach goes straight to the heart of value: a company is worth what someone is willing to pay for it.In the downstream oil and gas sector, there are ample comparable public companies that can be relied on to provide meaningful market-based indications of value. Such options are Alon US Energy Inc., CVR Refining, LP, Valero Refining, and Western Refining.  Acquisition data from industry acquisitions (typically a median from a group of transactions) can be utilized to calculate a valuation multiple on the subject company’s performance measure(s). This will often provide a meaningful indication of value as it typically takes into account industry factors (or at least the market participants’ perception of these factors) far more directly than the asset-based approach or income-based approach.   Additionally earnings multiples such as EV/ EBITDA can be used to calculate indication of values.The market-based approach is not a perfect method by any means. For example, industry transaction data may not provide for a direct consideration of specific company characteristics. Say a company is a market leader and operates in a prime geographic market. Since the market and the specific company are relatively more attractive than the average transaction, the appropriate pricing multiple for this company is likely above any median taken from a group of industry transactions. Additionally, many companies in the oil and gas industry are vertically integrated and have significant midstream or marketing operations in addition to their refining operations.  For example, Marathon Petroleum Company is a leading refiner in the US, but is also a marketer of refined products and has significant midstream operations.  Clearly, the more comparable the companies and the transactions are, the more meaningful the indication of value will be.  When comparable companies are available, the market approach can provide a helpful indication of value and should be used in determining the value of a refinery.The Income ApproachThe income approach can be applied in several different ways. Generally, such an approach is applied through the development of an ongoing earnings or cash flow figure and the application of a multiple to those earnings based on market returns. An estimate of ongoing earnings can be capitalized in order to calculate the net present value of an enterprise.  When determining ongoing earnings historical earnings should be analyzed for non-recurring and non-normal income and expenses which will not affect future earnings. The income approach allows for the consideration of characteristics specific to the subject business, such as its level of risk and its growth prospects relative to the market through the use of a capitalization rate.Income is the main driver of value of a business; thus, the income approach should be considered when determining the value of your business.Synthesis of Valuation ApproachesA proper valuation will factor, to varying degrees, the indications of value developed utilizing the three approaches outlined. A valuation, however, is much more than the calculations that result in the final answer. It is the underlying analysis of a business and its unique characteristics that provide relevance and credibility to these calculations. This is why industry “rules-of-thumb” (be they some multiple of revenue, earnings, or other) are dangerous to rely on in any meaningful transaction. Such “rules-of-thumb” fail to consider the specific characteristics of the business and, as such, often fail to deliver insightful indications of value.An owner who is contemplating any kind of transaction or agreement based on value needs to know what their business is worth.  Whether you are selling out or selling in, knowing the fair market value of your business will let you evaluate whether or not an offer for your company is reasonable.  Additionally, many business owners fail to understand the valuation implications of buy-sell agreements. If you have other shareholders in your business who are non-family, and maybe some who are, you probably have some kind of buy-sell agreement between the shareholders that describes how the business (or business interests) will be valued in the event of a shareholder dispute, death, or departure from the business (even on friendly terms). A business owner executing or planning a transition of ownership can enhance confidence in the decisions being made only through reliance on a complete and accurate valuation of the business.Mercer Capital has long promoted the concept of managing your business as if it were being prepared to sell. In this fashion you promote the efficiencies, goals and disciplines that will maximize your value. Despite attempts to homogenize value through the use of simplistic rules of thumb, our experience is that each valuation is truly unique given the purpose for the valuation and the circumstances of the business.Mercer Capital has experience valuing businesses in the oil and gas industry. We hope this information, which admittedly only scratches the surface, helps you better shop for business valuation services and understand valuation mechanics. We encourage you to extend your business planning dialogue to include valuation, because sooner or later, a valuation is going to happen. Proactive planning and valuation services can alleviate the potential for a negative surprise that could complicate an already stressful time in your personal and business life.For more information or to discuss a valuation or transaction issue in confidence, do not hesitate to contact us at 901.685.2120.End Note1 2016-2017 RMA Statement Studies. NAICS #324110. Companies with greater than $25 million in sales.
Refining 2017 Issue 2
Refining | 2017 Issue II
Over the last six months of fiscal 2017, changes in the oil & gas market led to increasing refinery revenues and the expansion of margins.
EP Third Quarter 2017 Region Focus Bakken
E&P Third Quarter 2017

Region Focus: Bakken

Region Focus: Bakken Oil prices remained relatively steady at $50/barrel over the last twelve months despite OPEC’s wavering commitment to production cuts.
EQT’s Acquisition of RICE Energy
EQT’s Acquisition of RICE Energy

Our Valuation Analysis of This Marcellus and Utica Mega Deal

Deal OverviewOn June 19, 2017, EQT announced the acquisition of Rice Energy (RICE) for approximately $6.7 billion. RICE will receive approximately $4.1 billion in EQT common stock and $1.1 billion in cash as well as be relieved from $1.5 billion in net debt that EQT is assuming.Based on EQT disclosures, the assets owned by RICE include (1) 255 wells currently producing 1,145 mmcfe per day (mmcfepd) which are expected to increase to 1,300 mmcfepd; (2) 252,000 in net Marcellus and Utica acres with more than 1,100 net locations remaining to explore; (3) 92% of RICE GP interest including the incentive distribution rights (IDR’s); and (4) 28% of Rice Midstream Partners (RMP). By all accounts, the location of the acreage is contiguous or nearby to EQT’s current acreage and the combination of the two companies will create the largest gas producer in the Marcellus and Utica.Reported Valuation Multiples Do Not Present the Whole PictureIn comparison to other operators in the Marcellus and Utica, the transaction is on the higher end of the range with Antero Resources Corp (AR) and Cabot Oil and Gas (COG) when considering an EV/Daily Production multiple and on the high end with the acreage multiple (See Table 2).  However, the “reported” value multiples may not be the whole picture. We have considered EQT’s offer to RICE shareholders, but RICE’s shareholders only own 28% of Rice Midstream and 92% of the GP interest.  Due to the accounting rules for consolidation, the majority of the income statement and production figures capture activity for 100% ownership (the non-controlling interest is not taken out until the end). Therefore, by not including the non-controlling interest that is consolidated into Rice’s balance sheet, we previously compared less than 100% of the Company’s Enterprise Vale to 100% of the Company’s production, acreage, and EBITDA. What Does the “All In” Enterprise Value Mean to Investors?The non-controlling interest on the balance sheet of RICE amounts to $2.4 billion as of the end of Q1 2017. The offer for $6.7 billion was for the interest RICE owns in the business' assets. Therefore, to compare production and acreage multiples to the publics, we would need to calculate an “all in” enterprise value as shown in Table 3. Under the “all in” approach, the production multiple of 48,415x is well above the other operators in the area (see Table 2) and investors should be excited about the proposed transaction according to the surface data. The EBITDA multiple is not a great indication here as some companies in the guideline group were marginally profitable at the EBITDA level leading to abnormally high EBITDA multiples. In response to the announced transaction, the share price of RICE increased approximately 25% or $1 billion. Based upon our experience in performing valuation services in the Appalachian play, the analysis above appears reasonable. Table 4 shows the previous 20 transactions in the area. Not all transactions could be broken down into producing and non-producing acres; therefore, it is shown as a total price to total net acres multiple. The EQT and Rice transaction shows as the most expensive price / acre transaction of the last 20 in the area. In Chart 1, disclosed by RICE and EQT, shows the acreage position with the resource play for RICE. According to this map, RICE has acreage in some of the most prolific and hottest areas in the Marcellus and Utica. Allocating Assets in This Transaction to Fair ValueConsidering the purchase price implications of the Rice Energy transaction, based upon the publicly disclosed information, the assets to allocate to fair value appear as found in Table 5.Does This Transaction Result in a Marcellus and Utica Mega-Producer?The result of this transaction is the potential creation of a Marcellus and Utica mega-producer with over 1.9 million acres, 591 barrels of daily flowing oil equivalent and a stronghold in the gathering pipelines that can transport gas to the East, Midwest, and South in the near future. The implied enterprise value of $24 billion would approximately double the enterprise value of the company next closest in size, Antero Resources.Further Reading on This DealOver the previous week there have been many articles written on this transaction.  We found the following articles most helpful:Rice Energy News Release: EQT To Acquire Ricer Energy for $6.7 BillionEQT Investor Relations: EQT Corporation to Acquire Rice Energy for $6.7 BillionOil & Gas Financial Journal: EQT to Acquire Rice Energy for $6.7 BHow Four Brothers Survived the Gas Bust to Make Family a BillionEQT to Acquire Rice Energy for $6.7 Billion -- UpdateThe EQT Corporation Acquisition of Rice Energy is SmartWith $8.2B Acquisition, Pittsburg’s EQT Becomes America’s Biggest Natural Gas ProducerMercer Capital’s ExperienceMercer Capital has significant experience valuing assets and companies in the energy industry, primarily oil and gas, bio fuels and other minerals.  Our oil and gas valuations have been reviewed and relied on by buyers and sellers and Big 4 Auditors. These oil and gas related valuations have been utilized to support valuations for IRS Estate and Gift Tax, GAAP accounting, and litigation purposes. We have performed oil and gas valuations and associated oil and gas reserves domestically throughout the United States and in foreign countries. Contact a Mercer Capital professional today to discuss your valuation needs in confidence.
Risk and Return: Working Interests and Royalty Interests
Risk and Return: Working Interests and Royalty Interests
The U.S. Mineral Exchange defines a mineral interest as “the ownership of all rights to gas, oil, and other minerals at or below the surface of a tract of land.” Last week we reviewed the three types of mineral interests – royalty interests, working interests, and overriding royalty interests. This week we analyze the risks associated with working interests versus royalty interests.  An overview of royalty interests and working interests is included below:Royalty Interest – an ownership in production that bears no cost in production. Royalty interest owners receive their share of production revenue before the working interest owners.Working Interest – an ownership in a well that bears 100% of the cost of production. Working interest owners receive their share of the profit after (i) royalty owners have received their share and (ii) after all operating expenses have been paid. Central to corporate finance is the principle that returns follow risk. As the risk of an investment increases, so do potential returns and potential losses; lower risk means less expectation for reward.  The Oil and Gas Financial Journal illustrates oil and gas investment risk in the following graphic: When valuing mineral interests, it is important to consider the nuances of the each type of mineral interest. Given that risk and asset values are indirectly related, it is important to keep in mind the various risk factors which pertain to the mineral interest.  We’ll begin by examining the various risks surrounding both types of interests. RiskBoth working interests and royalty interests are exposed to fluctuations in oil and gas prices. When crude oil prices fell in mid-2014, so did the value of working interests, whose worth is based on the present value of the cash flows generated from production, and the value of royalty interests, whose value is based on future payments of revenue. Further, both working interests and royalty interests face the risk of depletion as oil and gas wells are depleting assets.  Even if the price of oil and gas is stable from one year to the next, a well may have 30% less production in its second year.  This can dramatically decrease the yield of particular royalty and working interests.Holders of working interests can mitigate the risk of depletion by drilling new wells or improving production of existing wells.  While this gives a working interest holder more flexibility, it also requires a substantial investment in CAPEX. Working interest holders accept all fiscal burdens associated with the drilling process.Royalty interest holders, on the other hand, bear no cost of production but are at the mercy of their operators. Only the working interest owner can decide to halt production when prices drop and to increase production when the drilling environment is favorable.  The Oil and Gas Financial Journal compares buying a royalty interest to “buying an income strip in producing wells, and the risks are primarily price volatility and depletion.”Each type of interest has unique attributes, but the fact that working interest owners are responsible for operating expenses makes working interests inherently riskier than royalty interests which are characterized by monthly “mailbox money” precipitated by zero costs. We see this when examining the volatility of select E&P companies who spun off their royalty interests into royalty trusts structured as MLPs. The royalty trusts above generally demonstrate less volatility, which is often used as a proxy for financial risk, than their parent E&P companies.  The principles of risk and return, however, tell us that because there are fewer risks associated with royalty interests they will yield lower returns than their riskier counterparts. Royalty interests range in percentage ownership of revenues from 0.025%-25%, meaning that, at the highest royalty interest, at least 75% of revenue is still funneled to the working interest owners. Due to differences in risk, royalty interests are unlikely to generate the magnitude of returns that working interests can experience. At the same time, they are less likely to experience the same degree of loss. ReturnThe standardized measure of investment performance for a given unit of time is return.  Investment returns have two components.  The first, yield, measures the current income (distributions) generated by an investment.  Capital appreciation, the second component, measures the increase in value during the period.  As shown below, total return is the sum of yield and capital appreciation. Royalty trusts commonly make substantial distributions because they generate revenue as long as their operators are drilling and they have minimal operating expenses. Thus it is important to examine total return when comparing interests in E&P companies, who own working interests, and royalty trusts who own royalty interests. In the chart below we examine the total returns of the companies introduced above and their associated royalty trusts. As expected, the E&P companies which hold working interests show higher returns and steeper losses than their associated royalty trusts. We have assisted many clients with various valuation and cash flow issues regarding royalty interests.  Contact Mercer Capital to discuss your needs in confidence and learn more about how we can help you succeed.
3 Types of Mineral Interests
3 Types of Mineral Interests
The US Mineral Exchange defines mineral interest as “the ownership of all rights to gas, oil, and other minerals at or below the surface of a tract of land.” Mineral interests are divided into three categories – royalty interests, working interests, and overriding royalty interests. Each is defined as follows:Royalty Interest – an ownership in production that bears no cost in production. Royalty interest owners receive their share of production revenue before the working interest owners.Working Interest – an ownership in a well that bears 100% of the cost of production. Working interest owners receive their share of the profit after (i) royalty owners have received their share and (ii) after all operating expenses have been paid.Overriding Royalty Interest (ORRI)– a percentage share of production, or the value derived from production, which is free of all costs of drilling and producing, and is created by the lessee or working interest owner and paid by the lessee or working interest owner. A royalty interest is created when an exploration and production (E&P) company wants to extract gas, oil, or other minerals from privately held property. In this scenario, the E&P company could purchase the land, but it is generally much cheaper and more feasible to lease the rights to drill on the land. Under this type of agreement, the E&P company pays the landowner an up-front payment, called a lease bonus, as well as a monthly royalty payment – a specified percentage of all revenues generated by the minerals extracted from the land. Although the landowner profits from the drilling efforts on their property, they do not pay any production costs. A royalty interest is paid as long as minerals from the land generate revenue. Generally, if production stops so do royalty payments. Very rarely, however, some contracts specify certain levels of production which must be maintained. In the aforementioned situation, while landowners have a royalty interest, the E&P company has a working interest. As a result of the leasing agreement, the E&P company acquires the rights to the minerals on the property. This means that they bear the costs of exploration, drilling, and production, but they have rights to future cash flows generated once the wells are completed. The working interest owner must pay royalty interests, overriding royalty interests, and expenses before receiving their share of these cash flows. Overriding royalty interests are often used as an incentive for those who are affiliated with the drilling process but do not own the minerals or E&P company (a broker or geologist for, example). Owners of ORRI, like royalty interest owners, bear no cost of production but own a portion of the revenues generated by the drilling process. Unlike royalty interest owners, however, ORRI owners do not receive the royalty for the entirety of production; instead, they are bound by explicit leases, outlining the length of time in which the ORRI will be paid.Current Issues Surrounding Mineral InterestsStates also can receive royalties from oil production. Under the Gulf of Mexico Security Act of 2006, Texas, Louisiana, Alabama and Mississippi became part of a revenue sharing program from off-shore drilling royalties in the Gulf of Mexico. In his 2018 budget, however, President Trump has proposed to repeal this act in order to redistribute the funds to taxpayers. The White House believes that this will save approximately $3.6 billion over the next decade, but the proposal has been met with disapproval both from politicians and the oil and gas industry. Next year alone, the royalty disbursement to the four states is expected to total $275 million, which would be directed to support environmental protection, infrastructure improvements, and coastal restorations. It is unclear if this change will be approved, but the four states’ royalties, like many individual royalty interests, are enveloped in uncertainty in the current market.Valuations of Mineral InterestsAlong with the majority of the oil and gas industry, royalties were hit hard as a result of the oil price downturn beginning in 2014. Among other factors, the success of US shale drillers drove the supply of oil up and subsequently forced the oil price to decade-lows. As a result of shrinking margins for E&P companies, oil production drastically decreased. For some, oil production stopped completely and royalty payments were soon to follow. During the oil downturn, many royalty distributions shrank dramatically while others disappeared completely.  Over 120 companies filed for bankruptcy since the crash of commodity prices and most royalty owners were left to fend for themselves while uncertainty encompassed their mineral interests.Trends in royalty trusts can be indicative of the value of individual royalty interests. Over the past two years, nineteen out of twenty royalty trusts have shown negative price performance. However, when focusing solely on the past year, this number shrinks to three of twenty trusts exhibiting negative price performance. This suggests that royalty trusts are on an upward trend, and by extension that royalty interests are recovering as well.  However, no two royalty trusts are alike. Differences abound in asset mix, asset location, term, and resource mix and the value of royalty interests vary due to these factors.We will explore the valuation implications of each kind of interest in an upcoming blog post.We have assisted many clients with various valuation and cash flow issues regarding royalty interests.  Contact Mercer Capital to discuss your needs in confidence and learn more about how we can help you succeed.Our thanks to Paige Klump who drafted and did much of the research for this post in collaboration with our Energy Group.
How to Use an EV/Production Multiple
How to Use an EV/Production Multiple
As of 6/5/2017Current PriceFuture Price (12 months)% ChangeWTI$47.62$48.642.14%Natural Gas$2.84$2.871.06%Source: Capital IQOil and gas analysts use many different metrics to explain and compare the value of an oil and gas company, specifically an exploration and production (E&P) company. The most popular metrics (at least according to our eyeballs) include (1) EV/Production; (2) EV/Reserves; (3) EV/Acreage; and (4) EV/EBITDA(X). Enterprise Value (EV) may also be termed Market Value of Invested Capital (MVIC) and is calculated by the market capitalization of a public company plus debt on the balance sheet less cash on the balance sheet. In this post, we will dive into one of these four metrics, the EV/Production metric, and explore the most popular uses of it.DefinitionEV/Production is a commonly used valuation multiple in the oil and gas industry which measures the value of a company as a function of the total number of barrels of oil equivalent, or mcf equivalent, produced per day. When using this multiple, it is important to remember that it does not explicitly account for future production or undeveloped fields.Common UsesWhile the above definition was provided by Investopedia, the source goes on to explain the meaning of the multiple in the following way:All oil and gas companies report production in BOE. If the multiple is high compared to the firm's peers, it is trading at a premium, and if the multiple is low amongst its peers it is trading at a discount. However, as good as this metric is, it does not take into account the potential production from undeveloped fields. Investors should also determine the cost of developing new fields to get a better idea of an oil company's financial health.While some of the above explanation may appear true; the detail, analysis, and reason is lacking. Let’s more fully investigate the above notes:BOE or MCFE. Not all oil and gas companies report in barrel of oil equivalent per day (BOEPD). Those that are primarily dry gas producers will choose to report in MCF equivalent per day (MCFEPD). On the other hand, majority oil producers will report in BOEPD. One take away analysis to consider is that many times the metric a company uses to report production communicates the core production activity of the company (i.e. a company that reports in BOE wants to communicate they primarily target oil, while a company that reports in MCFE wants to communicate they primarily target gas).Premium or Discount. If the multiple is higher compared to its peers, it only appears to trade at a premium, but it does not mean the market value of the company is at a premium or more expensive than its peers. If it trades at a discount to its peers, the same is also true; it does not automatically mean the MVIC of a company is cheaper than its peers. To draw that conclusion, one assumes each of its peers has the exact same future production outlook, the exact same well locations and the exact same management team, just to name a few. Making this assumption in isolation is in error. Instead, analysis should be performed to understand the why behind a perceived “premium” or “discount.”Current or Future Production. The metric uses current production as an indication of value for the company. Using this metric, it could be assumed that (1) the current oil/gas/natural gas liquids mix will stay the same; (2) the current production level will continue on its previously experienced decline rate; and (3) the equivalency formula to translate gas production into oil production (typically 6.1 mcf = 1 barrel of oil equivalent) will not change. This metric fails to account for visibility into future production. When analyzing an E&P company, future production should always be considered.ExperienceWhile this multiple is useful, it also has its shortfalls. As with all multiples, it should never be used as the sole indicator of value. As an example, using this multiple in isolation would give zero value for an E&P flush with acreage and no production.We had a client with investments in an oil and gas company that was facing a transfer of ownership decision. During negotiations certain parties involved were convinced the only way to value, and therefore the only way they would pay for, an E&P was to utilize an EV/Production multiple and nothing else. They backed their position with their transaction experience of buying oil and gas assets as well as their knowledge of industry participants. We believed utilizing that particular method significantly undervalued our client. While the company had very little production, the acreage rights were significant as well as the PV 10 reserve report. We assisted our client through the transaction process by utilizing multiple valuation approaches, not solely the one a potential suitor strongly suggested.Multiples such as EV/Production can provide context for market pricing in the form of a range. We would never recommend using one market multiple as the only value indication for a subject company, particularly a non-publicly traded company. Ideally, market multiples should be used as one of many value indicators during analysis. While there may be facts and circumstances that prohibit the use of multiple value indicators, it is always advisable to (1) understand the implications of using a specific multiple; (2) understand its weaknesses; and (3) use other value indications together. When observing the EV/Production multiple, reconcile the observations with other valuation multiples and valuation indications for a reasonable analysis. For assistance in the process or other valuation analysis for an energy company, contact a member of our oil and gas team to discuss your needs in confidence.
Are Oil and Gas Bankruptcies a Thing of the Past?
Are Oil and Gas Bankruptcies a Thing of the Past?
As of 5/22/2017Current PriceFuture Price (12 months)% ChangeWTI$50.33$51.492.30%Natural Gas$2.59$2.8811.20%On June 20, 2014, the price for a barrel of crude oil on the NYMEX reached $107. Few, if any, expected oil prices to fall, and then, keep falling to a dip below $30. Even with hedges in place, this unexpected, sustained price drop crippled oil revenues. Many investments in oil and gas that were once projected to generate strong positive cash flows and profits could no longer generate enough cash to support the debts used to fund the project. Thus, as prices remained low, more and more companies ran out of cash to support once manageable debts. Since the start of the oil downturn, more than 120 upstream and oilfield service companies declared bankruptcy.However, as we described in a previous post, for these E&P and services companies, the decision to file for bankruptcy did not always signal the demise of the business. Despite the sense of doom often associated with the word “bankruptcy,” if executed properly Chapter 11 reorganization afforded these financially distressed or insolvent companies an opportunity to restructure their liabilities and emerge as sustainable going concerns.Many E&P companies who reorganized are “emerging from bankruptcy, looking to grow.”  The Financial Times reported that 80% of oil and gas companies who filed for Chapter 11 have emerged from bankruptcy and are still operating.  They even claim that this wave of bankruptcies made the industry stronger as companies were able to shed billions of dollars of debt and were forced to increase drilling efficiency in order to survive.  In the low oil price environment, companies worked to lower breakeven costs by using new technology to get more oil out of already developed wells.  Additionally, many companies sold off assets they could not afford to develop to those who had the ability to finance the necessary capital expenditures to bring new wells online.Thus, as OPEC and partners cut production at the end of 2016, U.S. shale drillers continued to increase production, which kept oil prices comparatively low.   Now, almost a year after the peak in bankruptcy activity, oil prices have stabilized around $50 per barrel, and U.S. shale drillers are well positioned to ramp up drilling activity.  The U.S. is estimated to have more recoverable oil than any other country, including Saudi Arabia and Russia.  Additionally, President Trump’s administration is expected to be a proponent of fracking.For the past two years, OPEC tried to squeeze U.S. shale drillers out of the market by increasing production to flood the market and lower prices, but it looks like domestic shale producers came out as the winners in this competition.  Earlier this year, Vauhini Vara, wrote in The Atlantic, “It has become clear that the shale-oil business is going to survive, at least for now.”  Over the first four months of 2017, only nine producers filed for bankruptcy, compared to 29 companies that went bankrupt in the first four months of 2016.  Although there may still be more bankruptcies to come, the trend of bankruptcies caused by the crash in oil prices has slowed, and companies are prepared to grow with leaner balance sheets than before.Mercer Capital has significant experience valuing assets and companies in the energy industry. To learn more about Mercer Capital’s experience in oil and gas and bankruptcy valuations contact a Mercer Capital professional today.
E&P: What We Learned from 1st Quarter Earnings
E&P: What We Learned from 1st Quarter Earnings
The first quarter of 2017 was productive and active for upstream E&P but the change in market capitalizations of many oil and gas companies does not match the reported increase in earnings and production estimates. Looking at our universe of energy companies in the E&P space, over 70% beat earnings estimates. This statistic held true no matter if the energy company was a global integrated operator or a pure upstream producer. To provide a flavor of the attitude, we selected two larger publicly traded energy companies involved in E&P (STO and XOM) as well as six companies with primary operations in the Permian Basin (PXD, CXO, NBL, XEC, FANG, and RSPP) and reviewed the highlights of their latest earnings releases. As summarized below, each of these companies exceeded analyst expectations. STO – StatOil ASA Over the first quarter StatOil’s market cap fell from $60.2 billion to $55.7 billion.  But, Eldar Saetre, President and CEO of Statoil ASA had only good things to say about first quarter earnings. Our solid financial result and strong cash flow across all segments was driven by higher prices, good operational performance and an organic production growth of 5%.We delivered seven discoveries from nine exploration wells drilled during first quarter. Many of these can be quickly put into profitable production.We are also about to start our exploration programme in the Barents Sea, testing several new opportunities over the next six months. In the quarter, we received approval for three plans for development and submitted additional two projects for approval by Norwegian authorities, showing commitment to industrial development on the NCS.XOM – Exxon Mobil Corporation Exxon’s market cap fell over the first quarter from $373 to $340 billion but overall the company reported positive results.   Darren W. Woods, Chairman and CEO, said, Our results reflect an increase in commodity prices and highlight our continued focus on controlling costs and operating efficiently.We continue to make strategic acquisitions, advance key initiatives and fund long-term growth projects across the value chain.Upstream volumes were 4.2 million oil-equivalent barrels per day, a decline of 4 percent compared with the prior year, primarily due to the impact of lower entitlements due to increasing prices, and higher maintenance.Upstream earnings of $2.3 billion improved on higher liquids and gas realizations.The following six companies’ operations are focused in the Permian Basin.  The bulleted information below is summarized from each of their earnings releases.PXD – Pioneer Natural Resource Company Pioneer’s market cap remained relatively stable over the first quarter of 2017 at $31.3 billion in January and $31.6 billion at quarter end. Production for the first quarter increased by 3% from 4Q16 and was above the top end of Pioneer’s guidance rangeProduction growth was driven by Spraberry/ Wolfcamp horizontal drilling programThe company reduced production costs compared to 4Q16.CXO – Concho Resources, Inc. Over the first quarter Concho’s market cap fell somewhat from $19.6 billion to $18.6 billion but overall, the company reported positive earnings and activity results. Concho delivered quarterly production of 181.4 Mboepd, exceeding the high end of the company’s guidance range and raised full-year 2017 production outlook to a range of 21% – 25% annual growth while maintaining their capital expenditures outlook.They increased crude oil production to 113.6 Mbpd, up 28% year-over-year.The company achieved record well performance in their Delaware Basin and New Mexico Shelf assets.The shift to manufacturing mode was made with large-scale development projects in the Delaware Basin and in the Midland Basin.The company reduced per-unit production expense and interest expense by 27% and 42%, respectively, year-over-year.Concho lowered full-year 2017 guidance for per-unit production and depreciation, depletion and amortization expenses.NBL - Noble Energy, Inc. Nobel Energy’s market cap fell from $16.4 billion to $14.84 billion over the first quarter of 2017 even as President and CEO David L. Stover said, “Noble Energy is off to a great start in 2017, with strong operational and financial performance and importantly, numerous recent strategic accomplishments.” The company delivered quarterly sales volumes at or exceeding the top end of guidance. And total oil volumes were at the high end of guidance, led by Delaware and DJ Basin performance.The company saw continued strong well performance in the Delaware Basin.Three new Wolfcamp A wells commenced production.Noble Energy's leading position in the Southern Delaware Basin was solidified through the acquisition of Clayton Williams Energy, increasing the company's position to 118,000 net acres.Full year sales volumes trended toward the upper half of original expectations, driven primarily from increased crude oil and NGL sales.XEC – Cimarex Energy Co. Cimarex’s market cap decreased over the first quarter from $13.2 billion to $11.4 billion. Total production was up 11% sequentially.Oil production was up 15% sequentially.Total company production, which increased 9% over the first quarter, came in above the high end of our guidance.Commodity prices improved significantly from a year ago and had a positive impact on Cimarex's financial results for the quarter.Realized oil prices increased 70% from the first quarter of 2016.Realized natural gas prices were up 57% from the first quarter 2016.NGL prices were up 107% from the same period one year ago.FANG - Diamondback Energy, Inc. Over the first quarter Diamondback’s market cap increased from $9.3 billion to $10.1 billion. 1Q17 production was up 19% over 4Q16 with 13% quarterly organic growth.Estimated 1Q17 Midland Basin drill, complete and equip cost per completed lateral foot was down 5% quarter-over-quarter.Closed Brigham Resources acquisition, which increased Diamondback's total leasehold to approximately 189,000 net surface acres in the Permian Basin.Diamondback continues to decrease drilling times, lower costs, and achieve new company records.RSPP - RSP Permian, Inc. RSP’s market cap decreased from $6.5 billion to $5.9 billion over the first quarter of 2017. Production increased 84% compared to 1Q16 and increased 26% compared to 4Q16.Adjusted EBITDAX increased by 249% from 1Q16 and 37% compared to 4Q16.On March 1, 2017, RSP Permian closed their previously announced SHEP II acquisition for approximately $646 million of cash and 16.0 million shares of RSP common stock. As the above earnings excerpts explain, the first quarter brought (1) higher oil and gas prices; (2) higher production rates; (3) lower production costs; (4) investment in new wells; and (5) an active environment for asset purchase and divestures. However, the stock price performance does not reflect the positive quarter performance. Of the 64 energy companies we track, 49 had lower market capitalizations as of May 11, 2017 compared to December 31, 2016.Why Is This?One significant reason for this mismatch is the outlook for crude oil has declined approximately 14% from the end of Q4 to the middle of May 2017. The following is a comparison of the 12 months futures contracts for WTI at the end of 4Q16 and middle of May 2017: The fear of too much oil supply is dampening the pricing outlook for oil. Although 1Q17 resulted in slightly higher prices for oil, the successful increase in production from new drilling techniques and stacked reserve play wells is boosting production and moving prices lower. The industry now looks to OPEC and Russia for production cuts to assist in increasing the price. In a volatile oil and gas market, the market capitalization of companies is more of a representation of the future earning potential of companies rather than the past.  While the first quarter of 2017 showed hopeful results, the change in the market pricing of these companies puts a damper on the increase in earnings and makes us question if these companies’ successes are short lived. Mercer Capital has significant experience valuing assets and companies in the energy industry, primarily oil and gas, bio fuels and other minerals.  We have assisted many clients with various valuation and cash flow issues regarding royalty interests.  Contact Mercer Capital to discuss your needs in confidence and learn more about how we can help you succeed.
Why Aren’t We Talking About the Gulf of Mexico?
Why Aren’t We Talking About the Gulf of Mexico?
Artem Abramov, of Rystad Energy, recently published an article in the Oil and Gas Financial Journal comparing shale and offshore drilling.  He claims, the “Gulf of Mexico [is] as important as [the] Permian Basin for U.S. oil production” but it has been overlooked since the advancement of shale gas.  The EIA reports that offshore drilling accounts for 17% of total domestic crude oil production. So, why aren’t we talking more about oil and gas production from the Gulf of Mexico (GoM)?Unlike shale plays, where production varies with oil prices, production in the Gulf of Mexico has been resilient to fluctuations in prices because projects in the Gulf of Mexico have longer time horizons.   After the downturn in oil prices drilling activity remained relatively flat at 25-35 wellbores per quarter.  The relative price insensitivity over the short term meant that the Gulf of Mexico did not see substantial production drops like many other oil producing regions of the U.S. when prices fell in mid-2014.  However, this also means that as oil prices have recently increased, the Gulf has not seen substantial increases in production.The Oil and Gas Financial Journal article stated:Only two sources of oil supply in the U.S. remained exceptionally resilient throughout the downturn: The Permian Basin and the Gulf of Mexico.  The Permian Basin’s output was growing every quarter, adding 300 Mbbl/d from the first quarter of 2015 through the fourth quarter of 2016.  While exposed to seasonal disruptions, GoM’s production was able to deliver a 240 Mbbl/d growth over the same period, contributing almost equally with the Permian Basin to the limited decline pace of the total U.S. oil production.Right before the 2014 downturn in oil prices, many deepwater drilling projects were approved. This led to increased start-up activity in the Gulf in the second half of 2016 which increased crude and condensate production by 400 Mbbl/d from 2014 to 2016.  In 2016, eight projects came online in the GoM and another seven projects are expected to come online by the end of 2018.  In 2016, crude oil production in the Gulf of Mexico reached an annual high of 1.6 Mmbbl/d which surpassed the previous high which was set in 2009.  Oil production is expected to reach 1.7 Mmbbl/d in 2017 and 1.8 Mmbbl/d in 2018 in the Gulf of Mexico.Recently, most oil and gas news has been centered on the Permian Basin.  As we explained in a recent post, the Permian Basin has had recent success due to its locational advantage, vast amount of untapped reserves, and low breakeven prices.   Most of the major M&A deals in the upstream sector were in the Permian Basin in 2016.  According to James Scarlett of RS Energy Group, approximately 25% of the U.S.’ lower 48 production came from the Permian Basin and 38% of the rigs in the U.S. are in the Permian.  The reason for so much concentration is that about 80% of currently economic (economic meaning under $50 breakeven oil) oil is in the Permian, particularly the Delaware Basin. Secondly, due to the numerous potential production zones (Wolfcamp, Bone Spring, Leonard Shale, Delaware Sands, etc.), there is a huge amount of oil in place for potential recovery (3,000 feet of pay zones).  Couple this with an area (West Texas) that has ample existing infrastructure from decades of development, and this has led to what some people are calling a land grab in the area.The Gulf of Mexico’s success can be similarly explained.  The EAI reports that 45% of total petroleum refining capital and 51% of U.S. natural gas processing plant capacity is located along the Gulf Coast, giving the Gulf easy access to its downstream market. Additionally, much of the midstream infrastructure is already in place, which allows companies to save money by utilizing already developed pipelines.  Further, the Gulf of Mexico had 4.8 billion barrels of crude oil proved reserves at year end 2015, according to the most recent information published by the EIA. In comparison, RRC Districts 7C, 8, and 8A, which includes the majority of the Permian Basin, combined proved reserves at year end 2015 of 7.3 billion barrels, and North Dakota, home to the Bakken shale play, had 5.2 billion barrels of proved reserves (2015 reserve estimates do not include some recent significant discoveries, including the discovery of an estimated 20 billion barrels in the Wolfcamp shale play in the Permian Basin).  In addition, the Gulf of Mexico has been able to realize increased drilling efficiency for many years.  Average drilling speed in shale increased by 100% from 2011 to 2016, but the Gulf of Mexico was not far behind, averaging an increase in drilling speeds by 60-75% from 2015 to 2016.  As shown in the chart below sourced from the Oil and Gas Financial Journal, drilling efficiency improvement in the GoM is greater than in shale oil. While the energy sector as a whole is expected to benefit from President Trump’s pro-energy policy, offshore drilling has recently been at the center of political talks. Interior Department Secretary Ryan Zinke signed two secretarial orders last week which are expected to increase America’s offshore energy potential. The first order, directed by the Bureau of Ocean Energy Management (BOEM), is to develop a new five-year plan for offshore oil and gas exploration and to reconsider the regulations surrounding these activities.  Secretary Zinke said that regulations which were created with good intentions, but that have been harmful to America’s energy industry, will be reviewed.  While some regulations have been removed, such as the Offshore Air Quality Control, Reporting, and Compliance Rule, Offshore Petroleum Industry Training Organization (OPITO) officials are encouraging the U.S. to follow their common industry standards, which have been adopted by 45 other oil producing regions internationally. The second order established a new position to coordinate the Interior Departments energy portfolio.  Zinke noted that in 2008 federal leasing revenue for the Outer Continental Shelf (OCS) was approximately $18 billion, but it was only $2.8 billion in 2016.  Focused on increasing leasing revenue, President Trump is likely to experience some legal obstacles.  In 2006, Congress placed a moratorium on drilling within 125 miles of the Florida Coast until 2022. However, this area is estimated to contain up to 2.35 billion barrels of oil.  President Obama in November 2016 permitted 10 lease sales in areas of the Gulf of Mexico in moratorium, but this plan only covered a small portion of the eastern gulf coast.  President Trump wants to expand leasing rights but will likely have to battle much of this argument in court because it requires a public comment period.1 One impact of the recent downturn in oil prices was the need for shorter term capital projects.  As we talked about in a recent post, "The Wild Goose Chase Is Over", companies have been looking to invest in quick ventures that have short payback periods.  The Gulf of Mexico is known to have longer payback periods but has been working to shorten investment time horizons.  Companies are focusing on “Subsea completions and tiebacks where you already have the infrastructure – the platform in place, the pipeline to the market place – so those require significantly less capital and faster lead times than the big spars that people think of in offshore projects” as Deloitte’s Andrew Slaughter said in a recent interview with the Oil and Gas Financial Journal.2 While the Permian Basin has been the center of most oil and gas discussion recently, there are notable investments being made in other oil rich areas of the U.S.  In February, Shell invested in the Kaikias oil and gas project in the Gulf of Mexico.  It will start production in 2019 and will be able to generate profits even with oil prices lower than $40 /bbl.  Last December BP made a similar announcement of a $9 billion investment, called “Mad Dog Phase 2” in the Gulf of Mexico that is expected to be profitable at $40/ bbl oil.  With uncertainty surrounding the future price of oil due to the unpredictability of OPEC’s production cuts, it is important for oil and gas producers to find economically efficient plays. While the Permian is currently one of the most economical plays, we cannot rule out all others such as those in the Gulf of Mexico.  Although the market is not rallying around the Gulf of Mexico like it is around the Permian, we can expect continued growth in the region over the next few years. Mercer Capital has significant experience valuing assets and companies in the energy and construction industries.  Contact a Mercer Capital professional today to discuss your valuation needs in confidence. End Notes1 Dlouhy, Jennifer. “Trump to Expand Offshore Drilling, Review Deepwater Horizon Regs. Bloomberg News. 2 Tiebacks are subsea lines that connect new wells to existing projects.
Is Cash Always King?
Is Cash Always King?
Travis Harms, CFA, CPA/ ABV, Senior Vice President at Mercer Capital, recently published a blog post on Mercer Capital’s Financial Reporting Blogcontemplating the appropriate amount of cash for a company to hold.  This topic is especially pertinent to the oil and gas industry, in which 70 companies went bankrupt last year.  Now as companies have started to increase capital expenditures again, they must consider how much cash they should keep as a cushion while considering the effect of this low-yielding asset on value. When it comes to money, “enough” is the hardest word to define in the English language.  The challenge of defining “enough” extends to corporate managers deciding what cash balance is appropriate.Cash balances can provide a cushion against unanticipated adverse events in the business. The moment companies need cash is usually the worst time to try to raise capital.  Having sufficient cash on hand to weather an unexpected downturn in the business can help shareholders avoid dilutive capital raises at inopportune times.On the other hand, cash is a very low-yielding asset. Large allocations to cash weigh down the returns to invested capital.  If capital providers recognize the risk-reducing attributes of cash and reduce their return expectations accordingly, the effect of a large cash balance on value is probably negligible.  If, instead, investors view the cash investment no differently than any other capital allocation, and fail to reduce their return expectations, then a large cash balance will be detrimental to value. As shown in Table 1 above, investors provide debt and equity capital (the right side of the balance sheet), which the company then allocates to a portfolio of assets (the left side of the balance sheet).  The enterprise value of the business represents the “engine” that generates operating cash flow (of which EBITDA is often considered a proxy).  Since cash balances do not generate EBITDA, cash and other short-term investments are excluded from enterprise value. In the current yield environment, the investment return on cash balances is nil.  As a result, cash balances represent a drag on the weighted average return on the company’s assets.  In both private and public companies, minority investors do not have any direct control regarding the allocation of the capital they provide.  Corporate managers and directors need to evaluate the effect of large cash holdings on both the returns provided to capital providers and the required returns demanded by capital providers.  In the balance of this post, we examine data from public markets to assess shareholder preferences with regard to cash holdings. Summary of the DataWe examined data pertinent to this question for non-financial companies in the S&P 1000 at the end of 2016.  The S&P 1000 index is a combination of the S&P MidCap 400 and the S&P SmallCap 600.  At December 31, 2016, the companies in the S&P 1000 index had market capitalizations ranging from about $200 million on the small end up to approximately $10 billion.Table 2 summarizes pertinent data by industry. Measured as a percentage of market value of invested capital (MVIC, or the sum of equity market capitalization and total debt), median cash balances for the various industry groups range from a low of 0.4% for utilities, to a high of 11.1% for information technology. We considered a number of characteristics that may contribute to industries allocating more or less of their capital to cash.  The relationships between cash balances, capital expenditure intensity and expected revenue growth are not very compelling.  In contrast, as shown in Table 3, there does appear to be a degree of correlation between cash balances and beta.  Correlation is not causation, of course.  However, what the data does begin to suggest is that higher-risk companies tend to hold more cash than lower-risk companies (if risk is measured using beta). This observation is consistent with the risk-reducing properties of cash mentioned above.  Companies in riskier industries may hold more cash as a buffer against unexpected adverse changes.  While this is intuitive from the perspective of corporate managers, the question remains as to whether shareholders perceive value in the allocation of capital to cash. What is Cash Worth?Analysts typically calculate valuation multiples relative to enterprise value – in other words, on a “cash-neutral” basis.  The principal merit of this approach is the recognition that, all else equal, a company with greater cash reserves should be worth more than a company with lesser cash reserves.  This approach also recognizes that cash balances do not contribute to the generation of operating cash flow.  Implicit in this approach, however, is the assumption that shareholders give full dollar-for-dollar credit for cash held on the balance sheet.This is undoubtedly true at the time of a transaction for a private company, as purchase agreements inevitably include target working capital levels with dollar-for-dollar adjustments to the negotiated purchase price for excess or deficit working capital relative to the target.However, it is not necessarily the case that minority investors facing a potentially lengthy holding period have the same perspective. Such investors may view large cash balances as no more than negative net present value capital projects that diminish value. Table 4 below summarizes the two potential extreme positions.In the scenario on the left, investors assign the same enterprise value multiple to the high and low cash companies. This behavior is consistent with the notion that allocating resources to cash results in a corresponding reduction to the cash-hoarding company’s weighted average cost of capital.  In other words, investors value the risk-mitigating properties of cash.In the scenario on the right, investors are unimpressed by management’s ability to hold onto cash. Since return expectations are not modified by the large cash balance and the cash balances do not generate any material cash flow, the ratios of MVIC to EBITDA are identical for the two companies. In an effort to screen out potential noise associated with industry factors, we examined the data summarized in Table 2 further by industry to discern which of the two possibilities more closely reflects investor attitudes toward corporate cash balances.  In order to avoid unduly small sample sizes, we examined the four most populous industries (consumer discretionary, healthcare, industrials, and information technology).  We sorted the companies within each industry by cash balance (measured as a percentage of MVIC), dividing each industry into cohorts of equal thirds.  Table 5 summarizes key results for each industry. Consideration of the data summarized in Table 5 yields a number of observations. Within the more mature consumer discretionary and industrials segments, cash balances are unrelated to company size, as the revenue for companies in Cohort 3 (least cash) is comparable to that of the companies in Cohort 1 (most cash). In contrast, cash balances in the faster-growing healthcare and information technology segments are inversely related to company size.  The cash-rich healthcare and IT companies are approximately one-half the size of the low-cash companies in the respective industries.While differences in beta within the industry segments are modest, the observed data points are generally consistent with the relationship between risk and cash holdings noted with respect to Table 2. Perhaps cash balances are viewed as a counter-weight to greater operating risk.Projected revenue growth is inversely related to cash balances for companies in the consumer discretionary and industrials segments. For companies in the healthcare and IT industries, however, the companies with the highest cash balances have the highest growth expectations.  Perhaps in these industries, cash balances are perceived by investors as “dry powder” for future positive-NPV projects.While differences in expected growth obscure direct observations regarding the impact of cash balances on WACC, data for the consumer discretionary and industrials segments more closely approximate the right side of Table 4, suggesting that investors in mature companies are unimpressed with large cash balances. For healthcare and IT, the data is more closely aligned with the left side of Table 4, suggesting that investors view cash accumulation as a reasonable strategy in industries in which positive-NPV projects are presumably abundant.ConclusionOne of the primary tasks of corporate managers and directors is capital allocation.  While cash balances can provide a safety net that allows corporate managers to sleep better at night, for shareholders, the risk-mitigating benefit of corporate cash balances is balanced by the corresponding drag on returns.  Based on the market data summarized in this post, the perceived availability of positive-NPV projects seems to influence investor preferences regarding cash stockpiles.Positive-NPV projects are presumably abundant in higher-growth industries such as healthcare and IT.  For firms in those industries, investors appear more likely to view cash as “dry powder” for future value-enhancing investments, and are more willing to bear the cost of lowered returns until such investments are identified and made.In more mature segments such as consumer discretionary and industrials, positive-NPV projects are presumably scarcer.  The value of large cash holdings among firms in these industries seems to be discounted by investors.For corporate managers and directors, cash balances should not be treated simply as a residual, but rather actively evaluated in conjunction with the firm’s capital budgeting and distribution policies.  Cash may be king, but shareholders aren’t necessarily monarchists.
How to Invest in PUDs in the Permian Basin without Paying for the Well
How to Invest in PUDs in the Permian Basin without Paying for the Well
In previous posts, we have discussed the existence of royalty trusts & partnerships and their market pricing implications to royalty owners. Many of those trusts have a set number of wells generating royalty income at declining rates for multiple years to come. Viper Energy Partners LP (VNOM) is not a trust, but a partnership, solely focused on the Permian Basin with royalty interests in producing wells as well as proven undeveloped (PUD), probable and possible wells. Per their latest 10K filing:Viper Energy Partners LP owns, acquires, and exploits oil and natural gas properties in North America. VNOM holds mineral interests covering an area of approximately 30,442 net acres in the Permian Basin, West Texas. As of December 31, 2015, its estimated proved oil and natural gas reserves consisted of 31,435 thousand barrels of crude oil equivalent. Viper Energy Partners GP LLC operates as the general partner of VNOM. VNOM was founded in 2013 and is based in Midland, Texas and is a subsidiary of Diamondback Energy, Inc (FANG).VNOM filed the initial public offering in June of 2014. Below is the entire trading history of VNOM: The following summarizes VNOM’s oil and gas assets in more detail per their latest 10K: VNOM’s primarily owns mineral interests located in the Permian Basin. As of December 31, 2016, VNOM owned mineral interests consisting of 107,568 gross acres in the Permian Basin. In total, Diamondback operates approximately 41% of this acreage. Details of VNOM’s acreage, as of December 31, 2016, are summarized below: Total Producing Wells: 545 vertical wells and 190 horizontal wellsNet Production during 4Q2016: 7,919 Boe/dEstimated Proved Reserves per Independent Petroleum Engineer: 31,435 Mboe 58% classified as PDP reservesIncludes 23 horizontal wells in various stages of completion68% Oil / 18% NGL / 14% Natural GasPUD Reserves from 86 gross horizontal well locationsRevenue generated from these mineral interests has increased from $77.8 million in 2014 to $78.8 million in 2016 VNOM, on average (on an acreage weighted basis), receives a 5.95% royalty interest from their 107,568 gross acres and they do not have to pay for any additional capital or operating expenses. The actual royalty percentages vary from 1% to 25% depending on the relative amount of production from the various leases. For example, in the Spanish trail area of Midland County, VNOM receives an average (on acreage weighted basis) of 20.4% for the 16,551 gross acres they own. Because Diamondback operates 41% of VNOM’s acreage, the performance of VNOM is closely tied to the activity of Diamondback Energy, Inc. (FANG). Below is the price history of VNOM and FANG: Market ObservationsThere are approximately 21 oil and gas focused royalty trusts and partnerships publicly traded, as of the date of this article. As demonstrated below, VNOM is unique from the other 20 similar entities. While many of these entities have assets located in the Permian Basin, the areas that make VNOM unique may include but are not limited to the following: Asset mix is primarily focused in the Permian Basin;Royalties are from producing wells;Future royalties are possible from PUD, probable and possible locations; andFANG is the operator of a significant portion of the VNOM’s acreage. As a result, VNOM has the second largest market capitalization, the 4th highest price to revenue multiple, the lowest yield (of the entities that have a yield) and has the longest implied payback period at 21.2 years. Each of these data points indicates VNOM’s popularity in the market place among investors, FANG being the largest owning approximately 74% of the total shares outstanding of VNOM. For many of the above entities, opportunity to participate in PUD, Probable and Possible wells does not exist. Based upon our knowledge of the exploration and production industry, opportunities to participate in new wells, without having to pay for the capital expenditure of drilling the well, casing the well and fracking the well, appears to be an exciting and valuable option. The market appears to agree.Implications for Royalty OwnersIn many respects, royalty owners can utilize publicly traded royalty trusts and partnerships to observe changes in investor behavior and get a feel for how much their royalty interests may be worth. Here are a few areas to consider for your specific situation to compare and contrast with royalty trusts and partnerships.Set Number of Assets. Royalty trusts and partnerships typically have a set number of wells and producing assets after they are formed. Does your property have a fixed number of assets or will it grow? If new oil and gas wells are not being added to the property, then the oil and natural gas reserves will deplete as they age and produce.Location. The royalty trusts and partnerships above have assets all over North America. Some are located in hot spots while others are not. Location drives investor appetite as operating costs and production levels, which vary by location, drive profitability in an industry that has zero control over the price of their product. This is a significant reason for the high transaction activity in the Permian Basin. Operators know they are able to make a profit through high production rates and low operating costs in Permian Basin even at $40 oil. Consider the investor activity, or lack there-of, in your area.Price and Production. Now that the U.S. has significant recoverable oil and gas reserves and the ability to export unrefined crude world-wide, the U.S. can be considered a swing producer, a power which historically characterized OPEC. As a swing producer, price dictates the level of production the market will consume and production will increase or decrease relatively quickly to meet demand. In response to price changes, operators will increase or decrease production levels at will. Consider how your operator has behaved in various pricing environments and the operators of the Royalty Trusts. In addition to the differences between your royalty assets and the royalty trusts and partnerships, consider the level of value indication provided by the royalty trusts and partnerships. The level of value is the publicly traded level of value verses the privately held royalty assets held by many land owners. Consider the following chart. Chris Mercer explains, The benchmark level is the marketable minority level of value, or the middle level in the chart above. Conceptually, it represents the pricing of the equity of a public company with an active and freely trading market for its shares. For a private company, it represents that same price as if there were a free and active market for its shares. The lowest level on the traditional levels of value chart is called the nonmarketable minority level of value. This level represents the conceptual value of illiquid (i.e., nonmarketable) minority interests of private companies, or entities that lack active markets for their shares.Publicly traded royalty trusts and partnership provide an indication of value at the marketable minority value level for minority interests in an entity with royalties as the primary asset. For royalty owners the value level can be a mixed bag. Many own the asset directly while others own equity interests in entities with royalties as their main assets. It is important to understand the value level comparability difference for your situation.To move from the marketable minority value to the nonmarketable minority value level, simply apply a marketability discount. Stated a different way, apply a discount for not having the ability to quickly sell your asset and receive cash. Fully marketable assets, like those publicly traded, have the ability to exchange the asset for cash in approximately three days. All other assets which do not have this access lack marketability. Therefore, in order to build and find a market for the assets, a discount is typically required by potential investors.We have assisted many clients with various valuation and cash flow issues regarding royalty interests. Contact Mercer Capital to discuss your needs in confidence and learn more about how we can help you succeed.
What Would You Do with $1 Billion?
What Would You Do with $1 Billion?
Less than one month ago investors bet $1 billion on James Hackett, former President and CEO of Anadarko Petroleum Corp.  Silver Run Acquisition Corp. II is a blank check company that will leverage James Hackett’s knowledge of the Eagle Ford Shale and Permian Basin to fund an opportunistic acquisition.  Silver Run II was created by the Riverstone Holdings LLC, the bank that successfully started the blank check company over a year ago now known as Centennial Resource Production LLC. The original stock sale for Silver Run Acquisition Corp I, which raised $900 million is expected to exceed $1 billion.  If the banks managing the deal exercise their options to buy shares, which they generally do, the Company would be tied for the record largest blank-check offering.  Before we review the recent uptick in investment in oil and gas blank check companies, we will review the basics of blank check companies and special purpose acquisition companies (SPACs).What Is a Blank Check Company?A blank check company, as defined by the SEC, is a “development stage company that has no specific business plan or purpose or has indicated its business plan is to engage in a merger or acquisition with an unidentified company or companies, other entity, or person.”  Because the acquisition opportunity has yet to be identified, investors do not know how their funds will be spent, so they write a blank check to the company.  One kind of blank check company is a special purpose acquisition company (SPAC).What Is a SPAC?Alice Hsu, Partner at Akin Gump Strauss Hauer & Feld LLP, explained “SPACs are newly formed shell companies, without any revenue or operating history, that raise proceeds in an IPO” in order to finance a merger or acquisition in a specific timeframe.  The money raised goes into a separate trust that can only be used for an eventual merger or acquisition.  At least 80% of the assets held in the trust account must be used to fund the acquisition of the target business or businesses.  If a SPAC does not meet certain goals within a specified time frame, generally 18 to 24 months, then the company will liquidate and return the pro-rata share of funds to investors.SPACs raise capital through IPOs, in which one unit and its attached warrant is typically priced at $10, making them “penny stocks.”  A short period after the IPO, the common stock and the warrants comprising one unit will begin separate trading at which point holders have the option to continue to hold their units or separate them.  SPACs are usually sponsored by an industry guru whose experience and knowledge of the industry gives them a unique position in to pursue acquisitions.   In 2007, there were 58 SPACs that completed IPOs.  But until 2016, oil and gas SPACs were uncommon.Oil and Gas SPACsSince the crash in oil prices in 2014, many oil and gas companies found themselves in dire need of capital.  Many distressed companies sold off non-core assets for heavy discounts in order to quickly generate cash to pay off debt and avoid bankruptcy. This gave investors a unique opportunity to pick up assets at low prices and SPAC’s provide a source of private capital to do this.The first oil and gas SPAC, Avondale Acquisition (AACOU) founded in April 2015, never completed an IPO as its original sponsor former CEO of Chesapeake Energy & founder of American Energy Partners, LP, Aubrey McClendon, died in a car crash in March 2016.  The Company formally withdrew its plans for an IPO to raise $200 million in November 2016.In early-2016 two oil and gas special purpose acquisition companies (SPACs) successfully completed IPOs.  This included 2016’s largest U.S. IPO as of February 23, 2016: Silver Run Acquisition Corp.  Corrie Driebusch and Ryan Dezember of the WSJ said the size of the deal in “an otherwise frozen market for initial public offering” […] “reaffirms investors’ appetite for bottom-feeding in the oil and gas business.”  The timing the deal shows that investors believed in early 2016 that the oil and gas market had bottomed out and would rebound within the next two years when its term to make a deal would expire.Where Are Oil and Gas SPACs Investing?Silver Run Acquisition Corp (SRAQU) was sponsored by Mark Papa, former CEO of EOG Resources.  Silver Run Acquisition Corp raised $500 million when it began trading on the NASDAQ.  In July 2016, Silver Run acquired a controlling interest in Centennial Resource Production LLC, an independent natural gas company located in the core of the Delaware Basin.  Centennial has acreage in Reeves, Ward, and Pecos Counties.  The transaction was financed by Riverstone Holdings LLC, an energy investment banking firm.  After the transaction Silver Run was renamed Centennial Resource Development Corp (CDEV).KLR Energy Acquisition Corp. (KLRE) raised approximately $85.1 million in its IPO.  It is sponsored by Gary Hanna, former CEO of EPL Oil and Gas Inc.  The Company announced a meeting date for stockholders to vote on the business combination with Tema Oil and Gas Company.  The meeting is scheduled for April 26, 2017.  Tema Oil and Gas Company is a privately held company operating in Texas and New Mexico and holds acreage in the core of the Deleware Basin in Loving County.  After the Closing of the transaction the Company will change its name to Rosehill Resources Inc. and will trade on the NASDAQ under the tickers ROSE, ROSEU, and ROSEW.Kayne Anderson Acquisition Corp. started by a Los Angeles private equity firm which focuses on pipelines, raised $350 million in an IPO on March 30, 2017.   This SPAC is different than most others in the oil and gas space as they do not have one industry guru as a sponsor but rather are sponsored by Kayne Anderson Sponsor, LLC which is most likely run by a team of investors at Kayne Anderson Capital Advisors, LLC.After listing on the NASDAQ just last week, Vantage Energy Acquisition Corp. (VEACU), a blank check special purpose acquisition company, raised $480 million.  Vantage Energy Acquisition Corp. is sponsored by Roger Biemans who was the CEO of Vantage Energy until it sold to Rice Energy last October.  It is likely that Vantage Energy will pursue investment opportunities in the Marcellus Shale, as Roger Bieman’s former experience was centered there.Additionally, it is rumored that Occidental Petroleum is in the talks to launch a SPAC sponsored by former CEO Stephen Chazen.ConclusionWhile the majority of M&A has been focused in the Permian Basin over the last year, the varying investments of oil and gas SPACs demonstrate that the knowledge of the industry experts is what investors find valuable.  Investment by SPACs has been higher of course in the Delaware Basin, but some of the SPACs are focusing on natural gas in the Marcellus and Utica as well.The continuation of investment in oil and gas SPACs shows that investors still believe that there are opportunities to find bargain investments in the oil and gas space throughout many basins.  The emergence of oil and gas SPACs however is still recent and there is little history to understand the success of such companies.Mercer Capital has significant experience valuing assets and companies in the energy and construction industries.  Our valuations have been reviewed and relied on by buyers and sellers and Big 4 Auditors. These valuations have been utilized to support valuations for IRS Estate and Gift Tax, GAAP accounting, and litigation purposes. Contact a Mercer Capital professional today to discuss your valuation needs in confidence.
Eureka!  Observations & Thoughts from the Permian DUG Conference
Eureka! Observations & Thoughts from the Permian DUG Conference
Last week, Mercer Capital attended the DUG Permian Basin Conference in Fort Worth.  It was a solidly attended event hosted by Hart Energy.  The session speakers were a mix of mostly company executives and industry analysts.  The presentations were tinged with a lot of optimism – centered on the positive and unique economics of the Permian, tempered by (some) cautionary commentary.  We will follow on in later posts with some more detail on specifics, but today we want to touch on a few thematic elements:The Permian was the center of the M&A activity in 2016 and will be in 2017Efficiency and productivity gains are helping to fuel activityRise in rig counts will eventually mean rise in costsActivity and M&A EpicenterMost of the major M&A deals in the upstream sector were in the Permian Basin in 2016.  It is clearly the most sought after basin.  According to James Scarlett of RS Energy Group approximately 25% of the U.S.’ lower 48 production came from the Permian Basin and 38% of the rigs in the U.S. are in the Permian.  The reason for so much concentration here, as opposed to other plays such as the Bakken or Eagle Ford, is that about 80% of currently economic (economic meaning under $50 breakeven oil) oil is in the Permian, particularly the Delaware Basin.Secondly, due to the numerous potential production zones (Wolfcamp, Bone Spring, Leonard Shale, Delaware Sands, etc.) there is a huge amount of oil in place for potential recovery (3,000 feet of pay zones – or as one presenter described: a “cubic mile of oil”).  Couple this with an area (West Texas) that has ample existing infrastructure from decades of development, and this has led to what some people are calling a land grab in the area.  According to one presentation, we saw the re-emergence of the “strategic bid” which was a term all but lost since 2014.Efficiency & Productivity GainsOne of the key reasons for the positive economics for the Permian has been the increased gains in production efficiency.  Much of this is simply the benefit of the Permian's superior geology; however, even within the play, drilling techniques and new technology have increasingly benefited production.  The relative production of wells (measured by MBOE per 1000 feet of lateral drilling) has nearly doubled in the past three plus years: In addition, production type curves are actually exceeding predictions in many cases in the Delaware.  This has led to operators considering drilling up to 60 wells per section (effectively 6 acre spacing)!  In addition, costs have come down in the past two years by about 25% per perforated lateral foot.  However, that cost reduction may be temporary as more demand pours into the Permian. Potential HeadwindsThere were some tempered presentations that noted how as more rigs are needed in the region, that costs will proportionately rise.   Much of the cost efficiencies in 2015 and 2016 were a result of an oversupply of rigs, equipment, people, etc.  The gap began to shrink at the end of 2016 and is continuing to balance out further in 2017.  As a consequence, costs will flatten out and even rise.  Early signs of this are already being felt.Although not mentioned much, conference goers were keenly aware that economics may change as well if OPEC decides to abandon its production cuts.  This would change the supply balance in world oil prices and could further change the equation.  However, this was not a centerpiece of discussion.TakeawaysThe marketplace is excited about the potential for the Permian Basin.  One analyst mentioned that up to $100 billion of capital could be available for investment in the near future.  Its exceptional economics with potential for outsized wells (3 million EUR) could keep the rig count high for decades.  What does this mean from a valuation standpoint?  Well, that question lies more on whether the marketplace is already capturing these potentials and risks in valuations.  Deals are essentially priced at PDP plus a development program.  PDP is pretty straightforward.  Whether a development plan is properly valued is another, more complex issue.
How to Value Overriding Royalty Interests
How to Value Overriding Royalty Interests
What is a Royalty Interest?Ownership of a percentage of production or production revenues, produced from leased acreage. The owner of this share of production does not bear any of the cost of exploration, drilling, producing, operating, marketing or any other expense associated with drilling and producing an oil and gas well.What is an Overriding Royalty Interest (ORRI)?A percentage share of production, or the value derived from production, which is free of all costs of drilling and producing, and is created by the lessee or working interest owner and paid by the lessee or working interest owner.ORRI’s typically do not own a perpetual interest in the mineral rights. Typically they are structured to have rights to royalties for the term of the lease period. Royalty interests, on the other hand, generally have mineral ownership into perpetuity, even after a lease expires. Thus the main difference between royalty interests and ORRI’s is that royalty interests are tied to the ownership of the mineral rights below the surface, and ORRI’s are tied to the lease agreement and ceases to exist once the lease expires.Some may find it surprising that the popular publicly traded Permian Basin Royalty Trust (PBT) only owns ORRI’s, not royalties, in various oil and gas properties in the United States. PBT owns a 75% net ORRI in the Waddell Ranch properties comprising Dune, Judkins, McKnight, Tubb, University-Waddell, and Waddell fields located in Crane County, Texas. As of December 31, 2016, its Waddell Ranch properties contained 349 net productive oil wells, 64 net productive gas wells, and 102 net injection wells.The company also holds a 95% net overriding royalty in the Texas Royalty properties that consist of various producing oil fields, such as Yates, Wasson, Sand Hills, East Texas, Kelly-Snyder, Panhandle Regular, N. Cowden, Todd, Keystone, Kermit, McElroy, Howard-Glasscock, Seminole, and others located in 33 counties in Texas. Its Texas Royalty properties consist of approximately 125 separate ORRI’s containing approximately 51,000 net producing acres.Over the past four years, crude oil and gas prices have fluctuated significantly. While this is creating significant volatility on the E&P side of the industry on both an operational and investment decision level, many look at royalty trusts as a way to bypass the complexities of an operating E&P and attempt to “pure play” the price of oil and gas. Based upon this assumption, we will analyze the changes PBT has endured over the past four years.Production PBT derives revenue from ORRI’s which cover approximately 382,000 gross acres (85,205 net acres) in west Texas. Since the ORRI’s that PBT owns were not derived from a 100% working interest, their gross acreage differs from their net acreage. Net acreage is calculated as the company’s percentage interest multiplied by its gross acreage. Over the past four years, the amount of acreage has not changed. Production, on the other hand, has changed significantly as shown in the table below. Comparing the production levels to the price levels of oil and gas indicates that even after the decline in oil and gas prices during 2014, production increased during 2015. Oil production increased 3% while gas production increased 44%. The increased production was in part due to the 3 new wells drilled during 2014, 3 workovers completed during 2014 and 29 wells completed during 2014 and 2015. During 2016, investment activity was significantly different which resulted in a 28% decline in oil production and 33% decline in gas production. No wells were drilled and completed during 2016. Only 1 workover was performed. Clearly the operators were holding back capital as they waited for more price certainty in the future. Reserves The change in reserves tells the same story. After investing in the drilling and completion of new wells, and workover wells, the proved reserves increased from 2014 to 2015 for both oil and gas. The increase is significant as reserves are impacted by (1) investment in new/existing wells and (2) future prices of oil and gas. The price utilized in the 2015 reserves was significantly lower than what was used in the 2014 reserves. Therefore, the increase in reserves is significant as the additional proved reserves more than countered the reduction in the commodity prices in the reserve model. For 2016, the reserves declined due to the lack of investment in current and future wells. And while pricing stayed relatively the same from 2015 to 2016, the loss in proved reserves was directly attributed to the lack of investment in new and existing wells. Distributions PBT is at its lowest yield in the last four years. While the price was lower at the end of 2015, the dividend as a percentage of price was higher in 2015 relative to 2016. The above chart shows the impact of (1) changes in oil and gas prices; as well as (2) changes in production levels. These two areas are directly related to the dividend per share. The price, however, is directly related to the movement of buyers and sellers of PBT securities. While the dividend is “trailing” information, because it is the result of the previous 12 months of activity, the price factors in forward looking information. For example, as of 2013, buyers and sellers of PBT were expecting higher dividends in 2014 due to the high price of oil and gas, PBT’s investment in wells and increasing proved reserves1. When commodity prices declined during 2014, the price quickly reflected the new pricing environment, the impact on reserves, and the shift in management’s investment attitude for new and existing wells. All of these factors pressured prices downward while the trailing dividends showed strength, resulting in a higher than normal yield. During 2015 and 2016, the price, dividend and yield settled to relatively tempered levels. All data points above have had enough time to reflect the current environment and as such, are communicating a similar story. Finishing ThoughtWhen valuing a royalty interest or ORRI, here are a few items to keep in mind:Understand the rights and restrictions of the subject royalty interest: Royalty interests may have value into perpetuity as it is a direct ownership in the minerals;ORRI’s typically only have value for the life of the lease;Understand the differences between the subject ORRI and a publicly traded security that owns ORRI’s and make adjustments for the differences;Understand the historical, current and future outlook for commodity prices relating to the subject ORRI;Understand the historical, current and future outlook for reserves;Utilize publicly traded yields to assess the markets attitude for investments in similar securities; andAdjust for the differences between a publicly traded security and a non-marketable security. When comparing a royalty interest to an ORRI, it is critical to understand the subtle nuances of the rights and restrictions between the two. Owners of royalty interests utilizing PBT as a valuation gauge should adjust for such differences as well as other differences between publicly traded and non-marketable securities.  Contact Mercer Capital to discuss your needs in confidence and learn more about how we can help you succeed. End Note1 Although not shown in the above chart, proved reserves increased 32% between 2012 and 2013 for PBT
The Wild Goose Chase Is Over
The Wild Goose Chase Is Over
The Great Y2K scare led to approximately $134 billion in preparation for the world-altering event.  The belief that computers would malfunction and the world as we then knew it would end at midnight of December 31, 1999, led all major companies and many families to seek out help in preparation for the event, no matter the cost.  When the clocks struck midnight and everything but a few slot machines in Deleware continued running, we moved on to planning the next apocalyptic event – what if oil runs out?From 2000 to 2005, “concerns that supply could run out and soaring oil prices sent energy companies on a grand, often wildly expensive, chase for new production.”  They were investing in multi-billion-dollar projects in the Arctic waters and Kazakhstan’s Captain Sea. A WSJ article titled, “Oil Companies Take Thrifty Bets,” explained that when oil was worth $100 per barrel oil companies had much higher risk tolerance and were able to invest heavily in the exploration of undeveloped land and ocean.  But as the price of oil declined and has settled around $50 per barrel, the wild goose chase for oil has come to an end.Declining Capital ExpendituresWe are facing a different kind of supply crisis than previously imagined. Bloomberg analysts forecast that if OPEC cannot come to an agreement to extend cuts, it is forecasted that oil prices will fall to $40 per barrel.  And if oil falls to $40 per barrel then much of the drilling activity that surged in the Permian Basin is expected come to a halt.  Oil companies today can only focus on decreasing costs and reducing risks in order to stay afloat in an oversupplied market.  From 2014 to 2016, capital expenditures of the E&P companies, shown below, declined, on average, by 64%. In mid-2014 when the price of oil fell, exploration and production companies struggled to continue pumping oil from current wells.  In order to fund day-to-day operations, companies had to pull the plug on most of their capital projects.  Now that the price of oil has settled around $50 per barrel, exploration and production companies have begun to allocate small portions of their budget to research for new reserves and the exploration of new wells. Even as exploration and production companies’ revenues declined dramatically, capital expenditures shrunk from an average of 71% of revenues in 2011 to 43% of revenues in 2016.  However, as capex budgets are shrinking, the cost to explore and drill new wells is increasing. The price of fracking sand has increased recently as companies drill wells deeper in order to find efficiencies of scale. Deeper drilling, however, requires larger amounts of sand. As fracking has become more common, drilling in shale fields requires approximately 30% more sand every year.  Although the price of fracking sand is still below $60 to $70 per ton, where it was before crude prices fell, Mr. O’Leary, director of oil-field services research at Tudor Pickering thinks that the price of sand will rise to $50 a ton this year. Last fall the cost of sand accounted for between 5% and 7% of the cost of a well but Mr. O’Leary expects that percentage to rise as exploration and production companies increase their usage of fracking sand this year.  Further he said, “The millions of pounds of sand being poured down wells is pushing up sand prices, eroding some of the profits that energy companies have managed to regain since the oil bust ended.” In order to protect themselves from higher costs and shortages in fracking sand, some companies such as Pioneer Natural Resources have purchased their own sand mines. In order to reduce costs and minimize risk, companies are looking for investments with shorter payback periods.  Exxon, BP, Shell, and Chevron are investing in quick ventures in Texas and in existing projects in the Middle East and Brazil.  Companies are looking back at old basins to see if new technologies can be used to extract any remaining resources.  This is a big shift for companies who used to believe that the large upfront costs that would be paid off over 20 to 30 years generated the best return. But what does the decline in capital expenditures today mean for supply and prices tomorrow?  Due to the advancement of technology and the speed at which companies can bring new projects online, it is not likely that we will see a supply shortage any time soon. Rather low oil prices seem to be the new normal.  When oil prices hit $60 then certain DUCS will be economical and will be brought online. And when oil hits $70… there will be more DUCs ready to be completed. Mercer Capital has significant experience valuing assets and companies in the energy and construction industries.  Our valuations have been reviewed and relied on by buyers and sellers and Big 4 Auditors. These valuations have been utilized to support valuations for IRS Estate and Gift Tax, GAAP accounting, and litigation purposes. Contact a Mercer Capital professional today to discuss your valuation needs in confidence.
How to Perform a Purchase Price Allocation for an Exploration and Production Company
How to Perform a Purchase Price Allocation for an Exploration and Production Company
This guest post first appeared on Mercer Capital’s Financial Reporting Blog on January 18, 2016. When performing a purchase price allocation for an Exploration and Production (E&P) company, careful attention must be paid to both the accounting rules and the specialty nuances of the oil and gas industry. E&P companies are unique entities compared to traditional businesses such as manufacturing, wholesale, services or retail. As unique entities, the accounting rules have both universal rules to adhere as well as industry specific. Our senior professionals bring significant experience in performing purchase price allocations in the E&P area where these two principles collide. For the most part, current assets, current liabilities are straight forward. The unique factors of an E&P are found in the fixed assets and intangibles: producing, probable and possible reserves, raw acreage rights, gathering systems, drill rigs, pipe, working interests, royalty interests, contracts, hedges, etc. Different accounting methods like the full cost method or the successful efforts method can create comparability issues between two E&P’s that utilize opposite methods. We will explore the unique factors in future entries. In this blog post, we discuss the guidelines for purchase price allocations that all companies must adhere. Reviewing a purchase price allocation report can be a daunting task if you don’t do it for a living – especially if you aren’t familiar with the rules and standards governing the allocation process and the valuation methods used to determine the fair value of intangible assets. While it can be tempting as a financial manager to leave this job to your auditor and valuation specialist, it is important to stay on top of the allocation process. Too often, managers find themselves struggling to answer eleventh hour questions from auditors or being surprised by the effect on earnings from intangible asset amortization. This guide is intended to make the report review process easier while helping to avoid these unnecessary hassles. Please note that a review of the valuation methods and fair value accounting standards is beyond the scope of this guide. Grappling with these issues is the responsibility of the valuation specialist, and a purchase price allocation report should explain the valuation issues relevant to your particular acquisition. Instead, this guide focuses on providing an overview of the structure and content of a properly prepared purchase price allocation report.General RulesWhile every acquisition will present different circumstances that will impact the purchase price allocation process, there are a few general rules common to all properly prepared reports. From a qualitative standpoint, a purchase price allocation report should satisfy three conditions:The report should be well-documented. As a general rule, the reviewer of the purchase price allocation should be able to follow the allocation process step-by-step. Supporting documentation used by the valuation specialist in the determination of value should be clearly listed and the report narrative should be sufficiently detailed so that the methods used in the allocation can be understood.The report should demonstrate that the valuation specialist is knowledgeable of all relevant facts and circumstances pertaining to the acquisition. If a valuation specialist is not aware of pertinent facts related to the company or transaction, he or she will be unable to provide a reasonable purchase price allocation. If the report does not demonstrate this knowledge, the reviewer of the report will be unable to rely on the allocation.The report should make sense. A purchase price allocation report will not make sense if it describes an unsound valuation process or if it describes a reasonable valuation process in an abbreviated, ambiguous, or dense manner. Rather, the report should be written in clear language and reflect the economic reality of the acquisition (within the bounds of fair value accounting rules).Assignment DefinitionA purchase price allocation report should include a clear definition of the valuation assignment. For a purchase price allocation, the assignment definition should include:Objective. The definition of the valuation objective should specify the client, the acquired business, and the intangible assets to be valued.Purpose. The purpose explains why the valuation specialist was retained. Typically, a purchase price allocation is completed to comply with GAAP financial reporting rules.Effective Date. The effective date of the purchase price allocation is typically the closing date of the acquisition.Standard of Value. The standard of value specifies the definition of value used in the purchase price allocation. If the valuation is being conducted for financial reporting purposes, the standard of value will generally be fair value as defined in ASC 820.Statement of Scope and Limitations. Most valuation standards of practice require such statements that clearly delineate the information relied upon and specify what the valuation does and does not purport to do.Background InformationThe purchase price allocation report should demonstrate that the valuation specialist has a thorough understanding of the acquired business, the intangible assets to be valued, the company’s historical financial performance, and the transaction giving rise to the purchase price allocation.Company OverviewDiscussion related to the acquired company should demonstrate that the valuation specialist is knowledgeable of the company and has conducted sufficient due diligence for the valuation. The overview should also discuss any characteristics of the company that play a material role in the valuation process. The description should almost always include discussion related to the history and structure of the company, the competitive environment, and key operational considerations.Intangible AssetsThe intangible assets discussion should both provide an overview of all relevant technical guidance related to the particular asset and detail the characteristics of the asset that are significant to the valuation. The overview of guidance demonstrates the specialist is aware of all the relevant standards and acceptable valuation methods for a given asset.After reading this section, the reviewer of the purchase price allocation report should have a clear understanding of how the existence of the various intangible assets contribute to the value of the enterprise (how they impact cash flow, risk, and growth).Historical Financial PerformanceThe historical financial performance of the acquired company provides important context to the story of what the purchasing company plans to do with its new acquisition. While prospective cash flows are most relevant to the actual valuation of intangible assets, the acquired company’s historical performance is a useful tool to substantiate the reasonableness of stated expectations for future financial performance.This does not mean that a company that has never historically made money cannot reasonably be expected to operate profitably in the future. It does mean that management must have a compelling growth or turn-around story (which the specialist would thoroughly explain in the company overview discussion in the report).Transaction OverviewTransaction structures can be complicated and specific deal terms often have a significant impact on value. Purchase agreements may specify various terms for initial purchase consideration, include or exclude specific assets and liabilities, specify various structures of earn-out consideration, contain embedded contractual obligations, or contain other unique terms. The valuation specialist must demonstrate a thorough understanding of the deal terms and discuss the specific terms that carry significant value implications.Fair Value DeterminationThe report should provide adequate description of the valuation approaches and methods relevant to the purchase price allocation. In general, the report should outline the three approaches to valuation (the cost approach, the market approach, and the income approach), regardless of the approaches selected for use in the valuation. This demonstrates that the valuation specialist is aware of and considered each of the approaches in the ultimate selection of valuation methods appropriate for the given circumstances.Depending on the situation, any of a number of valuation methods could be appropriate for a given intangible asset. While selection of the appropriate method is the responsibility of the valuation specialist, the reasoning should be documented in the report in such a way that a report reviewer can assess the valuation specialist’s judgment.At the closing of the discussion related to the valuation process, the report should provide some explanation of the overall reasonableness of the allocation. This discussion should include both a qualitative assessment and quantitative analysis for support. While this support will differ depending on circumstances, the report should adequately present how the valuation “hangs together.”Something to RememberA purchase price allocation is not intended to be a black box that is fed numbers and spits out an allocation. The fair value accounting rules and valuation guidance require that it be a reliable and auditable process so that users of financial statements can have a clear understanding of the actual economics of a particular acquisition. As a result, the allocation process should be sufficiently transparent that you are able to understand it without excessive effort, and the narrative of the report is a necessary component of this transparency.
A Bright Spot at the Bottom of the Barrel
A Bright Spot at the Bottom of the Barrel
How has the Asphalt Industry been Affected by Depressed Oil Prices?Asphalt and road oil are used primarily by the construction industry for roofing and waterproofing and for road construction.  Asphalt is a byproduct of petroleum refining.  During the distillation process of crude oil, asphalt does not boil off and is left as a heavy residue. Generally around 90% of crude is turned into high margin products such as gasoline, diesel, jet fuel, and petrochemicals while the other 10% is converted into asphalt and other low margin products.  Petroleum refiners sell asphalt to asphalt product manufacturers who produce retail products such as asphalt paving mixtures and blocks; asphalt emulsions; prepared asphalt and tar roofing and siding products; and roofing asphalts and pitches, coating, and cement. Demand for asphalt products is determined by the health of the construction industry and the level of infrastructure funding. How has the Construction Industry Impacted Demand for Asphalt?Spending on construction in December 2016 increased 0.2% from November 2016 and 4.2% from December 2015 to $1.18 trillion.  After several years of steady growth followed by decelerating growth in 2016, Dodge Data & Analytics forecasts total construction starts will increase by 5% in 2017 reaching $713 billion.  AIA believes that factors such as job growth, consumer confidence and low interest rates have propelled construction spending.How has Funding for Infrastructure Impacted Demand for Asphalt?About 93% of the 2.2 million miles of paved roads and highways in the U.S. are paved with asphalt.  Most road construction is funded by states, counties, or other federal programs.  Thus demand for asphalt and road oils are largely dependent on the level of funding available.  During the recession most local governments collected less revenue and could not afford investment in infrastructure.  Both federal and state level taxes designed to generate revenue for transportation use a per-gallon fuel tax.  Due to increasing fuel efficiency and lower gas prices, fuel taxes have generated less money. Further, the 18.4 cent-per-gallon federal gas tax has not been increased in more than twenty years and has not kept up with inflation or increasing costs.  Some states have increased their state gas tax in order to fund these programs, but funding of infrastructure over the last decade has generally been insufficient.For the past decade, the federal government has been funding transportation for short periods of time using extensions of previous plans.   In August 2005, the Safe, Accountable, Flexible, Efficient Transportation Equity Act: A Legacy for Users (SAFETEA-LU) was signed into law.  In July 2012, after multiple extensions of the SAFETEA-LU, the Moving Ahead for Progress in the 21st Century Act (MAP-21) was passed by Congress.  MAP-21 extended SAFETEA-LU for the remainder of 2012, with new provisions for FY 2013 and beyond.  Funding levels were maintained at FY 2012 levels with minor adjustments for inflation.President Obama signed the FAST (Fixing America’s Surface Transportation) Act in December of 2015. The FAST Act provided $305 billion from 2016 to 2022 for programs to improve highways, highway and motor vehicle safety, and other critical transportation projects.  Included in this legislation is a new National Highway Freight Program which will focus most of its funding on highways.  The legislation also aims to reduce administrative and bureaucratic obstacles allowing the DOT to delegate project oversight to states on a project and programmatic basis.While investment did modestly increase in 2016, it is likely that demand will pick up more in 2017 as projects funded by the FAST Act start being implemented.  Mike Acott, president of the National Asphalt Pavement Association (NAPA) said that the most significant change since the FAST Act was passed has been a pickup in resurfacing activity.  Resurfacing roads is a much cheaper alternative to repaving and many local governments were able to work the resurfacing of roads into the limits of their tight budgets.  Increased demand for repaving materials led to industry innovation and new product developments to meet this demand.How did the Asphalt Industry Perform in 2016?As the price of crude oil fell so did the price of asphalt sold by petroleum refineries.  Crude oil prices fell by 50% from June 2014 to January 2017 (the most recent PPI data available for asphalt) while asphalt prices fell 55% over this same time period. Refiner’s margins generally increased in 2015 and fell over the last year. As shown in the chart above, the movement of refined product prices lags changes in crude prices.  Thus in 2015, refiners purchased crude for cheaper prices than before but sold their products at the same prices. In 2016 however, asphalt prices began to fall and margins narrowed. Marathon reported that their asphalt operations were weaker than their “exceptionally strong” year of operations in 2015. Analysts expect the price of asphalt to increase over the next few years.  As refining technology improves refiners are able to produce more gasoline out of a barrel of oil leaving less to be made into paving grade asphalt.  This reduction in supply will likely increase asphalt prices. As the price of crude fell, refiners margins narrowed, which led to a decrease in cost of goods sold for asphalt manufacturers resulting in a pickup in earnings.  Because of the impact of transportation costs on the industry and the quick hardening time of ready mix asphalt, competition is based primarily on location and price. In general asphalt manufacturers’ margins increased in 2016 as their cost of goods fell.  Vulcan Materials, Inc. (VMC) produces aggregates and ready mix asphalt in Birmingham, Alabama.  Its asphalt mix segment’s gross profit increased 25% in 2016.  While sales volume and sales price declined by 3% and 2%, respectively the cost of goods sold decreased and expanded the Company’s gross profit margin by 4.3 percentage points. Martin Marietta (MLM), which produces aggregate and asphalt products in North Carolina, realized a 15.7% gross profit margin in its asphalt and paving segment in 2016 compared to a 12.6% margin in 2015. How will the Asphalt Industry Perform in 2017?Going forward investment in infrastructure is expected to increase.  After many states cut infrastructure funding, there is currently much work that needs to be done to improve the conditions of roads and highways.   As state and local government budgets have improved since the recession, it is anticipated that tax revenue available for investment in road infrastructure will expand.  Additionally, President Trump, during his campaign, pledged to invest $1 trillion in infrastructure in order to spur economic growth.   Finally, prices for cement, which is a substitute for asphalt, are expected to rise which will increase the demand for asphalt.  Overall, industry revenue is expected to increase by 2.3% over the next five years.1Mercer Capital has significant experience valuing assets and companies in the energy and construction industries.  Our valuations have been reviewed and relied on by buyers and sellers and Big 4 Auditors. These valuations have been utilized to support valuations for IRS Estate and Gift Tax, GAAP accounting, and litigation purposes. Contact a Mercer Capital professional today to discuss your valuation needs in confidence.End Note1 IBIS World Report 32412: Asphalt Manufacturing in the US: October 2016
Are S&P Energy Stock Valuations Really Crazy Right Now?
Are S&P Energy Stock Valuations Really Crazy Right Now?
A few days ago the Wall Street Journal published an article discussing what the author described as “crazy” stock valuations, and in particular the inflated valuations of oil and gas stocks from the perspective of operating earnings ratios.“The energy sector stands at more than 30 times Thomson Reuters IBES’s estimate of operating earnings over the next 12 months, higher than any time from when the sector data started in 1995 up to last year – when it briefly reached an extreme of almost 60 times.”The article also mentions that the S&P 500 as a whole is trading at almost 18 times estimated future operating margins.  This got us to thinking - In light of what has transpired over the past two plus years in the energy sector, could it really be that stocks are overvalued?  That certainly hasn’t been the sentiment that we hear from our clients.  Maybe we’re all wrong?  If so, what could be driving this?While we certainly are believers that value is driven by future operating earnings, and that earnings in the energy sector have fallen precipitously since 2014, is this all that determines the market’s pricing of the S&P 500 energy sector?  As we reflect on this for a moment, a few additional considerations came to mind that may explain these “crazy” valuations more fully.Anticipated Tax ReliefOne consideration not captured in an operating earnings ratio that markets are using to impact values is expectations for future tax reform.  Since the new administration has been inaugurated the stock market has risen significantly.  Clearly, one of the sources of this market optimism is the platform of tax reform – including corporate taxes.  There are a number of sources describing what this new structure may look like.  One particularly insightful article was written by Jason B. Freeman in the January/February issue of Today’s CPA titled "Tax Reform Under a Trump Administration".President Trump’s plan would drop the corporate tax rate from 35% (among the highest in the world) to 15% or 20%.  This would immediately bring tax relief at a corporate level and boost earnings.  Judging by the equity market’s early reaction this morning to Mr. Trump’s State of the Union address, in which he highlighted this issue, anticipation of this action is fueling higher stock prices.Anticipated Regulation ReformThe market may also be considering the future impact President Trump’s regulation reform.  While there is much uncertainty surrounding the future regulation of the oil and gas industry, President Trump ran as a friend to the oil and gas sector and promised to reduce regulations on the industry in order to boost the U.S. economy. Additionally, Oklahoma Attorney General Scott Pruitt was confirmed as the Environmental Protection Agency administrator.  Pruitt has openly opposed the EPA, which is one of the main regulators of the oil and gas industry.  Looser regulations on the oil and gas industry could reduce operating expenses associated with meeting current regulation and could provide new opportunities for the industry.Growth UnderpinningsThe energy sector has been hit hard, but a less visible aspect of the WSJ article’s premise is that there are signs that the energy sector’s depression in earnings may be short lived and the market is forecasting a rebound.  Consider this, the price of oil is at or near decade lows and earnings are sensitive to commodity prices, particularly when the price of oil hovers close to breakeven costs for producers (which it is currently).  Slight upward changes in oil and gas prices could have significant upward impacts on profits.  In addition, due to the drop in commodity prices, the industry has responded by innovating and pushing costs downward for drilling shale wells.Reserves Reserves Reserves!Another aspect that can’t be detected by an operating earnings ratio is how awash in reserves we currently are.  U.S. crude oil inventories have hit all-time highs, and demonstrate how poised the energy sector is to respond to manufacturing and consumer growth. Reserves are the foundation of value for E&P companies which is why this metric is oftentimes much more important than mere earnings.  It shows the potential for earnings 5 to 10 years or even 20 years down the road, which is something one year earnings estimates do not consider.  Better ratios to consider here are equity values relative to daily or annual production or total proved reserves. The Big PictureAt any given moment it can be hard to say if equities, sectors or companies are “overvalued”.  Valuation is relative to begin with and ultimately at a point in time the “value” is what market participants will pay.  As it pertains to oil and gas companies, it appears clear that earnings are low as the sector better copes with $50-55 oil and $3 gas.  However, the market appears to see brighter days ahead, beyond 2017 and that confidence along with optimism for tax reform, operating efficiencies, and positioning for future growth are buoying prices.  Perhaps investors aren’t crazy after all.  Of course that’s just my opinion….I could be wrong.
Refining Overview
Refining Overview
There are four main components to refined product prices: (1) Input Prices (i.e. crude oil), (2) Wholesale Margins, (3) Retail Distribution Costs, and (4) Taxes.  Generally, input prices and wholesale margins drive fluctuations in product prices as the last two are relatively stable.  Thus, in order to understand refined product prices we consider the macroeconomic trends in the global oil and gas market which drive input prices.Oil and Gas Market OverviewGlobal oil production outpaced global crude demand for almost a year which led to a plummet in oil prices in mid-2014.  Oil prices have remained depressed since then and an oversupply of crude caused downward pressure on the price of crude oil which for months benefitted refiners as their product costs fell.  A shortage of crude storage forced producers to sell crude at increasingly low prices to refiners, who then could earn substantial profits.In a move that surprised many markets, OPEC instituted production cuts for the first time in eight years following a November 30, 2016 meeting.  OPEC planned to reduce output by 1.2 million barrels a day by January 2017.  In addition, Russia, who is not a member of OPEC, agreed to cut oil production.  The reduction in output is designed to reduce high inventory levels around the globe.  The cuts are expected to be effective through May 25, 2017, at which time OPEC may opt to extend the cuts an additional six months.Oil prices may have found a new home around $50-$60 per barrel, which remains below normal levels, but exploration and production activities have recovered partially. The Baker Hughes North American (U.S.) total oil rig count increased by 32% over the year ended February 3, 2016.  Crude oil prices (“WTI”) ended 2016 nearly 45% higher than year-end 2015.  The WTI gain is the first annual price increase in two years, and is the largest annual gain in seven years.The oil and gas industry is heavily regulated.  The future impact of many regulations surrounding the oil and gas industry however is uncertain as President Trump ran as a friend to the oil and gas sector and promised to reduce regulations on the industry in order to boost the U.S. economy. Additionally, Oklahoma Attorney General Scott Pruitt is on his way to becoming the next Environmental Protection Agency administrator.  Pruitt has openly opposed the EPA, which is one of the main regulators of the refining industry.  As we work to understand the current position of refiners, it is key to analyze the impact of legislation and regulation surrounding the industry.Refining RegulationIn early 2016 the crude oil export ban that had been in place since 1975 was lifted.  Industry experts thought that the lifting of the export ban would better align the production capabilities of U.S. refineries. Refiners, on the other hand, feared that the exportation of crude oil would increase crude prices, as the pressure on price in an oversupplied U.S. market gave way.   However, due to the state of the global oil market there is not much incentive to buy crude oil from the U.S. in the current market. Currently, it is estimated that less than 400,000 barrels per day (bpd) is being exported form the U.S.  Once the Brent-WTI spread widens, and it is cheaper for other countries to buy WTI and pay transportation costs than to buy Brent, we may better understand the effect of the lifting of the ban.Although the price of crude oil remains low in comparison to historical levels, refined product prices fell to a similar extent as crude prices. As shown below, the price of gasoline fell to a low of $1.05/gallon in February 2016, which was almost one-third of the price of gasoline in July 2014.  Since February the price of gasoline has increased 36%.  In general, refined product prices have fallen over the last two years but have seen some recovery over the last 10 months. Additionally, operating expenses have increased with the cost of Renewable Identification Numbers (RINS).  The Renewable Fuels Standards (RFS) Program has had a significant impact on the refining sector over the last year.  The RFS were signed into law by President George W. Bush in order to reduce greenhouse gas emissions and boost rural farm economies.  Each November, the EPA issues rules increasing Renewable Fuel Volume Targets for the next year. RINs (Renewable Identification Numbers) are used to implement the Renewable Fuel Standards.  At the end of the year, producers and importers use RINs to demonstrate their compliance with the RFS.  Refiners and producers without blending capabilities can either purchase renewable fuels with RINs attached or they can purchase RINs through the EPA's Moderated Transaction System. While large integrated refiners have the capability to blend their petroleum products with renewable fuels, small and medium sized merchant refiners do not have this capability and are required to purchase RINS, which have significantly increased in price.  A common theme across refiners’ earnings calls last quarter was the effect of the rising cost of RINs on already squeezed margins.  President Trump promised to help small and medium sized merchant refiners who were disadvantaged by RFS, but he also spoke fondly of the program during his campaign.  It appears that many Republican lawmakers hope to repeal or reform the Standards, but the future of the Standards and the RIN system is still unclear. Other regulations that might affect refiners’ margins going forward include the Petroleum Refinery Sector Risk and Technology Review (RTR) and the New Source Performance Standards (NSPS).  Last December the RTR & NSPS rule was passed in in order to control air pollution from refineries and provide the public with information about refineries’ air pollution.  These regulations range from fence line and storage tank monitoring to more complex requirements for key refinery processing units.  The rule was expected to be fully implemented in 2018 however the expected new head of the EPA makes us to question the future implementation of the rules. We can understand refiner’s current earning power through the refiner maker margin.  The refiner marker margin (RMM) is a general indicator, calculated quarterly by British Petroleum, which shows the estimated profit refiners earn from refining one barrel of crude. Refiners’ margins increased dramatically in the second and third quarters of 2015 as the price of crude fell and the price of refined petroleum products lagged behind.  Refiners in the U.S. North West were making between $27 and $28 per barrel of oil, while global margins barely reached $20 per barrel.   However, in the fourth quarter of 2015 refined product prices fell, refiners’ margins tightened, and the geographic gap in margins narrowed. After some relief in margin pressure in the second quarter of 2016, margins tightened to the lowest seen in three years. M&AM&A activity in the refining sector was sluggish in the first half of 2016, partially due to the uncertainty which surrounded the refining industry and future regulation.  However, M&A activity picked up in the third and fourth quarter of 2016.  The chart below shows key valuation metrics associated with refining transactions which were announced in 2016. Overall, valuation multiples are inflated, demonstrating that companies are buying the future earnings potentials of refiners and are not too discouraged by currently low earnings. Mercer Capital has significant experience valuing assets and companies in the energy industry, primarily oil and gas, bio fuels and other minerals.  Our oil and gas valuations have been reviewed and relied on by buyers and sellers and Big 4 Auditors. These oil and gas related valuations have been utilized to support valuations for IRS Estate and Gift Tax, GAAP accounting, and litigation purposes. We have performed oil and gas valuations and associated oil and gas reserves domestically throughout the United States and in foreign countries. Contact a Mercer Capital professional today to discuss your valuation needs in confidence.
There Was Blood
There Was Blood
Warren Buffett’s guidance is salt in the wound for those in the oil and gas industry: “You pay a very high price in the stock market for a cheery consensus.” That was the title of his article published in Forbes Magazine in November of 2008. Energy companies, investors and royalty owners all paid a very high price to invest in the oil and gas industry prior to July 2014. But, those who invested when there was a “Cheery Consensus” have now endured more than 20 months since the crash of oil started. Fear and uncertainty were so rampant that many anticipated oil prices to fall to $10 per barrel. Yet during this turmoil did you remember another famous investing principle from Baron Rothschild: “Buy when there's blood in the streets, even if the blood is your own." Okay, I’m sure you remembered it at some point during the fall, but did you have the moxy to act on it?There was blood in the street, lots of it, over the last two years. Many operators and oil and gas service companies didn’t survive the last 20 months and most of the news headlines focused on their story. For royalty owners, who might depend upon royalty checks for steady income, it was equally scary as their payments shrunk due to low oil prices which were magnified by lower production rates. Operators went belly up or were acquired, each of which leads to administrative complications and disruptions in check disbursements to royalty owners. Some unlucky royalty owners received demand letters indicating they received royalty payments for interests they didn’t own and therefore must pay back multiple years’ worth of royalty receipts to the operators. How does that happen? It appears, when there is a cheery consensus, details get overlooked until the environment turns dire.However, the last 12 months have provided some relief. Oil prices have increased more than 65%, acquisition activity in the Permian Basin is high, and the oil and gas equity markets have shown positive growth. Additionally, investors seeking income generating investments have been interested in royalty trusts which have had significant returns over the last 12 months. If you had the moxy to grab the “falling knife” back in early 2016, it appears you grabbed the handle and not the blade. Returns over the last 12 months have been in the double digits and perhaps triple digits depending on the investment vehicle. Sadly, the fall in oil price was so significant that investments made more than 18 months ago are largely still under water, while those made less than 12 months ago are sitting pretty. This is true for royalty owners as well.Market indications are available in the form of publicly traded oil & gas royalty trusts. There are approximately 20 oil and gas focused royalty trusts publicly traded, as of the date of this article. In the last two months, the implied payback period increased 1.1 years, on average, from 11.1 years to 12.2 years. This occurred from declining yields as equity prices increased.Market ObservationsRoyalty trusts, like the rest of the oil and gas industry, have been hit hard over the previous 24 months. Before the bottom fell out, oil traded as high as $107.95 in June of 2014 and plunged to a low of $29.05 in February of 2016. Since February, the price of oil appears to have found a new home between $50-$60 / barrel. That said the last two years have been a trying time to hold investments in oil and gas, especially in Royalty Trusts. Below is a chart of the market price performance for each royalty trust over the last two years. Only one is showing a positive price performance, Black Stone Minerals, LP, but this is slightly misleading as it’s only been publicly traded for the prior 42 months (just shy of two years). The above chart looks very similar to the performance of the price of oil and gas over the same time period. Royalty interest owners have seen their monthly payments move in the same manner. Yes, if you invested in the energy sector approximately two years ago, there is a good chance your investment is still underwater. However, if you invested one year ago, the results are dramatically different. We are approximately 12 months from the days oil prices hit the “bottom of the barrel” and since February 2016, WTI has increased more than 65%. Below is the same chart adjusted to show the performance over the last 12 months. Only three of the twenty royalty trusts have negative price performance over the last year, compared to 19 when observing performance over the last two years. Of the three that are negative, two were discussed in earlier posts.  Sandridge Mississippian Trust I and II’s operator was going through bankruptcy and the location of their wells was not as desirable as other plays. The other royalty trust with negative performance is Chesapeake Granite Wash Trust. For the above 20 Royalty Trusts, we compared various pricing metrics between today and one year ago: Observations and Disclaimers1Price to revenue and price to distributable income indicate, on average, the trusts are more expensive now than a year ago. This trend has continued from our discussion in December 2016.Yields were higher last year as they did not reflect the quickly falling market price. Increase in pricing over the last 12 months is the primary cause of the lower yields. Some Trusts have cut their distributions in response to falling royalties. The combination of the two results in lower yields.As of today, market prices have leveled off and annual distributions are comprised of a full year of lower royalty payments, resulting in lower yields compared to a year ago.Price to PV-10 is significantly higher this year compared to last. The market is now willing to pay 2.5x more than the present value of future cash flows for the operating wells as opposed to 0.6x a year ago. However, PV 10 data is only disclosed annually, typically during the first quarter of the year. We are monitoring disclosures to update our models as the data becomes available. Stay tuned.A year ago, many expected oil prices to reach $43/ barrel, or increase by 44%, over the year. This turned out to be directionally correct, but understated the actual performance. The current spot price is $53.88/ barrel which was an increase of 80%. Natural gas prices performed much the same way, increasing 34%. However, for the next 12 months oil prices are expected to increase by only 4% while natural gas prices are anticipated to jump by 15%.Implications for Royalty OwnersIn many respects, royalty owners can utilize publicly traded royalty trusts to observe changes in investor behavior and get a feel for how much their royalty interests may be worth. Here are a few areas to consider for your specific situation to compare and contrast with Royalty Trusts:Set Number of Assets. Royalty trusts typically have a set number of wells and producing assets after they are formed. Does your property have a fixed number of assets or will it grow? If new oil and gas wells are not being added to the property, then the oil and natural-gas reserves will be depleted as they age and produce.Location. The Royalty Trusts above have assets all over North America. Some are located in hot spots while others are not. Location drives investor appetite as operating costs and production levels, which vary by location, drive profitability in an industry that has zero control over the price of their product. This is a significant reason for the high transaction activity in the Permian Basin. Operators know they are able to make a profit through high production rates and low operating costs in Permian Basin even at $40 oil. Consider the investor activity, or lack there-of, in your area.Price and Production. Now that the U.S. has significant recoverable oil and gas reserves and the ability to export unrefined crude world-wide, the U.S. can be considered a swing producer, a power which historically characterized OPEC. As a swing producer, price dictates the level of production the market will consume and production will increase or decrease relatively quickly to meet demand. In response to price changes, operators will increase or decrease production levels at will. Consider how your operator has behaved in various pricing environments and the operators of the Royalty Trusts. In addition to the differences between your royalty assets and the Royalty Trusts, consider the level of value indication provided by the Royalty Trusts. The level of value is the publicly traded level of value verses the privately held royalty assets held by many land owners. Consider the following chart. Chris Mercer explains, The benchmark level is the marketable minority level of value, or the middle level in the chart above.  Conceptually, it represents the pricing of the equity of a public company with an active and freely trading market for its shares.  For a private company, it represents that same price as if there were a free and active market for its shares. The lowest level on the traditional levels of value chart is called the nonmarketable minority level of value.  This level represents the conceptual value of illiquid (i.e., nonmarketable) minority interests of private companies, or entities that lack active markets for their shares.Royalty trusts provide an indication of value at the Marketable Minority Value level for minority interests in an entity with royalties as the primary asset. For royalty owners the value level can be a mixed bag. Many   own the asset directly while others own equity interests in entities with royalties as their main assets. It is important to understand the value level comparability difference for your situation.To move from the Marketable Minority Value to the Nonmarketable Minority Value level, simply apply a marketability discount. Stated a different way, apply a discount for not having the ability to quickly sell your asset and receive cash. Fully marketable assets, like those publicly traded, have the ability to exchange the asset for cash in approximately three days. All other assets which do not have this access lack marketability. Therefore in order to build and find a market for the assets, a discount is typically required by potential investors.We have assisted many clients with various valuation and cash flow issues regarding royalty interests.  Contact Mercer Capital to discuss your needs in confidence and learn more about how we can help you succeed.1 Disclaimer: no two of the above royalty trusts are alike. Differences abound in asset mix, asset location, term, and resource mix, just to name a few. In future blog posts, we will explore each trust individually and discuss their uniqueness.
Master Limited Partnerships
Master Limited Partnerships
Master Limited Partnerships (MLPs) are publicly traded partnerships, which reap the tax benefits of a partnership and the liquidity benefits of a public company. There are many tax benefits to an MLP.  Unlike public companies, MLPs are taxed only at the unitholder level.  Distributions to unitholders are tax deferred, if the Partnership distribution is greater than Partnership income.  And, units can be passed down to successors at a basis of fair market value, which means that the capital gains tax is not passed down along with the unit.  There are also some serious tax implications of the MLP structure.  For example, when an MLP’s debt is forgiven, the amount cancelled is treated as income and is taxed at the unitholder level.  However, there is generally not a cash distribution which accompanies this tax payment.History of MLPsApache Oil established the first MLP in 1981 and had such great success with the structure that real estate investors, restaurants, hotels, and NBA teams restructured to become MLPs.  In 1987, Congress revamped the tax code specifying that in order to be an MLP at least 90% of a company’s income must be generated from “qualified sources”.  Qualified sources include, “the exploration, development, mining or production, processing, refining, transportation (including pipelines transporting gas, oil, or products thereof), or the marketing of any mineral or natural resource (including fertilizer, geothermal energy, and timber).”  In 2008, Congress expanded this to include carbon dioxide, biofuels, and other alternative fuels.E&P companies are sensitive to swings in commodity prices and do not have stable enough cash flows to sustain the distribution requirement of MLPs.  Often times E&P companies spun off their midstream assets into MLPs because midstream operations provide stable cash flows and have the ability to reliably make distributions. Thus the majority of MLPs are involved in the midstream oil and gas sector.  Recently, however, the stability of midstream cash flows has been called into question.Midstream companies have long term contracts called take-or-pay contracts which require producers to pay midstream companies even if they are not currently using their gathering assets.  It was always assumed that these contracts were inviolate; however, the recent turmoil in the oil and gas market, which led to a multitude of bankruptcies in the E&P sector, caused these contracts to be called into question in bankruptcy court proceedings.   During the bankruptcy process, producers can request that certain contracts be rejected.  If the midstream contracts are thought to be vastly different from market value then the producer can request the judge consider the rejection of midstream contracts.  We saw this in March of 2015 when a New York judge ruled that Sabine Oil and Gas Corp., which was going through bankruptcy proceedings, could reject contracts it was in with midstream companies. This uncertainty caused the price of MLPs to fall as investors began to question the immunity of their cash flows.  From December 2014 to December 2015 the price of MLPs on average fell by 25%.MLPs have two classes of Partners: General Partners, who are responsible for managing day to day operations and receive compensation for doing so, and Limited Partners (called unitholders) who are investors in the Partnership and receive periodic distributions.  Unlike a public company which is governed by a board, a MLP is generally managed by a general partner.  Legally, the general partner has no fiduciary duty to the unitholders, but mostly their interests align.MLPs payout a large portion of cash flows (generally 80% to 100%) to their unitholders. Distributions are based on each MLP’s partnership agreement and usually minimum quarterly distributions are written into the MLP’s partnership agreements. The General Partner typically owns a 2% equity interest along with incentive distribution rights (IDRs).  Incentive distribution rights give a general partner an increasing share in the incremental distributable cash flow of the Partnership.  IDRs are meant to incentivize the GP to increase distributions for the limited partners.Valuing an MLPThere are approximately 140 MLPs and in 2013 over 50% of MLPs operated in the midstream and downstream oil and gas sector.  While each Company is unique the guideline approach can commonly be used to value MLPs in the oil and gas sector.   A price to earnings multiple however is uninformative when valuing an MLP.  MLPs generally have a lot of fixed assets on the balance sheet that result in high depreciation expenses charged to earnings. Thus earnings are not a good indicator of value. Instead we turn to companies’ distribution history.Several MLPs and their key financials are summarized in the chart below.   MLPs generally pique the interest of investors looking for income generating investments, demonstrated by the dividend yield.  But there are three other measures that should be used to understand the value and inherent risk of an MLP: (1) Distribution Coverage Ratio (DCR), (2) Price / Distributable Cash Flow (P / DCF), and (3) Debt / EBITDA.A MLP’s distribution coverage ratio (DCR) measures the sustainability of current distributions.  A DCR of 1.0 indicates that an MLP is distributing all available cash flow and a DCR of greater than 1.0 indicates that a Partnership is retaining some cash.  A DCR of less than 1.0 is not sustainable.  All of the MLPs above have sustainable levels of distributions but Magellan Midstream’s (MMP) DCR of 1.0 does beg for further analysis as they are paying out all available cash flow.Instead of evaluating Price / Earnings multiples, we analyze Price / Distributable Cash Flow for MLPs.   Generally a P / DCR of more than 15x or 16x is considered high.  However, if the MLP has consistently grown distributions then the partnership may be worth the premium. Magellan Midstream was trading at 17.4x distributable cash flow, which is on the higher end of the range shown above. However, MMP has increased its quarterly distribution 59 times since it IPO-ed in 2001.  This trend of an increasing yield merits a higher P / DCF multiple.The Debt to EBITDA multiple can give us further insight into the company’s risk position.  Since MLPs must pay out the majority of their cash flows as distributions to unitholders, in order to fund capital expenditures and acquisitions an MLP must take on debt.  Magellan has a debt to EBITDA ration of 3.9x.  Generally a debt to EBIDTA multiple above 5x would be cause for concern, but Debt / EBITDA multiples for MLPs have trended upwards over the last four years.  In 2013 the median Debt / EBITDA multiple was 3.8x but increased to 5.4x by 2015.  Over the past three years the median EBITDA of our group increased by a compound annual rate of 8% while debt increased at a rate of 16% showing that the industry as a whole has become more leveraged.Mercer Capital’s oil and gas valuations have been reviewed and relied on by buyers and sellers and Big 4 Auditors. These oil and gas related valuations have been utilized to support valuations for IRS Estate and Gift Tax, GAAP accounting, and litigation purposes. We have performed oil and gas valuations throughout the United States and in foreign countries. Contact a Mercer Capital professional today to discuss your valuation needs in confidence.
Noble Energy Buys Clayton Williams: A Closer Look at the Acquisition
Noble Energy Buys Clayton Williams: A Closer Look at the Acquisition
Deal Details 1On January 16, 2017, Noble Energy, Inc. (NBL) announced the acquisition of all Clayton Williams Energy (CWEI) equity for approximately $2.7 billion in NBL stock and cash. Noble Energy is a global independent oil and gas exploration and production company.  Over 50% of their sales volume is generated from domestic onshore production. The Company focuses onshore domestic operations in the DJ, Delaware, and Eagle Ford Basins and the Marcellus Shale. The Company’s acquisition of CWEI demonstrates their effort to accelerate high margin growth by focusing capital in productive regions such as the Permian Basin.Shareholders of CWEI will receive approximately $34.75/share in cash and 2.7874 NBL common shares for each share of CWEI stock. Based on CWEI disclosures, NBL will assume control of 330,000 net acres in the Permian Basin and Giddings area of the Eagle Ford which include 13.6 MBOE of net daily production. The 170,000 net acres in the Permian are located in Ward and Reeves County. Approximately 72% of the current production is crude oil. The transaction indicated a 48% premium to the publicly traded equity value for CWEI.   Noble Energy was willing to pay a premium for the CWEI because the CWEI’s acreage was continuous to Noble’s which provides Noble with potentially cost saving synergies.Based upon the consideration given by NBL, here is the implied market value of invested capital (MVIC) for CWEI: A summary of CWEI’s book value balance sheet is shown below.2 Before venturing into our approach to the allocation, we have compared pricing multiples of the CWEI acquisition and other oil and gas public companies. At the time of the transaction, CWEI owned acreage rights in one of the most popular domestic resource plays, the Delaware Basin. The chart below shows the implied pricing metrics for CWEI versus selected transactions involving companies with a significant presence in the Permian Basin. Noble Energy’s pricing multiples are also presented to show size comparisons. Observations: Noble Energy’s purchase of CWEI was one of the largest acquisitions in the Permian basin over the last few years.Based on BOE per day production, CWEI was priced higher than Yates and SHE, as both companies were producing more than CWEI.Based upon net acres acquired, the CWEI transaction was priced in the middle of Yates and SHE and slightly above its’ suitor NBL.While this acquisition appears to be priced high on the BOEPD metric, the significant amount of acreage acquired by NBL indicates a net acre multiple that is consistent with other transactions.Assets PurchasedThe following maps, disclosed by CWEI, shows the acreage positions within each of the core resource plays, the Permian Basin and the Eagle Ford. The highlighted acquired assets include:65,000 net acres in Reeves County, Texas (Permian Basin map below) with over 100 wells producing or soon to be producing. A target pay zone of 3,500 feet wide (between the depths of 8,000 ft to 11,500 ft,) and 1 rig actively drilling in the area.Eagle Ford shale property includes 160,000 net acreage positions, 40 completed wells, a demonstrated and repeatable drilling program and new well costs of $4m per well. Chairman, President and CEO of NBL David Stover had the following comments on their acquisition: "This transaction brings all the key elements we value: excellent rock quality, a large contiguous acreage position adjacent to our own and robust midstream opportunities, reinforcing the Delaware Basin as a long-term value and growth driver for Noble Energy.""This combination creates the industry's second-largest Southern Delaware Basin acreage position and provides more than 4,200 drilling locations on approximately 120,000 net acres, with over 2 billion barrels of oil equivalent in net unrisked resource."Earlier, we displayed the high level categories for an allocation of purchase price. Two of these categories are oil and gas related assets:  (1) the fixed assets on the balance sheet; and (2) the implied goodwill value. Each of these is inter-related as a majority of the fixed assets are related to the exploration and production of oil and gas resources. Based upon our experience, much of the “implied goodwill” is related to the present value of future benefits of the production of oil and gas. The valuation for current production and proved developed reserves can be straight forward. CWEI more than likely prepared a reserve report which would aid in the valuation of the currently producing wells and the remaining proved reserves. However, the valuation gap between the proved developed reserves and the remaining proved undeveloped, probable and possible reserves or acreage value can be detailed, tedious, and complex. The historically low oil and gas price environment and financial tension within the industry creates a complicated market place for using market transactions as indications of value.More information is needed to drill down into the specifics and valuation of each of the acquired oil and gas assets. Interested parties may want to consider the following information areas:Reserve Reports. Specifically, it is important to understand the amount of acreage in each of the maps above that have been drilled versus what areas are included in the drilling plan, PV 10 indications and price deck assumptions;Drilling plan and synergistic efficiencies. Rarely are specific drilling plans disclosed publicly, but they can be observed at a high level in the reserve report, as well as certain expense assumptions that provide company specific expense profiles for operating and capital expenditures for new wells. NBL’s acquisition of CWEI ranks as a top E&P transactions of 2017, not only because it is one of the first transactions of the year, but compared to 2016, it ranks in the top five in size. Based upon our experience involving public and private companies, we understand that pricing for proven undeveloped, probable and possible reserves have dropped significantly in the previous year, by upwards of 90% in some cases. In addition, due to the nature of the current oil and gas environment, we understand that historical transactions may have little comparability to transactions today and any comparison depends upon the details and assumptions of each transaction. Mercer Capital has significant experience valuing assets and companies in the energy industry, primarily oil and gas, bio fuels and other minerals.  Our oil and gas valuations have been reviewed and relied on by buyers and sellers and Big 4 Auditors. These oil and gas related valuations have been utilized to support valuations for IRS Estate and Gift Tax, GAAP accounting, and litigation purposes. We have performed oil and gas valuations and associated oil and gas reserves domestically throughout the United States and in foreign countries. Contact a Mercer Capital professional today to discuss your valuation needs in confidence. End Notes1 Clayton Williams Energy, September 22, 2016 Johnson Rice Energy Conference Presentation 2 As of September 30, 2016 per S&P Capital IQ
2016 M&A Overview
2016 M&A Overview
When oil prices collapsed in mid-2014, the M&A market soon came to a standstill as investors waited for clarity regarding the future of the domestic oil and gas market.  The low price environment led to a disconnect between the value of oil and gas reserves and the price that buyers and sellers negotiated in a distressed market.  As prices remained low, deal volume picked up in the beginning of 2016 as companies were forced to sell assets in order to quickly generate cash to pay off debt and avoid bankruptcy.  As the year continued, M&A activity increased and total deal value at the end of 2016 doubled that of 2015.Factors Leading to Increased M&A activity in 2016Price stabilization of crude in the range of $45 to $54 played a role in the increase in M&A activity as investors regained confidence in the sector.Cost reduction in certain plays from new technology has allowed more cost-efficient drilling.The low price environment made distressed companies’ assets acquisition targets as these companies were willing to sell them for heavy discounts.In order to decrease break-even costs, companies merged to realize potential synergies.Recent discoveries and low break-even costs in the Permian Basin attracted investors and producers to the play and increased overall M&A deal volume.Price StabilizationCrude oil price volatility declined over the last year as excess supply began to decline.  Since mid-April of 2016, US crude oil inventories have declined by approximately 6%.   Additionally, OPEC production declined in the second quarter of 2016 and had slower-than-normal growth in the fourth quarter, which helped to reduce excess supply 1.Cost ReductionIn a stacked play, multiple horizontal wells can be drilled from one main wellbore.  This provides increased productivity as multilateral wells have greater drainage areas than single wellbore.  Additionally, it can reduce overall drilling risk and cost.  For deep reservoirs, a multilateral well eliminates the cost of drilling the total depth twice.  In some plays such as the Permian, the reservoir is deep enough at some points that operators can drill multiple horizontal wells from one main wellbore. This advancement of drilling technology has allowed producers in certain plays to reduce costs so that drilling in lower price environment is economically feasible.Only the Strong SurviveIn early 2016, banks decreased lending to oil and gas companies.  In a low price environment, the value of a company’s reserves falls when valued using a traditional PV-10 calculation. Lower valuations have led to decreased borrowing capacity, which in turn has caused cash flow pressure for many companies.  Thus many companies have had to sell non-core assets in order to ease cash flow pressures.  But in order to generate liquidity quickly, they often were forced to accept heavily discounted prices.  This increased deal volume in 2016 as many companies tried to avoid bankruptcy and buyers moved quickly to get their hands on cheap assets.Mergers for SynergiesAs companies worked to reduce break-even prices, many looked for strategic acquisition targets in hopes of realizing operational efficiencies which could reduce costs and give them a competitive advantage in the market.  This increased the number of mergers in 2016 in the E&P industry and also in the midstream sector which benefits from the network effect.The Permian BasinApproximately $69 billion dollars of North American E&P assets and companies changed ownership during 2016 with the Permian Basin resource accounting for nearly 40% of the deal dollar volume. The most significant trend in E&P this year was production companies’ move to the Permian Basin.  Out of the 15 deals that were valued at over $1 billion, 8 were in the Permian Basin.  The Permian became the center of the M&A stage due to its low drilling costs, resource diversity, and large remaining reserves.  Although the Permian was discovered in the 1920s, the true potential of the Permian was not realized until 2007 when hydraulic fracturing techniques were used to access the tight sand layers of the play. Since then the Permian has been revitalized as producers have begun using unconventional drilling techniques in addition to traditional vertical wells. Because the crude in the shale layers has only recently been explored, there are still tremendous reserves left.  Just this year the USGS announced an estimated 20 billion barrels of crude oil, 1.6 billion barrels of NGLs, and 16 trillion cubic feet of natural gas were discovered in four layers of shale in the Wolfcamp formation.  Additionally, the Permian is a stacked play—which means that companies can drill multi-lateral horizontal wells to reduce costs.  And, companies that operate in the Permian do not have to choose between oil and gas, but can diversify operations. Last week, we briefly looked at the six largest transactions in 2016.  Recent asset deals in the US are summarized below. Due to the factors discussed above, average deals in Permian transacted at higher dollar per-acre multiples than other plays such as the Williston Basin. When prices declined, production in the Permian continued increasing while production in other domestic plays such as the Bakken and the Eagle Ford declined significantly.  Unlike the Eagle Ford and the Bakken, which are mostly drilled for oil, the Permian holds a more diverse combination of oil, gas, and NGLs, making it more economical to produce at low prices. The Bakken was center stage in the early 2000s during the onset of hydraulic fracturing.  The Eagle Ford, which was once the most active shale plays in the world, was the center of the M&A market in 2013 and 2014 when drilling activities increased there.  M&A in the Eagle Ford and Bakken was sluggish in 2016, and the transactions that did occur there were largely motivated by distressed companies looking for liquidity or an exit. M&A OverviewM&A activity is expected to remain strong in 2017.  It is expected that OPEC will follow through on production cuts and excess inventory should be absorbed in early 2017.  This will cause the price of oil to continue increasing.   As the price of oil continues to rise, drilling in other plays besides the Permian Basin will begin to become more economical and M&A activity should increase in other plays.  However, it is expected that oil and gas companies will have to turn to private equity in order to gain liquidity as banks remain cautious in lending to the energy sector.End Note1 Data from Bloomberg
2016 Oil and Gas: A Year in Review
2016 Oil and Gas: A Year in Review
2016 was a year to remember and a year to forget for many in the oil and gas industry. On the positive side, energy commodity prices curbed their downward, volatile nature by finishing the year at higher prices than where they started. If this wasn’t enough good news, prices achieved this growth with relatively minimal volatility along the way. International and domestic supply are of particular importance as OPEC’s supply cuts and declining domestic supply helped bring a steady increase in the commodity prices. On the downside, many E&P companies were forced to restructure, through selling off assets or filing for bankruptcy, as a much need rebound in oil prices did not occur. The most popular area to snatch up assets was in the Permian Basin where approximately 40% of the North American deal volume occurred. This did not go unnoticed by many industry observers like Mercer Capital. Of our 31 Energy Valuation Insights posts from 2016, over 30% were related to the Permian Basin.Oil and Gas Commodity PricesAfter a volatile 2014 and shaky 2015, this past year brought about the feeling of stability in both natural gas and oil prices. For the year, WTI increased 43% and Henry Hub natural gas increased 58%. This was the first year-over-year increase in both WTI and Henry Hub since 2013, and prior to that 2007. The WTI to Brent crude spread averaged 3% during 2016, the lowest overall annual average since 2010 when the average was 0%. Factors related to the lower spread include a strong U.S. Dollar, and a full year of U.S. crude oil exports since the 40-year ban was lifted in December 2015. International Supply NewsInternational production decisions, especially those of OPEC, will continue to drive much of the change in oil price going forward. The primary supply factor for 2016 was the actions of OPEC and agreements to cut supply in an effort to stabilize the oil markets. Compounding the issues were OPEC members Iran and Libya which returned to production levels not seen in years due to the lifting of economic sanctions and stabilization of governments. Most recently, OPEC’s latest production cut agreements led to changes in trade. For example, Middle Eastern suppliers are working to keep their market share in Asia by keeping America and Africa’s trade confined to the Atlantic. OPEC in the past has been able to maintain market share by increasing production, driving prices down, and outlasting the competition.  In the commodities market, the flow of trade dictates supplier’s ability to take advantage of price gaps in certain areas.Domestic Supply NewsDomestically, production was mixed based upon reserve location and financial wellbeing of producers. Because drilling costs in the Permian are lower than many other plays in the U.S., when oil prices began to show signs of recovery, rig counts in the Permian picked up faster than in any other domestic play.  Producers were eager to begin operating after two years of an uneconomical drilling environment, and for many producers, the Permian was the first play in which the cost of oil rose above breakeven costs. Additionally, the Export Ban lifted at the beginning of the year provided more avenues for producers to sell crude.Domestic reserve estimates increased significantly this year as the USGS announced an estimated 20 billion barrels of crude oil, 1.6 billion barrels of NGLs, and 16 trillion cubic feet of natural gas were discovered in four layers of shale in the Wolfcamp formation.  This discovery alone is 3x larger than the entire Bakken play in North Dakota, and equates an estimated $900 billion of oil.BankruptciesAs anticipated, many E&P operators and servicers needed a sharp increase in oil prices to avoid restructuring or filing for bankruptcy during 2016. As the sharp increase in oil prices did not occur, tough decisions were made during the year. As mentioned in our July 2016 post, there were four types of energy companies operating in 2016:The “I need to restructure yesterday” company;The “In denial about restructuring” company;The “Racing to restructure” company (to be healthier when oil prices recover); andThe “Low leverage / healthy” company (looking for opportunities); Three of the above types are characterized as being in a motivated seller position. Midway through the year, industry analysts noted over 100 oil and gas companies have filed for bankruptcy with an estimate that we may only be half way done. By the end of the year, “more than 220 upstream and oilfield service companies have declared bankruptcy since the start of the downturn in 2014.” While this is a significant number of bankrupt companies, the higher oil price may give reason to have a positive outlook for 2017. Additionally, 2016 provided significant acquisition opportunities for those companies looking for strategic purchases.TransactionsCrude oil price stability and financially weak E&P companies resulted in an increase in sellers, voluntary or involuntary, which created a relatively robust merger and acquisition market. In comparison to the last ten years, 2016 was the 4th highest year for number of deals. Approximately $69 billion dollars of North American E&P assets and companies changed ownership during 2016 with the Permian Basin resource accounting for nearly 40% of the deal dollar volume. The Marcellus/Utica and Scoop/Stack were a distant 2nd and 3rd, respectively accounting for $6.7 billion and $5.1 billion in deal value. The top six deals during 2016 in terms of dollar value are listed in the chart below. While the top three transactions were scattered throughout North America, the next three involved companies with core assets in the Permian Basin. The largest deals in 2016 are summarized below. Largest North American Deal in 2016: Suncor Energy purchases Canadian Oil Sands2nd Largest North American Deal In 2016: Range Resources purchases Memorial Resources3rd Largest North American Deal In 2016: Rice Energy purchases Vantage Energy4th Largest North American Deal In 2016: Diamondback purchases Brigham Resources5th Largest North American Deal In 2016: RSP Permian purchases Silver-Hill Energy. We explored an allocation of purchase price for this transaction in an earlier post.6th Largest North American Deal In 2016: EOG purchases Yates Petroleum: Refer Here for more information. We explored an allocation of purchase price for this transaction in an earlier post.Outlook for 2017The impacts of the oil and gas downturn will continue into 2017 and likely past that.  While OPECs decision to cut production should help supply and demand rebalance and prices to continue recovering, the path to recovery is likely to be slow. There are reasons to expect improvement in the oil and gas market in 2017, but many producers are hesitant to be too optimist.Mercer Capital has significant experience valuing assets and companies in the energy industry, primarily oil and gas, bio fuels and other minerals.  Our oil and gas valuations have been reviewed and relied on by buyers and sellers and Big 4 Auditors. These oil and gas related valuations have been utilized to support valuations for IRS Estate and Gift Tax, GAAP accounting, and litigation purposes. We have performed oil and gas valuations and associated oil and gas reserves domestically throughout the United States and in foreign countries. Contact a Mercer Capital professional today to discuss your valuation needs in confidence.
Quick Facts: Bakken
Quick Facts: Bakken
Each quarter, Mercer Capital’s Exploration & Production Industry newsletter provides an overview of the E&P sector, including world demand and supply, public market performance, valuation multiples for public companies, and a region focus.  Mercer Capital closely follows oil and gas trends in the Permian Basin, Eagle Ford Shale, Bakken Shale, and Marcellus and Utica Shale.  Last quarter our E&P newsletter, focused on the Bakken Shale.  Today, we take a step back and review the broad characteristics of the Bakken Shale. Download this information in a convenient PDF at the bottom of this post.Bakken at a GlanceFirst Discovered1951Discovery as Viable Play2000Primary ProductionOilOil TypeSweet, Light CrudePlayUnconventional ShaleDrillingHorizontal, Multi-Stage Hydraulic FracturingTop 3 Production CompaniesContinental, Whiting, HessBreakeven$29 – $77 per barrel 1Abnormal DUCs526 2Production Since 20072,517 MMBOE 3IssuesCost of Extraction & Cost of TransportationPotentialImproving Technology, Dakota Access Pipeline Project, and Large, Undiscovered Quantities of Oil & Gas1 North Dakota Dept. of Mineral Reserves Sept. 2015 county-level estimates 2 Drilled Uncompleted Wells with > 3 months in inventory as of January 2016; also referred to as fraclog (Bloomberg Intelligence) 3 EIA as of June 2016OverviewAt 14,700 sq. miles, the Bakken and associated Three Forks formation is the largest continuous crude oil source in the U.S. Discovered in 1951, it remained largely unproductive until 2000 when technological advances such as hydraulic fracturing and horizontal drilling enabled economically viable production of its sizable reserves.The region has struggled recently due to falling oil prices.Geography & DrillingThe Bakken is primarily an oil producing region. It is made up of three layers: top and bottom shale layers, and a siltstone and sandstone middle member. The two shale layers function as source rock that traps oil in the middle member. Even this middle member, however, has low permeability and low porosity, making this a tight, unconventional play. Multi-stage hydraulic fracturing and horizontal drilling are used to extract oil, and pad drilling is commonly used to enhance efficiency. Underlying the Bakken shale layers is a more extensive, thicker shale play called the Three Forks. This layer is accessed using the same unconventional techniques, and is estimated to hold a little over half the undiscovered, recoverable resources of the total Bakken/Three Forks petroleum system.Issues & Future PotentialLimited shipping options from the Upper Midwest create high transportation costs in the play. In combination with the low price of oil and the use of advanced drilling techniques, this lack of transportation pushes the cost of production above the realized wellhead price for most wells in the play. Looking to the future, the Bakken will benefit from new pipelines, continued technological improvements, the likelihood of eventual increases in oil prices, and the formation’s large remaining quantities of oil and gas.Bakken ProductionUndiscovered, Recoverable Resources in BakkenResource Estimate*Oil7,383 MMBNatural Gas6,726  BCFLiquid Natural Gas527 MMB*Mean estimates in the 2013 USGS report.AVAILABLE RESOURCEQuick Facts: BakkenDownload this information in a convenient, one-page PDF. Download
Refining 2017 Issue I
Refining | 2017 Issue I
Despite profit margin improvement since the start of 2017, the high cost of RINs led to an increase in operating expenses which more than offset the decrease in cost of goods sold.
EP First Quarter 2017 Region Focus Eagle Ford
E&P First Quarter 2017

Region Focus: Eagle Ford

Region Focus: Eagle Ford Oil prices increased over the last twelve months from $38/bbl at March 31, 2016 to $50/bbl at the end of the first quarter 2017.
EP Second Quarter 2017 Region Focus Permian Basin
E&P Second Quarter 2017

Region Focus: Permian Basin

Region Focus: Permian Basin: Although oil prices have increased over the last 12 months, they fell over the second quarter from $50.54/bbl to $46.02/bbl on June 30, 2017.
Renewable Fuel Standards and Refiners
Renewable Fuel Standards and Refiners
The Renewable Fuel Standards (RFS) program, which originated from the Energy Policy act of 2005, set a goal to use 36 billion gallons of renewable fuels by 2022. RFS was signed into law by President George W. Bush in order to reduce greenhouse gas emissions and boost rural farm economies.  Each November, the EPA issues rules increasing Renewable Fuel Volume Targets for the next year.  The following table shows the Renewable Fuel Volume requirements for the past three years and the targets for 2017. Separate quotas and blending requirements are determined for cellulosic biofuels, biomass-based diesel, advanced biofuels, and total renewable fuel.  The individual obligations for producers are called Renewable Volume Obligations (RVO). Refiners and importers of gasoline and diesel fuel must meet Renewable Volume Obligations (RVOs) by blending ethanol and biodiesel into gasoline and diesel fuel.  An RVO is determined by multiplying the output of the producer by the EPA's announced blending ratios for each of the four standards described above. RINs (Renewable Identification Numbers) are 38-digit numbers used to implement the Renewable Fuel Standards.  RBN Energy describes RINs as the “Currency of the […] RFS program”.  The EPA explains that when a producer makes one gallon of renewable fuel, RINs are generated.  At the end of the year, producers and importers use RINs to demonstrate their compliance with the RFS.  Refiners and producers without blending capabilities can either purchase renewable fuels with RINs attached or they can purchase RINs through the EPA's Moderated Transaction System.  RINs can be carried over from one compliance year to another, if unused. On the other hand, a RIN deficit can be carried over into the next year but must be made up for during the following year. While integrated refiners blend their petroleum products with renewable fuels, merchant refiners do not have the capability to blend their own petroleum products. Tesoro Corp., an integrated refiner, is not affected by RIN costs.  Steven Sterin, EVP & CFO explained in their third quarter earnings call, “in a quarter where RIN costs rise, we reflect the higher obligation in refining and the benefit from blending in our marketing segment. It's important to know that we run our business in the integrated manner. This does not have a material impact on total Company results.”  But he did acknowledge that gasoline blending is where the true benefit of integration is realized.  Even Tesoro faces challenges acquiring cellulosic and biodiesel RINs. Merchant refiners are required to obtain RINs for RFS compliance purposes.  A common theme across refiners’ earnings calls last quarter was the effect of the rising cost of RINs on already squeezed margins.  Holly Frontier, a merchant refiner, spent $63 million on RINs, in the third quarter alone.  Holly Frontier’s President and CEO, George Damiris, said in their third quarter earnings call that they have considered expanding into fuel marketing because of the current RINs environment. The increase in RIN costs is at the simplest, an issue of supply and demand.  Production targets that are greater than equilibrium supply and demand cause price increases to correct the shortage of goods.   As Renewable Fuel Volume targets have increased year over year, the price of RINs continue increasing. Reuters quoted that on average Renewable fuel credits saw a 25% increase in price from 2Q 2015 to 2Q 2016. What’s Next?President-elect Trump voiced a pro-ethanol platform when visiting America’s farm states implying that he would keep increasing RFS targets.  However, he is also known to be pro-oil and many oil groups have called for changes or the repeal of the RFS program which is known to hurt independent refiners.President-elect Trump has nominated Exxon CEO, Rex Tillerson, as Secretary of State and former Texas Governor, Rick Perry, for Secretary of Energy.  Additionally, many more cabinet positions are stacked with oil and gas supporters such as Montana Republican Ryan Zinke, who was nominated to the Department of the Interior, and Oklahoma Attorney General and EPA critic Scott Pruit, who was nominated to head the EPA.Trump’s nominations suggest that the upcoming presidential term will provide a friendly oil and gas environment.   While it is unclear what the President-elect’s plan is for the RFS program, it is likely that he will face challenges balancing farm and oil interests.
Exploration & Production 3Q16 Newsletter | Region Focus: Bakken
Exploration & Production 3Q16 Newsletter | Region Focus: Bakken
Each quarter, Mercer Capital’s Exploration & Production Industry newsletter provides an overview of the E&P sector, including world demand and supply, public market performance, valuation multiples for public companies, and a region focus. This quarter we focus on the Bakken Shale.Excerpting from the third quarter newsletter:Oil prices trended up for the beginning of the third quarter but ended the quarter about where they started. For the last two years companies have postponed exploration activities and cut capital projects to drill new wells. Now that oil prices show signs of recovery, production has increased across the U.S. Although oil prices have increased slightly, oil and gas bankruptcies continued in the third quarter as 52 companies filed for bankruptcy. The majority filed for Chapter 11 protection in hopes to reorganize. Many of the firms that went bankrupt were smaller companies who had less flexibility to exchange debt or draw a second-lien. The price of crude oil is determined by market forces: supply and demand. In order to understand the current pricing environment, we analyze these metrics on pages 1 and 2 of the newsletter.View the newsletter below or download the PDF.
Royalty Interests Discover the Permian
Royalty Interests Discover the Permian
In August 2016, we discussed bankruptcy and valuation issues related to royalty interest owners. We mentioned using the publicly traded market as one method to value royalty interests, specifically observing royalty trusts. As a primer for O&G royalty trusts, these trusts hold various royalty and net profit interests in wells operated by large exploration & production companies. These trusts have little in the way of operating expenses, have defined termination dates and can serve as an investment opportunity that provides exposure to oil and gas prices. This Motley Fool article, from 2014, explains the pros and cons of investing in this sort of vehicle.Market indications are available in the form of publicly traded oil & gas (“O&G”) royalty trusts. There are approximately 20 oil and gas focused royalty trusts publicly traded, as of the date of this article.1Market ObservationsRoyalty trusts, like the rest of the oil and gas industry, have been hit hard over the previous 29 months. Before the bottom fell out, oil traded as high as $106.86 in June of 2014 and plunged to a low of $29.05 in February of 2016. Since February, the price of oil appears to have found a new home around $50 / barrel. Here is a comparison of the 20 publicly traded royalty trusts’ metrics today versus one year ago.Observations and Disclaimers:Price to revenue and price to distributable income indicate, on average, the trusts are more expensive now than a year ago. This is a flip from our August 2016 blog post when multiples were lower in July 2016 than July 2015.Yields were higher last year as trailing yields did not reflect the quickly falling market price.As of today, market prices have leveled off and annual distributions are comprised of a full year of lower royalty payments, resulting in lower yields compared to a year ago.Price to PV 10 is higher this year compared to last. The remaining observations are for commodity prices, both current and futures price for the 12 month contract.Disclaimer: no two of the above royalty trusts are alike. Differences abound in asset mix, asset location, term, and resource mix, just to name a few. In future blog posts, we will explore each trust individually and discuss their uniqueness. Below is a chart of the market price performance for each royalty trust over the last two years. The above chart looks very similar to the performance of the price of oil and gas over the same time period. Royalty interest owners have seen their monthly payments move in the same manner, and possibly have not experienced the small rebound during 2016. Uncertainty is high as some operators have been forced to file bankruptcy after commodity prices have remained low for too long for them to survive. Three of the above 20 royalty trusts are tied to SandRidge Energy. In May 2016, SandRidge Filed for Bankruptcy Reorganization and Emerged from Bankruptcy in October 2016. During this time, the three royalty trusts: (1) SandRidge Mississippian Trust 12, (2) SandRidge Mississippian Trust II3 and (3) SandRidge Permian Trust4 experienced the following performance: The popularity of the Permian Basin is nothing new this year. In oil and gas, location is key when trying to generate returns on invested capital. Even as the price of oil is near three year lows, transaction activity is high in this area of the country.  Royalty Trusts appear to support the trend to try to get a piece of the very hot Permian Basin. Add on the reserve discovery in the Wolfcamp formation by the United States Geological Survey last month and it is clear that there is no other place to be drilling for oil right now. This attention appears to have spread into the royalty trusts. As the publicly traded price indicates, after SandRidge Energy files for bankruptcy, albeit “pre-arranged reorganization,” each of the three related royalty trusts decline. The price of the two trusts which do not own properties in the Permian Basin decline more than 20% initially after the bankruptcy filing while the SandRidge Permian Trust’s price declines only 6%.  Upon emergence from bankruptcy, the trust with Permian related assets was up 11% while the two non-Permian related trusts were down more than 35%. Depending on your situation, the current pricing environment may provide excellent planning opportunities as market prices are relatively low. With the Treasury Department attempting to change the way gift and estate planning can be performed, it is even more timely to execute a transfer plan.  Contact Mercer Capital to discuss your needs in confidence and learn more about how we can help you succeed. End Notes1 Data for charts and tables for this post are from Capital IQ 2 The Trust holds Royalty Interests in specified oil and natural gas properties located in the Mississippian formation in Alfalfa, Garfield, Grant and Woods counties in Oklahoma. (respective 10-K, March 2016) 3 The Trust holds Royalty Interests in specified oil and natural gas properties located in the Mississippian formation in Alfalfa, Grant, Kay, Noble and Woods counties in northern Oklahoma and Barber, Comanche, Harper and Sumner counties in southern Kansas. (respective 10-K, March 2016) 4 The Trust holds Royalty Interests in specified oil and natural gas properties in the Permian Basin located in Andrews County, Texas. (respective 10-K, March 2016)
An Introduction to Dividends and Dividend Policy for Private Companies
An Introduction to Dividends and Dividend Policy for Private Companies
As the calendar year draws to a close, many private companies consider the issue of dividends and dividend policy.  Originally published in Unlocking Private Company Wealth,  Z. Christopher Mercer, ASA, CFA, ABAR provides an introduction to dividends and dividend policy.  He begins with the obvious observation that no matter how informal, your company has a dividend policy. Reprinted with permission. The issue of dividends and dividend policy is of great significance to owners of closely held and family businesses and deserves considered attention. Fortunately, I had an early introduction to dividend policy beginning with a call from a client back in the 1980s. I had been valuing a family business, Plumley Rubber Company, founded by Mr. Harold Plumley, for a number of years. One day in the latter 1980s, Mr. Plumley called me and asked me to help him establish a formal dividend policy for his company, which was owned by himself and his four sons, all of whom worked in the business. Normally I do not divulge the names of clients, but my association with the Plumley family and Plumley Companies (its later name) was made public in 1996 when Michael Plumley, oldest son of the founder and then President of the company, spoke at the 1996 International Business Valuation Conference of the American Society of Appraisers held in Memphis, Tennessee. He told the story of Plumley Companies and was kind enough to share a portion of my involvement with them over nearly 20 years at that point. Let’s put dividends into perspective, beginning with a discussion of (net) earnings and (net) cash flow. These are two very important concepts for any discussion about dividends and dividend policy for closely held and family businesses. To simplify, I’ll often drop the (net) when discussion earnings and cash flow, but you will see that this little word is important.(Net) Earnings of a BusinessThe earnings of a business can be expressed by the simple equation:Earnings = Total Revenue – Total CostCosts include all the operating costs of a business, including taxes.C Corporations. If your corporation is a C corporation, it will pay taxes on its earnings and earnings will be net of taxes. The line on the income statement is that of net income, or the income remaining after all expenses, including taxes, both state and federal, have been paid. By the way, if your company is a C corporation, feel free to give me a call to start a conversation about this decision.S Corporations and LLCs. If your corporation is an S corporation or an LLC (limited liability company), the company will make a distribution so that its owners can pay their pass-through taxes on the income. To get to the equivalent point of net income on a C corporation’s income statement, it is necessary to go to the line called net income (but it is not) and to subtract the total amount of distributions paid to owners for them to pay the state and federal income taxes they owe on the company’s (i.e., their pass through) earnings. This amount would come from the cash flow statement or the statement of changes in retained earnings. Ignoring any differences in tax rates, the net income, after taxes (corporate or personal) should be about the same for C corporations and pass-through entities.(Net) Cash FlowCompanies have non-cash charges like depreciation and amortization related to fixed assets and intangible assets. They also have cash charges for things that don’t flow through the income statement. Capital expenditures for plant and equipment, buildings, computers and other fixed assets are netted against depreciation and amortization, and the result is either positive or negative in a given year. Capital expenditures tend to be "lumpy" while the related depreciation expenses are amortized over a period of years, often causing swings in the net of the two.There are other "expenses" and "income" of businesses that do not flow through the income statement. These investments, either positive or negative, relate to the working capital of a business. Working capital assets include inventories and accounts receivable, and working capital liabilities include accounts payable and other short-term obligations. Changes in working capital can lead to a range of outcomes for a business. Consider these two extremes that could occur regarding cash in a given year:Make lots of money but have no cash. Rapidly growing companies may find that while they have positive earnings, they have no cash left at the end of the month or year. They have to finance their rapid growth by leaving all or more than all of earnings in the business in the form of working capital to finance investments in accounts receivable and/or inventories and in the purchase of fixed assets to support that growth.Make little money, even have losses, and generate cash. Companies that experience sales declines may earn little, or even lose money on the income statement, and still generate lots of cash because they collect prior receivables or convert previously accumulated inventories into cash during the slowdown. Working capital on the balance sheet is the difference between current assets and current liabilities. Many companies have short-term lines of credit with which they finance working capital investments. The concept of working capital, then, may include changes in short-term debt. In addition, companies generate cash by borrowing funds on a longer-term basis, for example, to finance lumpy capital expenditures. In the course of a year, a company may be a net borrower of long-term debt or be in a position of paying down its long-term debt. So we’ll need to consider the net change in long-term debt if we want to understand what happens to cash in a business during a given year. We are developing a concept of (net) cash flow, which can be defined as follows in Figure 11.Most financial analysts and bankers will agree that this is a pretty good definition of Net Cash Flow.Net Cash Flow is the Source of Good ThingsWe focus on cash flow because it is the source of all good things that come from a business. The current year’s cash flow for a business is, for example, the source of:Long-term debt repayment. Paying debt is good. Bankers are extremely focused on cash flow, because they only want to lend long-term funds to businesses that have the expectation of sufficient cash flow to repay the debt, including principal and interest on the scheduled basis. Interest expense has already been paid when we look at net cash flow. Companies borrow on a long-term basis to finance a number of things like land, buildings and equipment, software and hardware, and many other productive assets that may be difficult to finance currently. They may also borrow on a long term basis to finance stock repurchases or special dividends.Reinvestment for future growth. Investment in a business is good if adequate returns are available. If a company generates positive cash flow in a given year, it is available to reinvest in the business to finance its future growth. Reinvested earnings are a critical source of investment capital for closely held and private companies Reinvesting with the expectation of future growth (in dividends and capital gains) is an important source of shareholder returns, but the return is deferred, at least in the form of cash, until a future date.Dividends or distributions. Corporate dividends are also good, particularly if you are a recipient. Cash flow is also the normal source for dividends (for C corporation owners) or what we call “economic distributions,” or distributions net of shareholder pass-through taxes (for S corporation and LLC owners).What is a Dividend?At its simplest, a dividend (or economic distribution) reflects the portion of earnings not reinvested in a business in a given year, but paid out to owners in the form of current returns.For some or many closely held and family businesses, effective dividends can include another component, and that is the amount of any discretionary expenses that likely would be “normalized” if they were to be sold. Discretionary expenses include:Above-market compensation for owner-managers. Owners of some private businesses who compensate themselves and/or family members at above-market rates should realize that the above-market portion of such compensation is an effective dividend.Mystery employees on the payroll. Some companies place non-working spouses, children or other relatives on the payroll when no work is required of them.Expenses associated with non-operating assets used for owners’ personal benefit. Non-operating assets can include company-owned vacation homes, aircraft not necessary for the operation of the business, vehicles operated by non-working family members, and others. It is essential to analyze above-market compensation and other discretionary expenses from owners’ viewpoints to ascertain the real rate of return that is obtained from investments in private businesses. In an earlier chapter, we touched on the concept of the rate of return on investment for a closely held business. Assuming that there were no realized capital gains from a business during a given year, the annual return (AR) is measured as follows:Now, we add to this any discretionary expenses that are above market or not normal operating expenses of the business that are taken out by owners:We now know what dividends are, and they include discretionary benefits that will likely be ceased and normalized into earnings in the event of a sale.We won’t focus on discretionary benefits in the continuing discussion of dividends and dividend policy. However, it is important for business owners to understand that, to the extent discretionary benefits exist, they reflect portions of their returns on investments in their businesses.In summary, dividends are current returns to the owners of a business. Dividends are normally residual payments to owners after all other necessary debt obligations have been paid and all desirable reinvestments in the business have been made.Dividends and Dividend Policy for Private CompaniesWith the above introduction to dividends for private companies, we can now talk about dividend policy. The remainder of this chapter focuses on seven critical things for consideration as you think about your company’s dividend policy.Every company has a dividend policy.Dividend policy influences return on business investment.Dividend policy is a starting point for portfolio diversification.Special dividends enhance personal liquidity and diversification.Dividend policy does matter for private companies.Dividend policy focuses management attention on financial performance.Boards of directors need to establish thoughtful dividend policies. We now focus on each of these seven factors you need to know about your company’s dividend policy.Every Company Has a Dividend PolicyLet’s begin with the obvious observation that your company has a dividend policy. It may not be a formal policy, but you have one. Every year, every company earns money (or not) and generates cash flow (or not). Assume for the moment that a company generates positive earnings as we defined the term above. If you think about it, there are only three things that can be done with the earnings of a business:Reinvest the earnings in the business, either in the form of working capital, plant and equipment, software and computers, and the like, or even excess or surplus assets.Pay down debt.Pay dividends to owners (or economic distributions – after pass-through taxes – for S corporations and LLCs) or repurchase stock (another form of returns to shareholders). That’s it. Those are all the choices. Every business will do one or more of these things with its earnings each year. If a business generates excess cash and reinvests in CDs, or accumulates other non-operating assets, it is reinvesting in the business, although likely not at an optimal rate of return on the reinvestment. Even if your business does not pay a dividend to you and your fellow owners, you have a dividend policy and your dividend payout ratio is 0% of earnings. On the other hand, if your business generates substantial cash flow and does not require significant reinvestment to grow, it may be possible to have a dividend policy of paying out 90% or even up to 100% of earnings in most years. This is often the case in non capital intensive service businesses. Recall that if a business pays discretionary benefits to its owners that are above market rates of compensation, or if it pays significant expenses that are personal to the owners, it is the economic equivalent of paying a dividend to owners. So when talking to business owners where such expenses are significant, we remind them that they are, indeed, paying dividends and should be aware of that fact. Some may think that discretionary expenses are the provenance of only small businesses; however, they exist in many businesses of substantial size, even into the hundreds of millions in value. Discretionary expenses are not necessarily bad, but they can create issues. In companies with more than one shareholder, discretionary expenses create the potential for (un)fairness issues. However, discretionary expenses are paid for the benefit of one shareholder or group of shareholders and not for others, they are still a return to some shareholders. Every company, including yours, has a dividend policy. Is it the right policy for your company and its owners?Dividend Policy Influences Return on Business InvestmentTo see the relationship between dividend policy and return on investment we can examine a couple of equations. This brief discussion is based on a lengthier discussion in my book, Business Valuation: An Integrated Theory Second Edition (John Wiley & Sons, 2007). There is a basic valuation equation, referred to as the Gordon Model. This model states that the price (P0) of a security is its expected dividend (D1) capitalized at its discount rate (R) minus its expected long term growth rate in the dividend (Gd). This model is expressed as follows:D1 is equal to Earnings times the portion of earnings paid out, or the dividend payout ratio (DPO), so we can rewrite the basic equation as follows:What this equation says is that the more that a company pays out in dividends, the less rapidly it will be able to grow, because Gd, or the growth rate in the dividend, is actually the expected growth rate of earnings based on the relevant dividend policy.We can look at this simplistically in word equations as follows:Dividend Income + Capital Gains = Total ReturnDividend Yield + Growth (Appreciation) = Cost of Equity (or the discount rate, R)These equations reflect basic corporate finance principles that pertain, not only to public companies, but to private businesses as well. There is an important assumption in all of the above equations – cash flow not paid out in dividends is reinvested in the business at its discount rate, R.There are many examples of successful private companies that do not pay dividends, even in the face of unfavorable reinvestment opportunities. To the extent that dividends are not paid and earnings are reinvested in low-yielding assets, the accumulation of excess assets will tend to dampen the return on equity and investment returns for all shareholders.Further, the accumulation of excess assets dampens the relative valuation of companies, because return on equity (ROE) is an important driver of value. For example, consider the following relationship without proof:ROE x Price/Earnings Multiple = Price/Book ValueAt a given multiple of (net) earnings available in the marketplace, a company’s ROE will determine its price/book value multiple. The price/book value multiple tells how valuable a company is in relationship to its book value, or the depreciated cost value of its shareholders’ investments in the business.Let’s consider a simple example. Assume that a company generates an ROE of 10% and that the relevant market price/earnings multiple (P/E) is 10x. Using the formula above:In this example, the company would be valued at its book value and the shareholders would not benefit from any “goodwill,” or value in excess of book value. Consider, however, that a similar company earns an ROE of 15%.Assuming the same P/E of 10x, it would be valued at 150% of its book value.Suppose the second company, because of its superior returns, received a P/E of 11x. In that case the price/book multiple would be 165%. To the extent that a company’s dividend policy influences its ongoing ROE, it influences its relative value in the marketplace and the ongoing returns its shareholders receive. In short, your dividend policy influences your return on investment in your business, as well as your current returns from that investment.Dividend Policy is a Starting Point for Portfolio DiversificationRecall the story of my being asked to help develop a dividend policy for a private company. The company had grown rapidly for a number of years and its growth and diversification opportunities in the auto parts supply business were not as attractive as they had been. The CEO, who was the majority shareholder, realized this and also that his sons (his fellow shareholders) could benefit from a current return on their investments in the company, which, collectively, were significant.We reviewed the dividend policies of all of the public companies that we believed to be reasonably comparable to the company. I don’t recall the exact numbers now, but I believe that the average dividend yield for the public companies was in the range of 3%. As I analyzed the private company, it was clear that it was still growing somewhat faster than the publics, so the ultimate recommendation for a dividend was about 1.5% of value.The value that the 1.5% dividend yield was compared to was the independent appraisal that we prepared each year. Based on the value at the time, I recall that the annual dividend began at something on the order of $300,000 per year. But, for the father and the sons, it was a beginning point for diversification of their portfolios away from total concentration in their successful private business.Your dividend policy can be the starting point for wealth diversification, or it can enhance the diversification process if it is already underway.Special Dividends Enhance Personal Liquidity and DiversificationA number of years ago, I was an adviser to a publicly traded bank holding company. Because of past anemic dividends, this bank had accumulated several million dollars of excess capital. The stock was very thinly traded and the market price was quite low, reflecting a very low ROE (remember the discussion above).Because of the very thin market for shares, a stock repurchase program was not considered workable. After some analysis, I recommended that the board of directors approve a large, one-time special dividend. At the same time I suggested they approve a small increase in the ongoing quarterly dividend. Both of these recommendations provided shareholders with liquidity and the opportunity to diversify their holdings.Since the board of directors collectively held a large portion of the stock, the discussion of liquidity and diversification opportunities while maintaining their relative ownership position in the bank was attractive.At the final board meeting before the transaction, one of the directors did a little bit of math. He noted that if they paid out a large special dividend, the bank would lose earnings on those millions and earnings would decline. I agreed with his math, but pointed out (calculations already in the board package) that the assets being liquidated were very low in yield and that earnings (and earnings per share) would not decline much. With equity being reduced by a larger percentage, the bank’s ROE should increase. So that increase in ROE, given a steady P/E multiple in the marketplace, should increase the bank’s Price/Book Value multiple.The director put me on the spot. He asked point blank: "What will happen to the stock price?" I told him that I didn’t know for sure (does one ever?) but that it should increase somewhat and, if the markets believed that they would operate similarly in the future, it could increase a good bit. The stock price increased more than 20% following the special dividend.Special dividends, to the extent that your company has excess assets, can enhance personal liquidity and diversification. They can also help increase ongoing shareholder returns. I have always been against retaining significant excess assets on company balance sheets because of their negative effect on shareholder returns and their adverse psychological impact. It is too easy for management to get "comfortable" with a bloated balance sheet.If your business has excess assets, consider paying a special dividend. Your shareholders will appreciate it.Dividend Policy Does Matter for Private CompaniesSomeone once said that earnings are a matter of opinion, but dividends are a matter of fact. What we know is that when dividends are paid, the owners of companies enjoy their benefit, pay their taxes, and make individual choices regarding their reinvestment or consumption.The total return from an investment in a business equals its dividend yield plus appreciation (assuming no capital gains), relative to beginning value. However, unlike unrealized appreciation, returns from dividends are current and bankable. They reduce the uncertainty of achieving returns. Further, if a company’s growth has slowed because of relatively few good reinvestment opportunities, a healthy dividend policy can help assure continuing favorable returns overall.Based on many years of working with closely held businesses, we have observed that companies that do not pay dividends and, instead, accumulate excess assets, tend to have lower returns over time. There is, however, a more insidious issue. The management of companies that maintain lots of excess assets may tend to get lazy-minded. Worse, however, is the opposite tendency. With lots of cash on hand, it is too easy to feel pressure to make a large and perhaps unwise investment, e.g., an acquisition, that will not only consume the excess cash but detract from returns in the remainder of the business.Dividend policy is the throttle by which well-run companies gauge their speed of reinvestment. If investment opportunities abound, then a no- or low-dividend payout may be appropriate. However, if reinvestment opportunities are slim, then a heavy dividend payout may be entirely appropriate.Any way you cut it, dividend policy does matter for private companies.Dividend Policy Focuses Management Attention on Financial PerformanceBoards of directors are generally cautious with dividends and once regular dividends are being paid, are reluctant to cut them. The need, based on declared policy, to pay out, say, 35% of earnings in the form of shareholder dividends (example only) will focus management’s attention on generating sufficient earnings and cash flow each year to pay the dividend and to make necessary reinvestments in the business to keep it growing.No management (even if it is you) wants to have to tell a board of directors (even if you are on it) or shareholder group that the dividend may need to be reduced or eliminated because of poor financial performance.Boards of Directors Need to Establish Thoughtful Dividend PoliciesIf dividend policy is the throttle with which to manage cash flow not needed for reinvestment in a business, it makes sense to handle that throttle carefully and thoughtfully. Returns to shareholders can come in the form of dividends or in the form of share repurchases.While a share repurchase is not a cash dividend, it does provide cash to selling shareholders and offsetting benefits to remaining shareholders. Chapter 10 of the book (Leveraged Share Repurchase: An Illustrative Example) provides an example of a substantial leveraged share repurchase from a controlling shareholder to provide liquidity and diversification.From a theoretical and practical standpoint, the primary reason to withhold available dividends today is to reinvest to be able to provide larger future dividends – and larger in present value terms today. It is not a good dividend policy to withhold dividends for reasons like the following:A patriarch withholds dividends to prevent the second (or third or more) generations from being able to have access to funds.A control group chooses to defer dividends to avoid making distributions to certain minority shareholders.Dividends are not paid because management (and the board) want to build a large nest egg against possible future adversities.Dividends are not paid to accumulate excess or non-operating assets on the balance sheet for personal or vanity reasons.Dividend policy is important and your board of directors needs to establish a thoughtful dividend policy for your business.ConclusionDividends and dividend policies are important for the owners of closely held and family businesses. Dividends can provide a source of liquidity and diversification for owners of private companies. Dividend policy can also have an impact on the way that management focuses on financial performance.To discuss corporate valuation or transaction advisory issues in confidence, please contact us.
The Permian Basin: Loaves and Fishes
The Permian Basin: Loaves and Fishes
One of the most commonly taught Bible stories is the miracle of Jesus feeding five thousand people with only five loaves of bread and two fish.  Last week we learned of a new miracle story of never ending sustenance.  The Permian Basin, which has been drilled since the 1920s and produced billions of barrels of oil, was discovered to hold the largest unconventional crude accumulation in the US.Less than 10 years ago, the United States Geological Survey (USGS) estimated that the Permian Basin held just 1.0 billion barrels of conventional oil and 1.3 billion barrels of unconventional oil classified as technically recoverable reserves.1 The advancement of horizontal drilling techniques, however, increased the amount of recoverable reserves.  Now, according to the Texas Rail Road commission, over 29 billion barrels of oil and 75 trillion cubic feet of gas have been produced from the Permian over the last 90 years.  Further, last Tuesday, the USGS announced an estimated 20 billion barrels of crude oil, 1.6 billion barrels of NGLs, and 16 trillion cubic feet of natural gas were discovered in four layers of shale in the Wolfcamp formation.  This discovery alone is 3x larger than the entire Bakken play in North Dakota, and equates an estimated $900 billion of oil. The Wolfcamp Shale has been a recent target of E&P companies in the face of two years of low oil prices.  The Wolfcamp is an oil and gas zone located below the Spraberry oil play in the Midland Basin.  The Spraberry oil play has been developed since 1943 but the Wolfcamp was not developed until the onset of horizontal drilling.  Companies saw opportunity in the Wolfcamp shale because of its depth and geological makeup.  The Permian Basin is a stacked play which means that multiple horizontal wells can be drilled from one main wellbore.  This provides increased productivity as multilateral wells have greater drainage areas than single wellbore.  Additionally, it can reduce overall drilling risk and cost.  For deep reservoirs like the Permian, a multilateral well eliminates the cost of drilling the total depth twice.  The Wolfcamp is as much as a mile deep at some points which means that operators can drill multiple horizontal wells from one main wellbore. M&A activity in the E&P sector has picked up this year due to the opportunity seen in the Permian. There have been 132 deals in the Permian this year so far, totaling $20.8 billion in deal value, which is more than 40% of total E&P deal value generated throughout the US.  Much of this activity has been focused in the Midland Basin. Because drilling costs in the Permian are lower than many other plays in the US, when oil prices began to show signs of recovery, rig counts in the Permian picked up faster than in any other domestic play.  Producers were eager to begin operating after two years of an uneconomical drilling environment, and for many producers the Permian was the first play in which the cost of oil rose above breakeven costs. The chart below shows the combined rig counts of oil and gas rigs in various domestic plays. What Does This Mean?Business Insider associates some of the collapse of oil prices in 2014 to be driven by the increase in production in the Permian.  The oversupply of oil pushed prices down worldwide.  Just as oil prices have started recovering, this new discovery makes producers seriously consider if $50 per barrel oil is a thing of the past.  Walter Guidroz, program coordinator for the USGS Energy Resources Program said, “The fact that this is the largest assessment of continuous oil we have ever done just goes to show that, even in areas that have produced billions of barrels of oil, there is still the potential to find billions more.”From a valuation perspective, acreage values in the Permian are likely to continue increasing as more producers try to get their hands on valuable Permian acreage and available land becomes scarcer.  However, there is one problem with talking about technically recoverable resources: cost is not considered.  Many headlines recently boasted that the discovery in the Wolfcamp is worth $900 billion in revenue at today’s prices… but what about cost?  When using the income approach to value oil and gas assets, earnings estimates, not revenue, are capitalized. Art Berman, a petroleum geologist, described this best: “if the oil magically leaped out of the ground without the cost of drilling and completing wells; if there were no operating costs to produce it; if there were no taxes and no royalties” then the Wolfcamp discovery would be worth $900 billion.This is not to say that the Wolfcamp discovery is inconsequential, but to simply highlight the affect the pricing environment has on oil and gas valuations.  The oil and gas industry is constantly changing.  Each location in the Permian is different and costs vary by region. As a result, the valuation implications of reserves and acreage rights can swing dramatically in resource plays. Utilizing an experienced oil and gas reserve appraiser can help to understand how location impacts valuation issues in this current environment. Contact Mercer Capital to discuss your needs and learn more about how we can help you succeed.End Note1 The USGS defines recoverable resources as those that can be produced using currently available technology and industry practices. Whether or not it is profitable to produce these resources has not been evaluated.
Quick Facts: Permian Basin
Quick Facts: Permian Basin
Over the past few weeks, we have discussed the increase in M&A activity in the Permian and looked at specific characteristics that make the Permian attractive in a low price environment.  Today, we take a step back and review the broad characteristics of the Permian Basin. Download this information in a convenient PDF at the bottom of this post.Permian at a GlanceFirst Discovered1920Discovery as Viable PlayBegan in 1923, declined post 1970s, increased again after 2007Primary ProductionOilOil TypeSweet, Light CrudePlayConventional & Unconventional PlaysDrillingVertical (traditionally), Horizontal (81% of recent drilling) and Multi-Stage Hydraulic FracturingTop 3 Production CompaniesOccidental, Pioneer, ApacheBreakeven$25 – $63 per barrel 1Abnormal DUCs433 2Production Since 20077,156 MMBOE 3IssuesCheapest Oil Has Already Been ProducedPotentialImproving Technology, Easy Entry, Stacked Play Efficiency, Low Service & Transport Costs, & Under-Explored Layers1 Bloomberg Intelligence county-level estimates 2 Drilled Uncompleted Wells with > 3 months in inventory as of January 2016; also referred to as fraclog (Bloomberg Intelligence) 3 EIA as of June 2016Overview of Permian BasinStretching over 86,000 sq. miles in western Texas and New Mexico, the Permian Basin is the most productive formation in the U.S. Since 2007, new technologies have created a boom in the region by increasing the production of old wells and enabling drilling in previously underdeveloped geological layers. In the current low price environment, Permian production has been affected less than other large U.S. reserves.Geography & DrillingThe Permian Basin produces from a variety of geological formations. These formations are layered on top of each other, creating stacked reservoirs of limestone, sandstone, and shale. For decades, wells have targeted conventional, permeable reservoir layers that trap oil and gas produced primarily in the shale layers. Recently developed enhanced extraction techniques have maintained these reservoirs’ outputs. However, since 2007, hydraulic fracturing targeting the less permeable tight sand and shale layers has driven over 60% of new production growth. Many of these new wells are “stacked plays” that capitalize on the region’s layered geography by exploiting multiple producing zones (conventional and unconventional) from one surface drill point. The Permian is divided into basins such as the Delaware Basin and Midland Basin which are further divided into zones, or stacks, such as the Wolfcamp, Spraberry, Clearfork, Avalon, and Bone Springs.Issues & Future PotentialThe easiest, cheapest oil and gas to extract from the Permian Basin was produced long ago making many areas uneconomical to produce at low oil prices. However, Permian wells tend to be more efficient than pure shale plays because they drill through many productive layers. For example, Wolfcamp wells are estimated by Bloomberg Intelligence to have the lowest break-even point of any U.S. shale oil play. The Permian will benefit from continued technological advances, development of less-known, potentially productive layers, and an abundance of low cost support services and pipelines.Permian Production Baker Hughes collects and publishes information regarding active drilling rigs in the United States and internationally. The number of active rigs is used as a key indicator of demand for oilfield services & equipment.  However, rig counts can be misleading if not considered along with production. Rig counts in the Permian drastically decreased in late 2014 and throughout 2015. However, production did not experience the same decline. This demonstrates that producers with average or poor locations, higher costs, and inefficiencies were forced out of the market, while those with good locations and lower costs continued to drill for oil and gas in the Permian. AVAILABLE RESOURCEQuick Facts: Permian BasinDownload this information in a convenient, one-page PDF. Download
The Fair Market Value of Oil and Gas Reserves
The Fair Market Value of Oil and Gas Reserves
A couple of weeks ago we looked at Exon Mobil Corp.’s lack of asset write-downs to understand different values placed on oil and gas reserves in a GAAP, Non-GAAP, and IFRS context.  This week we explain how to find the fair market value of oil and gas reserves. Oil and gas assets represent the majority of value of an E&P company. The oil and gas financial journal describes reserves as “a measurable value of a company's worth and a basic measure of its life span.”  Thus understanding the fair market value of a company’s PDP, PDNP, and PUDs is key to understanding the fair market value of the Company.  As we discussed last time, the FASB and SEC offer reporting guidelines regarding the disclosure of proved reserves. But none of these represent the actual market price.  It is especially important to understand the price one can receive for reserves as many companies have recently sold “non-core” assets to generate cash to pay off debt and fund operations. The American Society of Appraisers defines the Fair market value as:The price, expressed in terms of cash equivalents, at which property would change hands between a hypothetical willing and able buyer and a hypothetical willing and able seller, acting at arm’s length in an open and unrestricted market, when neither is under compulsion to buy or sell and when both have reasonable knowledge of the relevant facts.1The American Society of Appraisers recognizes three general approaches to valuation: (1) The Cost Approach, (2) The Income Approach, and (3) The Market Approach.  The IRS provides guidance in determining the fair market value of an oil and gas producing property.  Treasury Reg. 1.611–2(d) offers that if possible the cost approach or comparative sale approach should be used before a discounted cash flow analysis (DCF).  When valuing acreage rights comparable transactions do provide the best indication of value.  However, when valuing reserves, a DCF is often the best way to allocate value to different reserve categories because comparable transactions are very rare as the details needed to compare these specific characteristics of reserves are rarely disclosed.Cost ApproachThe cost approach determines a value indication of an asset by considering the cost to replicate the existing operations of an asset. The cost approach is used when reserves have not been proved up and there have been no historical transactions, yet a participant has spent significant time, talents, and investments into exploratory data on an oil and gas prospect project.Market ApproachThe market approach is a general way of determining a value indication of an asset by using one or more methods that compare the subject to similar assets that have been sold.Because reserve values vary between oil and gas plays and even within a single play, finding comparable transactions is difficult. A comparable sale must have occurred at a similar time due to the volatile nature of oil and gas prices.  A comparable sale should be for a property that is located within the same play and within a field of similar maturity.  Additionally, comparable transactions must be thoroughly analyzed to make sure that they were not transacted at a premium or discount due to external factors.  Thus the market approach is often difficult to perform because true comparable transactions are rare. However, the transaction method generally provides the best indication of fair market value for acreage and lease rights.Income ApproachThe income approach estimates a value indication of an asset by converting anticipated economic benefits into a present single amount.  Treasury Reg 1.611 – 2(e)(4) provides a straightforward outline of how the approach should be used.In practice, this method requires that: The appraiser project income, expense, and net income on an annual basisEach year's net income is discounted for interest at the "going rate" to determine the present worth of the future income on an annual and total basisThe total present worth of future income is then discounted further, a percentage based on market conditions, to determine the fair market value. The costs of any expected additional equipment necessary to realize the profits are included in the annual expense, and the proceeds of any expected salvaged of equipment is included in the appropriate annual income. Although the income approach is the least preferred method of the IRS, these techniques are generally accepted and understood in oil and gas circles to provide reasonable and accurate appraisals of hydrocarbon reserves, and most closely resembles the financial statement reporting requirements discussed in our previous post.  This method is the best indication of value when a seismic survey has been performed and reliable reserve estimates are available.  In order to properly account for risk, we divide the reserves by PDP, PDNP, PUD, Probable, and Possible reserves.  We will review the key inputs in a DCF analysis of oil and gas reserves below.Cash InflowsIn order to estimate revenue generated by an oil and gas reserve, we must have an estimate of production volume and price.  Estimates of production are collected from Reserve reports which are produced by geological engineers.The forward price curve provides monthly price estimates for 84 months from the current date.  Generally, the price a producer receives varies with the price of benchmark crude such as WTI or Brent. Thus, it is important to carefully consider a producers contract with distributors. For example a company may sell raw crude to the distributor at 65% of Brent.Cash OutflowsMany E&P companies do not own the land on which they produce. Instead they pay royalty payments to the land owner as a form of a lease payment.  Royalty payments are generally negotiated as a percentage of the gross or net revenues derived from the use of the property.  Besides royalty payments and daily operating costs, it is important to have conversations with management to understand future infrastructure maintenance and capital expenditures.DiscountOil and gas reserves can be based on pre-tax or after-tax cash flows.  Pre-tax cash flows make reserve values more comparable as tax rates vary by location.  When using pre-tax cash flows, we use a pre-tax cost of debt and pre-tax cost of equity to develop a WACC.Risk Adjustment FactorsWhile DCF techniques are generally reliable for proven developed reserves (PDPs), they do not always capture the uncertainties and opportunities associated with the proven undeveloped reserves (PUDs) and particularly are not representative of the less certain upside of the Probable and Possible reserve categories.  A risk adjustment factor could be used to the discounted present value of cash flows according to the category of the reserves being valued to account for PUDs upside and uncertainty by reducing expected returns from an industry weighted average cost of capital (WACC).  You could also add a risk premium for each reserve category to adjust a baseline WACC, or keep the same WACC for all reserves but discount the present value of the cash flows accordingly with comparable discounts to those shown below. The low oil price environment forced many companies to sell acreage and proved reserves in order to generate cash to pay off debt.  In order to create a new business models in the face of low oil prices, it is critical for companies to understand the value of their assets.  The valuation implications of reserves and acreage rights can swing dramatically in resource plays. Utilizing an experienced oil and gas reserve appraiser can help to understand how location impacts valuation issues in this current environment. Contact Mercer Capital to discuss your needs and learn more about how we can help you succeed. End Note1 American Society of Appraisers, ASA Business Valuation Standards© (Revision published November 2009), “Definitions,” p. 27.
RSP Permian / Silver Hill Energy: A Closer Look at the Acquisition
RSP Permian / Silver Hill Energy: A Closer Look at the Acquisition
On October 13, 2016 RSP Permian (RSPP) announced the acquisition of Silver Hill Energy (SHE) for approximately $2.4 billion dollars. SHE will receive approximately $1.182 billion in RSPP common stock and $1.25 billion in cash. Based on RSPP disclosures, the assets received include (1) wells currently producing 15,000 barrels of oil equivalent per day (BOEPD); and (2) 41,000 in net acreage throughout Loving and Winkler County Texas. Approximately 69% of the current production is crude oil. Based upon the consideration given by RSPP, here is the implied market value of invested capital (MVIC) for SHE: The other side of the transaction ledger is the value of the individual assets acquired. Since SHE is not a public company, allocating the purchase price to the individual assets is, dare we say, educated guesswork at best. Here is our guestimate of the assets that will need allocated value. 1 Before venturing into our approach to the allocation, we have compared pricing multiples of the SHE acquisition and other oil and gas public companies. At the time of the transaction, SHE owned acreage rights in one of the most popular domestic resource plays, the Delaware Basin. The chart below shows the implied pricing metrics for SHE versus the market pricing multiples for publicly traded operators in the Delaware Basin. Valuation Metrics Based upon these ratios2, we have the following observations: RSPP is approximately 2x larger than SHE;Of the seven public companies, SHE is very close in size to Matador Resources Company (MTDR). SHE has acreage adjacent to acreage operated by MTDR;Based on per day production, the SHE transaction was priced at the highest indicated value;Based upon net acres acquired, the SHE transaction was priced at the higher end of the indicated value of all the publicly traded companies. Note that approximately 95% of the acreage acquired is considered developed; Based upon these observations, we have the following commentary on SHE:It appears the majority of SHE’s asset values are in the producing 58 wells: 95% of the 41,000 net acreage is considered producing;49 of the 58 producing wells are horizontal;Less than 5% of the net acres are undeveloped;58 wells over 39,050 acres equates to well spacing of one per 673 acres. While 49 are horizontal wells, it appears they may be opportunities to add additional wells;Additionally, with less than 5% of the net acres to be explored, a higher than average BOEPD multiple may be explainable.Lastly, based on the data reviewed to date and the location of SHE’s acreage, RSPP may have identified opportunities to recomplete existing wells, with longer lateral and horizontal wells which may produce from other resource plays within the area. The following map, disclosed by RSPP, shows the acreage position within the resource play as well as the depths of the highly sought after Wolfcamp resource. According to this map, SHE’s acreage is centered in the deepest portions of the Wolfcamp, approximately 7,500 to 8,500+ feet. This location allows for penetration into multiple zones. RSPP has thus far identified seven zones they would target. Additionally RSPP has identified other wells around the acquired acreage (shown below) that have seen success from multi-zone production. Some of these wells are that of SHE, others from competing operators. 3 Assets PurchasedEarlier, we displayed the high level categories for an allocation of purchase price. Three of these categories are oil and gas related assets: (1) 58 wells currently producing 15,000 barrels of oil equivalent per day; (2) proved developed reserves; and (3) 41,000 net acres, of which 5% are considered undeveloped. The valuation for current production and proved developed reserves is fairly straight forward. No doubt SHE prepared a reserve report which would aid in the valuation of the currently producing wells and the remaining proved reserves. However, the valuation gap between the proved developed reserves and the remaining proved undeveloped, probable and possible reserves or acreage value can be detailed, tedious, and complex. The historically low oil and gas price environment and financial tension within the industry creates a complicated market place for using market transactions as indications of value.More information is needed to drill down into the specifics and valuation of each of the acquired oil and gas assets. Interested parties may want to consider the following information areas:Reserve Reports. Specifically, we would like to understand the amount of acreage in each of the maps above that have been drilled versus what areas are included in the drilling plan, PV 10 indications and price deck assumptions;Financial Statements. It would also be helpful to understand more about SHE’s decision to sell and perhaps the financial situation immediately prior to the sale. If SHE was backed by private equity investors rather than a typical oil and gas operator, management could have had different reasons to exit their investments. Timing may also have played a part as Permian dominated assets currently appear to be selling for a Premium compared to other domestic plays.Synergistic efficiencies. Drilling efficiencies have been disclosed by RSPP, but we don’t know how many are new well locations verses recompletion of existing into multiple resource plays. Much of the acquisition details have not been disclosed, and we’ll wait for additional filings from RSPP to learn more. Regardless, RSPP’s acquisition of SHE ranks as a top five E&P related transactions of 2016 based on size and analyzing available information can help us to better understand the current marketplace. Based upon our experience involving private companies, we understand that pricing for proven undeveloped, probable and possible reserves have dropped significantly in the previous year, by upwards of 90% in some cases. In addition, due to the nature of the current oil and gas environment, we understand that the historical transactions may have little comparability to today. Mercer Capital has significant experience valuing assets and companies in the energy industry, primarily oil and gas, bio fuels and other minerals. Our oil and gas valuations have been reviewed and relied on by buyers and sellers and Big 4 Auditors. These oil and gas related valuations have been utilized to support valuations for IRS Estate and Gift Tax, GAAP accounting, and litigation purposes. We have performed oil and gas valuations and associated oil and gas reserves domestically throughout the United States and in foreign countries. Contact a Mercer Capital professional today to discuss your valuation needs in confidence. End Notes1 We have used publicly available information. As such this is a high level summary of approaching an allocation without having all the needed information. 2 BOEPD = Barrels of Oil Equivalent Produced Per Day PD Reserves = Proved Developed Reserves 3 RSP Investor Presentation Acquisition of Silver Hill on October 13, 2016
Oil and Gas Reserve Values
Oil and Gas Reserve Values
This is the first of two posts in which we will investigate the different values placed on oil and gas reserves in a GAAP, Non-GAAP, IFRS, and fair market value context. As an example we will consider Exxon Mobil Corp., the nation’s largest energy company, which is under investigation for its lack of asset write-downs amid falling oil and gas prices. The Exploration and Production sector focuses on finding and using oil and gas reserves; thus the value of an E&P company exists in the value of its reserves. For many companies, such as professional service firms and tech start-ups, book value is meaningless from a valuation perspective because the true value of the company is not reflected on the balance sheet. But, because E&P companies’ value lies in the value of their reserves, investors often look to book value in order gauge future performance. In order to protect investors from misleading information, the SEC, FASB, and IFRS have specific rules for reporting and accounting for proved reserves. When we talk about reserve values there is a difference between the fair market value of reserves, the value of reserves as shown on a company’s 10-K, and the GAAP standard measure for oil and gas reserves. The SEC uses a reported value known as PV-10 in order to make proved reserves comparable across companies. PV-10 is the value of reserves calculated as the present value of estimated future revenues less direct expenses discounted at an annual rate of 10%. But, PV-10 is a non-GAAP accepted measure. The FASB’s ASC 932 requires a similar standardized measure for the value of proved reserves called SMOG (standardized measure of oil and gas). SMOG is calculated with the same methodology as PV-10 but deducts income taxes whereas PV-10 does not. Both PV-10 and SMOG require (1): reserve estimates (2): a sales price and (3): an estimate of cost.All reserve estimates involve some degree of uncertainty, which can be minimized with dependable geological and engineering data and proper interpretation of the data. There are two methods of reserve estimates. While both are based on geological, engineering, and economic data, a deterministic estimate is single estimated value while a probabilistic estimate is a range of values given with their associated probabilities.The price of oil/natural gas used to calculate future income must be the twelve-month average price not the year end spot price.While the SEC and FASB provide guidelines for what should be included as a direct expense, costs, realistically, are estimated differently by every company leading to some inconsistency in these standardized values across firms. The SEC’s Modernization of Oil and Gas Reporting requires that PUDs only include wells that are “economically producible” within five years. As the price of oil dropped in 2014, companies had to revise revenue estimates for many of their wells and some wells were no longer considered economically viable during the SEC’s five year time period. Thus many companies had to reclassify certain proved reserves as probable or possible reserves. Bradley Olson, of the Wall Street Journal, reported:With low crude oil and natural gas prices, billions of barrels of fuel in the ground cannot be tapped cost effectively, making reserves revisions and write-downs staples of oil-patch earnings in recent years, and helping push energy company losses to record levels.Competitors of Exxon have booked over $200 billion of write downs since oil prices collapsed in 2014, but Exxon has not recorded losses associated with reserve write downs. Exxon says that they have not written down the value of their reserves because they use conservative accounting techniques when they initially book the value of new fields and wells. Unlike its competitors, Exxon’s proved reserves only consist of fields in which “management has made significant funding commitments toward the development of the reserves.” Exxon’s CEO challenges management to make sure that capital expenditure projects will be viable even in a low price environment. Thus, when the price of oil fell Exxon claimed that they still had the necessary funding to develop its PUDs and did not have to write down the value of its reserves. However, if a 60% drop in oil prices did not impair reserve values, then maybe Exxon’s reserves were undervalued before.The SEC recently broadened the definition of proved reserves as:those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations[… ]The SEC elaborates on many details such as what is a reasonable time frame, what part of the reservoir is included as proved, and when can improved recovery techniques be used to estimate future production. But there is still room for interpretation. Although Exxon executive, Alan Jeffers said that Exxon is confident that its financial reporting is legal, it is clear that Exxon has used the somewhat ambiguous definition of proved reserves to do something different than many of its peers. Additionally, this investigation overlaps with another investigation into Exxon’s asset values in consideration of the future cost of environmental regulations and the global response to climate change.Just as there are differences in reporting standards when determining the value of proved reserves, there are differences in the way companies determine if reserves are impaired. Companies that have overseas operations often keep two sets of books because they must also follow International Financial Reporting Standards (IFRS). Both GAAP and IFRS have the same goal of making sure that assets are not reported above the value that could be recovered from liquidating the asset, but they have different methodologies to determine if an asset is impaired. Under IFRS, future discounted cash flows are compared to the book value of the asset, while under GAAP, undiscounted future cash flows are compared to book value. Although the threshold of impairment is higher under GAAP, GAAP write downs cannot be reversed when economic conditions recover, unlike IFRS write downs which are reversible. In order to write down assets, discounted cash flows are used by both IFRS and GAAP.It is important to remember, especially, in a low oil price environment that the reserve values presented on company’s 10-Ks may not be an accurate representation of fair market value. Fair market value represents the price at which property would change hands between a hypothetical buyer and seller. Next time we will discuss how to determine the fair market value of oil and gas reserves.Contact Mercer Capital to discuss your valuation needs in confidence and learn more about how we can help you succeed.
M&A in the Permian: The Trend Continues
M&A in the Permian: The Trend Continues
Last week, we looked at the recent transition of E&P companies out of the Bakken and the Eagle Ford to the Permian.  We concluded that E&P companies are moving to the Permian for its (1) upside potential, (2) low break even prices, and (3) diversity of resources.  This week M&A activity reinforced this idea.  In the last week, there were 18 E&P deals in the U.S.1  Seven of those transactions were in the Permian and over half of the total deal value generated ($768 million in total) from September 30 to October 6 was in the Permian.  Today we focus on two transactions: Resolute Energy’s acquisition of Delaware Basin Acreage and Apollo and Post Oak Energy’s merger to form Double Eagle Energy Permian.  Before we drill down the details of these transactions, here’s a breakdown of total announced deal value generated in the U.S. this year.Resolute Energy / Firewheel Energy TransactionResolute Energy, a Denver based company, received notice twice in 2015 that it was at risk of being delisted from the NYSE and its EBITDA fell so low that the Company considered a Chapter 11 restructuring in late 2015.   The Company sold its Powder River and Midland Basin assets for $275 million which allowed it to reduce its debt and increase its drilling activity in the Delaware Basin. Since then they have more than tripled their Delaware Basin output.  They estimated third quarter output for 2016 to be between 16,000 and 16,500 Boe/d, which is a 37% increase from the second quarter of 2015.On October 4 Resolute announced its acquisition of 3,293 acres in the Delaware Basin from Firewheel Energy, a portfolio Company of EnCap Investments. The acquired acreage will increase Resolute’s position in Reeves County in the Delaware Basin by 25%, according to their press release.  The acquired acreage includes thirteen horizontal and fifteen vertical wells, which produce approximately 1,200 Boe/d.Resolute’s purchase price consisted of $90 million payable in cash and $45 million payable in common stock.  Although Resolute’s stock had been at risk of being delisted just 9 months prior, the Company was able to increase the value of its stock by refocusing operations in the Permian, which investors have lately placed a premium on, and by participating in a one-for-five reverse stock split. This allowed the Company to fund this transaction with common stock and generate cash to fund the acquisition with an offering of a new class of preferred shares.Resolute reported the value of the Proved reserves as $45.8 million and Undeveloped Acreage as $79.8 million.Double Eagle Lone Star LLC / Veritas Energy Partners Holdings LLC MergerTwo private-equity backed E&P companies recently merged their Permian focused operations.  Double Eagle Lone Star LLC, an affiliate of Apollo Global Management, assembled a portfolio of assets in the Powder River Basin, the DJ Basin, Mid-Continent, Eagle Ford and Permian. The Company sold its SCOOP (South Central Oklahoma Oil Province) and STACK (Sooner Trend Anadarko Basin Canadian and Kingfisher Counties) assets for $250 million in order to transition its focus away from Anadarko Basin in Oklahoma to the Permian in west Texas.  Veritas Energy acquired acreage mainly in the Midland Basin and Fort Worth Area and formed a partnership with Post Oak Energy Capital to focus on increasing acreage in the Midland Basin.  The two announced their merger on October 3rd.  The new Company will have more than 63,000 net acres in the Permian’s Midland Basin.  The deal values were not disclosed.Analysts with 1Derrick predict that the Company was formed in order to prepare for an IPO in order to take advantage of the high equity valuations of pure play Permian producers.  Industry averages of EV/ Boe of proved reserves are estimated to be $13.45, while Permian producers multiples are often higher than $25 / Boe.2In order to prepare for an IPO, however, Double Eagle Permian will have to focus on developing its assets as only 70% of the assets are currently operated. The Texas Railroad commission reports that the combined Texas production of both Double Eagle and Veritas is about 3,000 Boe/d. The appeal of the Permian to market participants is the low cost of drilling. Thus in order to reach its full potential, the Company must be able to achieve the double-digit production growth that many of its peers have.These two transactions demonstrate that market is currently placing high value on the equity of companies located in the Permian and E&P companies are doing what they can to take advantage of this.  Mercer Capital has significant experience valuing assets and companies in the energy industry, primarily oil and gas, bio fuels, and other minerals.  We have performed oil and gas valuations and associated oil and gas reserves domestically throughout the United States and in foreign countries. Contact a Mercer Capital professional today to discuss your valuation needs.End Notes1Only includes packages valued at greater than $100 million. 21Derrick
M&A Overview: Race to the Permian
M&A Overview: Race to the Permian
M&A activity in the exploration and production industry has recovered from the standstill experienced one year ago as oil and gas companies waited to see what the market would throw at them next. When crude oil prices dropped, companies reduced their exploration budgets and stopped drilling new wells. When prices remained low, many companies began to sell off non-core assets in order to generate cash to pay off debt. Companies, who cut drilling activity when prices collapsed, are now looking to replace their reserves through acquisitions. Bloomberg analysts predict that the majority of M&A activity going forward will be asset purchases as E&P companies look to acquire more than 50% of their reserve replacement.The majority of these transactions have occurred in the Permian. This year, 38% of total E&P deal value was generated from deals in the Permian, and 24% of the number of total deals occurred in the Permian.1 This demonstrates that more deals and larger deals are happening in the Permian than in other plays in the U.S. Last week we looked in depth at EOG’s acquisition of Yates Petroleum for $2.5 billion. The acquisition helped EOG shift from the Eagle Ford into the Permian. EOG’s CEO Bill Thomas told investors, “We’ll be able to grow oil (production) with less capital and more efficiently than we do now.” EOG’s share price rose by more than 6% the day after the transaction. E&P companies are flocking to the Permian for many reasons, including its (1) upside potential, (2) low break even prices, and (3) diversity of resources. Upside PotentialAlthough the Permian was discovered in the 1920s, the true potential of the Permian was not realized until 2007 when hydraulic fracturing techniques were used to access the tight sand layers of the play. Since then the Permian has been revitalized as producers have begun using unconventional drilling techniques in addition to traditional vertical wells. Because the crude in the shale layers have only recently been explored, there are still tremendous reserves left.Low Breakeven PricesThe Permian has low break even prices compared to other reserves in the U.S. Although production costs may not be as low as Pioneer Natural Resources CEO, Scott Sheffield, boasted ($2.25 per barrel excluding taxes), costs are lower than other plays due to the geological makeup of the shale.The Permian is a stacked play which means that multiple horizontal wells can be drilled from one main wellbore. This provides increased productivity as multilateral wells have greater drainage areas than single wellbore. Additionally, it can reduce overall drilling risk and cost. For deep reservoirs like the Permian, a multilateral well eliminates the cost of drilling the total depth twice.2In many plays, the low price of crude oil has made drilling uneconomical. Many companies are trying to acquire acreage in the Permian, where production is cheaper, because it is unclear when crude prices will rise and if they will ever rise to the same levels as before.Diversity of ResourcesThe Permian is the largest producer of oil and the second largest producer of gas, after the Marcellus. Even as gas prices collapsed, production in the Permian increased. Companies that operate in the Permian do not have to choose between oil and gas, but can diversify operations. The market for commodities is inherently risky because producers are price takers. Although related, the price of natural gas and crude oil are not perfectly correlated. Thus when the price of natural gas fell six years ago, producers in the Marcellus and Utica were entirely exposed to the natural gas market, while producers in the Permian were able to rely on their profits from crude oil to fund operations. Exploration and Production companies are trying to get their hands on acreage in the Permian now before the next swing in crude oil prices. OPEC agreed on Wednesday to cut its production of crude oil. IEA analysts believe that the proposed cuts to between 32.5 million and 33 million barrels per day would bring production back in line with demand until the second half of 2017. Definitive policies are expected to be set in November, but there still remains doubt that the deal will be able to relieve supply due to OPEC’s inability to enforce these quotas. This uncertainty about the future price of crude oil has caused producers to leave other plays and increase their acreage in the Permian. Consequently, this has increased acreage prices in the Permian compared to other plays, such as the Bakken and Eagle Ford. A summary of some transactions in the Permian this year is shown below. Callon Petroleum increased its position in the Permian the same day as the EOG / Yates transaction. Callon was traditionally an offshore driller in the Gulf of Mexico. They began shifting out of the Gulf in 2010 due to the high costs of offshore drilling and sold their last offshore asset in 2013. Since then the company has steadily been increasing its stake in the Permian. Since the second quarter of last year the Company has increased production by 56%, while at the same time reducing capital expenditures by 48%.3 The company has recently been using its highly valued stock to fund acquisitions in the Permian. The price of Callon’s stock price has tripled since January even though they have increased their shares outstanding by 50% over the same time period. This demonstrates investor’s confidence in the Permian. The valuation implications of reserves and acreage can swing dramatically in resource plays. Utilizing an experienced oil and gas reserve appraiser can help to understand how location impacts valuation issues in this current environment. Mercer Capital has significant experience valuing assets and companies in the energy industry, primarily oil and gas, bio fuels, and other minerals. We have performed oil and gas valuations and associated oil and gas reserves domestically throughout the United States and in foreign countries. Contact a Mercer Capital professional today to discuss your valuation needs. End Notes1 1Derrick 2 New Aspects of Multilateral Well Construction. Fraija, José; Ohmer, Hervé; and Pulick, Tom. Online Available at http://www.slb.com/~/media/Files/resources/oilfield_review/ors02/aut02/p52_69.ashx. 3 1Derrick
EP Fourth Quarter 2016 Region Focus Marcellus Utica Shale
E&P Fourth Quarter 2016

Region Focus: Marcellus & Utica Shale

Region Focus: Marcellus & Utica Shale: Oil prices increased over the last twelve months from $37/bbl at January 4, 2016 to $55/bbl at year end.
Refining Fourth Quarter 2016
Refining Fourth Quarter 2016
The refining industry has struggled with margin compression over the last six months.
EOG/Yates Merger
EOG/Yates Merger

A Closer Look at the Acquisition

On September 6, 2016 EOG Resources (EOG) announced the acquisition of Yates Petroleum (Yates) for approximately $2.4 billion dollars, by our calculations. Yates will receive approximately $2.2 billion in EOG common stock and $37 million in cash. In addition, EOG assumed $114 million (net) in Yates debt.1 Based on EOG’s disclosures, the assets received by EOG include (1) Wells currently producing 29,600 barrels of oil equivalent per day (BOEPD); (2) proved developed reserves of 44 million barrels of oil equivalent; and (3) 1.624 million in net acreage throughout New Mexico, Wyoming, Colorado, Montana, North Dakota and Utah. Approximately 48% of the current production and proved developed reserves are crude oil. Based upon the consideration given by EOG, here is the implied market value of invested capital (MVIC) for Yates: The other side of the transaction ledger is the value of the individual assets acquired. Since Yates is not a public company, allocating the purchase price to the individual assets is, dare we say, educated guesswork at best. Here is our guestimate of the assets that will need allocated value and their key information items.2 Before venturing into our approach to the allocation, we have compared pricing multiples of the Yates acquisition and other oil and gas public companies. At the time of the transaction, Yates owned acreage rights in several domestic resource plays with the most popular resource play of 186,000 net acres in the Delaware Basin. The below chart shows the implied pricing metrics for Yates versus the market pricing multiples for publicly traded operators in the Delaware Basin. Valuation MetricsBased upon these ratios, we have the following observations:3EOG is approximately 25x larger than Yates;Of the six public companies, Yates is very close in size to Matador Resources Company (MTDR);Based on per day production, the Yates transaction was priced at the lowest indicated value except for Apache Corp (APA);Based upon net acres acquired, the Yates transaction was priced at the lowest indicated value of all the publicly traded companies;Based on proved developed reserves, the Yates transaction was priced at the highest indicated value of the group. Based upon these observations, we have the following commentary on Yates:The attractive upside for Yates is not in the current production, but in the undeveloped acreage, possibly adjacent to EOG acreage (explains the low MVIC to BOEPD metric);Of the acreage that Yates owned, a large majority of it is not highly coveted by Yates and EOG (explains the low MVIC to net acre metric);Of the proved developed reserves known by Yates, EOG believes they can develop significantly more reserves in the future (explains the high MVIC to proved developed reserves metric);As the interest for EOG does not appear to be in vast amounts of acreage that Yates owns, the current production nor the developed reserve, this leads us to believe the highly coveted Delaware Basin positions were the primary drivers for the acquisition.Assets PurchasedEarlier, we displayed the high level categories for an allocation of purchase price. Three of these categories are oil and gas related assets: (1) Wells currently producing 29,600 barrels of oil equivalent per day; (2) proved developed reserves of 44 million barrels of oil equivalent; and (3) 1.624 million in net acreage. The valuation for current production and proved developed reserves is fairly straight forward. No doubt Yates prepared a reserve report which would aid in the valuation of the currently producing wells and the remaining proved reserves. However, the valuation gap between the proved developed reserves and the remaining proved undeveloped, probable and possible reserves or acreage value can be detailed, tedious, and complex. The historically low oil and gas price environment and financial tension within the industry creates a complicated market place for using market transactions as indications of value.Acreage Owned by Yates The highly publicized acreage includes: (1) 186,000 net acres in the Delaware Basin; (2) 138,000 net acres in the Northwest Shelf; (3) 200,000 net acres in the Powder River Basin and (4) other western basins which add up to 1.1 million net acres. The following maps, disclosed by EOG, show the resource plays Yates owned acreage within. These resource plays range from Texas to Canada. Of the eight resource plays named in the map, EOG classifies two as the “best plays”. These are the Delaware Basin and the Powder River Basin. Delaware Basin EOG then allows us a closer look at the location of Yates acreage in the Delaware Basin in comparison to EOG’s acreage. Many instances exist where Yates acreage is right next to EOG’s acreage, this could allow for longer and more cost effective lateral wells. Market transactions for acreage in this area vary significantly based on seller motivation, buyer synergies and commodity price timing. Our experience indicates acreage rights historically transact from $50 per acre to $14,000 per acre and above, depending on location. Northwest Shelf Another map comparing Yates and EOG’s acreage location in the Northwest Shelf shows less instances where the two companies acreage is connected but clearly demonstrates Yates is seemingly centered in the most desired areas of the Northwest Shelf. In addition to these two plays, the map shows Yates acreage located in northern Chaves and Lea counties. EOG does not show any acreage in these areas. Our historical transaction data indicates acreage rights transact for $50 to $350 per acre in northern Chaves, Lea, and Roosevelt counties. Compare this to the Delaware Basin and Northwest Shelf areas which have spots that historically transact for $5,000 per acre and above. Powder River Basin EOG also discusses their interest in the Powder River Basin. As the map shows, EOG has significant acreage positions in the middle of the play. Similarly, Yates has large clumps of acreage rights in the same general area and in some cases, right next to EOG. This tends to indicate efficient drilling benefits may exist in the Powder River Basin too. Similar to the resource plays in New Mexico, acreage rights pricing varies widely by location. Drilling DeeperMore information is needed to drill down into the specifics and valuation of each of the acquired oil and gas assets. Interested parties may want to consider the following information areas:Reserve Reports. Specifically, we would like to understand the amount of acreage in each of the maps above that have been drilled versus what areas are included in the drilling plan, PV 10 indications and price deck assumptions.Financial Statements. It would also be helpful to understand more about Yate’s decision to sell, and perhaps, the financial situation immediately prior to the sale. What we know is approximately 48% of the current production is oil which leaves 52% of the production as either natural gas or natural gas liquids. This leads us to ask: is Yates an example of oil prices exposing a struggling natural gas company? Yates had $245 million in debt, and $114 million in net debt. Based upon our calculated $2.3 billion MVIC indication, debt is approximately 4.85% of the capital structure. While this is just a guess on our part, this doesn’t indicate a financially stressed company. It does make us question their ability to obtain additional financing for new wells.Synergistic efficiencies. Drilling efficiencies have been disclosed by EOG, but we don’t know how many new well locations EOG created by having access to Yates acreage. Yates may not have been able to release on their own for many reasons. Much of the acquisition details have not been disclosed and we’ll wait for additional filings from EOG to learn more. Regardless, EOG’s acquisition of Yates was one of the largest E&P related transactions of 2016 and analyzing available information can help us to better understand the current marketplace. Based upon our experience involving private companies, we understand that pricing for proven undeveloped, probable and possible reserves have dropped significantly in the previous year, by upwards of 90% in some cases. In addition, due to the nature of the current oil and gas environment, we understand that the historical transactions may have little comparability to today. Mercer Capital has significant experience valuing assets and companies in the energy industry, primarily oil and gas, bio fuels, and other minerals. Our oil and gas valuations have been reviewed and relied on by buyers and sellers and Big 4 Auditors. These oil and gas related valuations have been utilized to support valuations for IRS Estate and Gift Tax, GAAP accounting, and litigation purposes. We have performed oil and gas valuations and associated oil and gas reserves domestically throughout the United States and in foreign countries. Contact a Mercer Capital professional today to discuss your valuation needs in confidence. End Notes1 $245 million in Yates debt less $131 million in Yates cash 2 We have used publicly available information. As such this is a high level summary of approaching an allocation without having all the needed information. 3 BOEPD = Barrels of Oil Equivalent Produced Per Day, PD Reserves = Proved Developed Reserves
Quick Facts: Eagle Ford
Quick Facts: Eagle Ford
Over the previous weeks, we have discussed specific factors in the Eagle Ford like DUCs (Drilled but Uncompleted Wells) and how certain operators behave in this resource play. Today, we take a step back and review the broad characteristics of the Eagle Ford Shale resource. Download this information in a convenient PDF at the bottom of this post.Eagle Ford at a GlanceFirst Discovered2008Discovery as Viable Play2008Primary ProductionOilOil TypeSweet, Light CrudePlayUnconventional ShaleDrillingHorizontal, Multi-Stage Hydraulic FracturingTop 3 Production CompaniesEOG Resources, BHP Billiton, Conoco PhillipsBreakeven$27 – $63 per barrel 1Abnormal DUCs416 2Production Since 20074,338 MMBOE 3IssuesLikely to have High Entry Cost & Low Oil PricesPotentialLow Breakeven Oil & Gas Prices due to High Productivity per Well & New Play so Large Amounts of Oil & Gas Remain1 Bloomberg Intelligence county-level estimates 2 Drilled Uncompleted Wells with > 3 months in inventory as of January 2016; also referred to as fraclog (Bloomberg Intelligence) 3 EIA as of June 2016Eagle Ford ShaleLocated in south Texas, the Eagle Ford is the most active shale play in the world.   The shale’s potential was first recognized in 2008 when the first drillers, Petrohawk, found natural gas. Soon after that, other drillers began to enter the play and discovered not only significant natural gas reserves, but also large quantities of oil. Since then companies have invested heavily in Eagle Ford, with almost $30 billion spent on developing the play in 2013. In 2015, 57% of production was oil, and 43% of production was natural gas.As with other oil and gas formations, the current price environment hampers profitability. However, the region has some of the lowest natural gas breakeven prices in the U.S. (according to Barclays) and the lowest shale oil breakeven prices after the Permian (according to Bloomberg).  Such low costs are likely to attract many large players to the region, particularly as other areas struggle. This in turn will raise the cost to enter the play.Undiscovered, Recoverable Resources in Eagle FordResource Estimate*Recoverable Oil994 MMBRecoverable Natural Gas52,428  BCFRecoverable Liquid N.G.2,059 MMB*Estimate calculated from the mean undiscovered, recoverable reserve estimates in the 2011 USGS report.The U.S. Geological Survey (USGS) completed a geology-based assessment of the undiscovered, technically recoverable oil and gas resources in Upper Cretaceous strata of the U.S. Gulf Coast region, which includes the Eagle Ford Group. The amount of undiscovered, recoverable natural gas in the Eagle Ford exceeds that in the Permian Basin.Eagle Ford Production Baker Hughes collects and publishes information regarding active drilling rigs in the United States and internationally. The number of active rigs is used as a key indicator of demand for oilfield services & equipment. However, rig counts can be misleading if not considered along with production. Rig counts in the Eagle Ford drastically decreased in late 2014 and throughout 2015. However production did not experience the same scale of decline. This demonstrates that producers with average or poor locations, higher costs, and inefficiencies were forced out of the market, while those with good locations and lower costs continued to drill for oil and gas in the Eagle Ford. AVAILABLE RESOURCEQuick Facts: Eagle FordDownload this information in a convenient, one-page PDF. Download
Long Term Value Drivers in the Eagle Ford
Long Term Value Drivers in the Eagle Ford

Get Your DUCs in a Row

The Eagle Ford Shale is one of the largest economic developments in the state of Texas. Almost $30 billion was spent developing the play in 2013. However, that figure dropped off dramatically in 2015 and 2016. In the wake of that drop-off some of the key residuals of that investment remain and are still on the precipice of becoming more active. These residual investments exist in the form of drilled, but uncompleted horizontal wells – sometimes known as “DUCs” or “Fracklog”.Economically, these DUCs function as a form of storage for companies who do not want to complete and produce these wells at current pricing. Thus, they sit idle – waiting to be completed and graduate to a full-fledged producing PDP well.  This is a phenomenon that exists in all the major shale plays in the U.S. and second only to the Bakken, the Eagle Ford has the largest inventory of DUCs (460) in the U.S. Many of the big shale producers are jumping on board the fracklog bandwagon. The largest U.S. shale producer to fracklog is EOG Resources (EOG). It started 2015 with 200 DUCs and announced it would “intentionally delay” about 85 more wells this year (these are overall figures, not Eagle Ford specific). Anadarko Petroleum (APC) said it expects to have about 440 uncompleted wells by the year’s end. As a point of comparison, last week there were only a total of 44 rigs in the Eagle Ford, as compared to 205 at year-end 2014. As it pertains to the Eagle Ford specifically, Chesapeake leads the way with 86 DUCs with several other major Eagle Ford players with significant counts as well. Producers have hoped this would bring value to their shareholders, by delaying capital expenditures and functioning as storage for future reserves. These companies can then wait for more favorable oil and gas prices that justify the capital investment to complete the wells. This brings a favorable ROI to the costs, which is the core metric that management teams are tracking. How much value that this creates (or preserves depending on point of view) is linked to how much capital it requires to complete the well as compared to production and price (production x price = revenue). The Eagle Ford shale has pockets of some of the best possible wells for this ROI potential. Bloomberg Intelligence has estimated that breakeven prices for oil in the Eagle Ford can be as low as $27 per barrel. This helps explain why DUCs in the Eagle ford actually decreased in 2015 while other plays had a marked increase; several groups of wells in the Eagle Ford still had positive ROI’s and were economical to be drilled. However, there is a flip side to simply waiting until oil prices go up. Some estimates claim it will take only one to three months to get production from these now-uncompleted wells.  Bloomberg Intelligence has projected the output from these wells to be as high as three million barrels per day. This onslaught of new oil could serve to cap any rally in the oil prices. “The destruction of production potential that we've needed to see to complete the bust cycle in oil and completely rebalance markets, allowing for a long-term constructive rise in the prices of oil and natural gas, have yet to be seen.” – Daniel Dicker, Real MoneyIf Eagle Ford producers wish to capitalize on these undrilled wells, timing, resources and capital must be ready to go when the time becomes right.
What Would Warren Buffet Do?
What Would Warren Buffet Do?
[caption id="attachment_12679" align="aligncenter" width="349"] Photo Credit: Gus's Fried Chicken[/caption] One of my favorite pastimes is sampling the amazing food Memphis has to offer. Many of the best restaurants are located in buildings that are unassuming – or sometimes downright disconcerting. I am a little hesitant about walking down back streets and into old buildings to find my next meal, but I find comfort in the reviews of others. With its Styrofoam plates and 40 ounce bottles of beer, Gus’s World Famous Fried Chicken may not seem very promising, but the reviews are excellent … “lurking below that crunch is a subterranean flesh so moist and tender that it almost defies reality.” How could you not give it a try? We often rely on the reviews of experts for decisions as trivial as where to eat lunch.   When it comes to investing, we pay even more attention to what the experts say. It caught investors’ attention when Warren Buffet further increased his stake in Phillips 66 from 78.782 million shares as of June 30, 2016 to 79.6 million as of August 30, 2016. He now has invested over $6 billion in Phillips 66 and owns almost 15% of Phillips’ available shares. His recent move has sparked a lot of questions regarding what Warren Buffet was thinking. Does he think the delayed effect of the export ban won’t hurt refining margins?Does he think crack spreads are on the rise for good?Or does he know something that I don’t? Uncertainty currently surrounds the refining industry. In early 2016 the crude oil export ban that had been in place since 1975 was lifted. Industry experts thought that lifting the export ban would better align the production capabilities of U.S. refineries. Refiners, on the other hand, feared that the exportation of crude would increase crude prices, as the pressure on price, in an oversupplied U.S. market, gives way. Nine months later, we do not know all the consequences as the Brent-WTI spread is still insignificant. Once the spread widens — and it is cheaper for other countries to buy WTI and pay transportation costs than to buy Brent — the true effect will be understood. Until then, refiners should enjoy currently low input prices. Adding to the uncertainty, the refining industry is heavily regulated. One of the newest rules is the Petroleum Refinery Sector Risk and Technology Review (RTR) and the New Source Performance Standards (NSPS) rule. The RTR & NSPS was passed in December of 2015 in order to control air pollution from refineries and provide the public with information about refineries’ air pollution. These regulations range from fence line and storage tank monitoring to more complex requirements for key refinery processing units. The rule is expected to be fully implemented in 2018. However additional time has already been proposed by the EPA. The EIA estimates the rule will cost refineries a total of $40 million per year, while the American Petroleum Institute (API) argued that the annual cost would exceed $100 million. This uncertainty has led to a standstill in M&A activity. While M&A Activity in the exploration and production sector has picked up since the beginning of 2016, M&A in refining and marketing has remained sluggish. Over the last nine months, the majority of the transactions in refining and marketing were between chemical and lubricant refineries and renewable fuels refineries. Currently, investors are sticking with what they know – demand for renewable fuels will increase and chemical lubricants are still in high demand. The few transactions that occurred with petroleum transportation product refineries had very little public information. Thus we look to the public market in order to understand valuation multiples. Since the fall of crude prices in 2014, valuation multiples have been through multiple cycles of compression and expansion. For refiners, low oil prices initially signal higher profit margins as refined oil product prices are not perfectly correlated with input prices. This is especially true for non-transportation refined product prices (such as asphalt, butane, coke, sulfur, and propane) whose prices are even less likely to respond to changes in the price of crude oil. Thus, upon the initial fall of prices, earnings increased because the price of refined petroleum products did not fall as quickly as the price of crude. Additionally, the low prices of crude oil and natural gas decrease refiners’ own operating expenses. Refining is itself an energy intensive process and natural gas is used to power refineries. By the fourth quarter of 2015, refiners’ margins began to compress as the price of refined petroleum transportation products started falling. Refiners’ profits continued to fall through the first quarter of 2016, but have since recovered as the price of refined products saw slight increases.1 Buffet’s move gave downstream investors hope that refining profits won’t disappear altogether as the oil and gas market changes. Refining and Marketing valuation multiples are somewhat inflated in the current market due to compressed profit margins.  This tells us that the market views refiners’ decline in earnings as temporary.   Phillips 66 profitability is in line with the group average, but has a higher EV/ EBITDA multiple of 11.3x whereas the average is 9.1x.  This is due to their comparatively large size and depressed first quarter earnings.  Additionally Phillips 66 operations are not entirely concentrated in the refining industry.  Phillips has well developed midstream operations which they have expanded recently. Midstream operations are not as sensitive to changes in price and thus do not face the same risk of margin compression. Warren Buffet is known for making long term investments. His position in Phillips 66 does not imply smooth sailing ahead for the refining sector. Refiners’ inputs and products are both commodities, which means that the price they pay for inputs and the prices they receive for their products are generally determined by the market and out of their control. However, demand for refined products increases with the strength of the economy, and Chairwoman Janet Yellen’s recent announcement that an interest rate hike is on the table predicts that a strong economy is in our future. The oil and gas industry is still surrounded with uncertainty, but refiners have generally proven to be resilient through the oil market downturn. Despite the uncertainty, we can find some comfort from Warren Buffets recent investment decision. I know that I will find the best food on back streets, in shacks in the Lowes parking lot, and in basements downtown, but reassurance is comforting. When I ask myself what would Warren Buffet do … I think he would eat fried chicken. End NoteThe refiner marker margin (RMM) is a general indicator, calculated quarterly by British Petroleum, which shows the estimated profit refiners earn from refining one barrel of crude.
Royalty Interests: First in Line, Last in Conversation
Royalty Interests: First in Line, Last in Conversation
When the price of oil started its descent during 2014, the majority of media attention was, and still is, focused on exploration, production, and oil field services companies. While bankruptcy courts are busy deciphering reorganization plans and perhaps liquidations of companies, one group of oil and gas participants are getting little attention: royalty owners. While the last two years have been a rough ride, opportunities do exists for forward thinking royalty owners and investors.Although they are first to receive money from production, for the most part, royalty owners have been left to fend for themselves during this commodity price downturn. The lucky ones, holding their breath hoping their operator doesn’t go bankrupt, watched their monthly distributions fall to fractions of their 2014 payments. The unlucky ones haven’t seen a payment in months only to learn through media sources that their operator entered bankruptcy. When this situation occurs, many questions surface:What will happen to my royalty payments?What will happen to the lease contract?What legal action should I take? While Mercer Capital does not provide legal advice we can provide guidance on valuing royalty interests in the current environment. For some guidance on the legal questions, refer to the the first end note. Each of the questions above indicates uncertainty. As uncertainty increases, risk increases as well. As risk increases, the value of a given asset declines. But let us back up. When understanding the value of a royalty interest, it is important to understand its origin and its financial features.OriginRoyalties typically originate from an agreement between a land owner and an exploration and production (E&P) company. E&P companies that approach the owners of the property where they seek to drill wells, have two options: (1) purchase the land from the current owner; or (2) acquire the rights to drill and produce. Option two is typically cheaper, initially. The monetary components of a contract between the land owner and the E&P company is usually comprised of two components: (1) an up-front cash payment (commonly referred to as a lease bonus); and (2) a royalty interest in all future wells on the property.Financial FeaturesThe financial features of a royalty interest are best described in the definition of a royalty as follows: Ownership of a percentage of production or production revenues, produced from leased acreage. The owner of this share of production does not bear any of the cost of exploration, drilling, producing, operating, marketing, or any other expense associated with drilling and producing an oil and gas well.2Generally, royalty payments are made on a monthly basis for the production generated in the prior month. As the definition above indicates, royalty interests are not exposed to the costs of drilling, producing, or operating the well. In simplified terms, there are three main inputs driving the monthly royalty payment: (1) commodity price; (2) monthly production; and (3) royalty interest percentage. Royalty interest percentage typically will stay the same throughout the contract life, unless amendments are made. Therefore, any changes in the paystub come from changes in commodity price and production levels.Valuation of a Royalty InterestAs the financial features suggest, valuation of a royalty interest can be a straight forward exercise for an experienced professional with knowledge of the nuances. Typically there are two methods used to estimate the value of a royalty trust: (1) income approach and (2) market approach.Income ApproachA discounted cash flow analysis is based on the theory that the value of any investment is equal to the present value of its expected future economic benefit stream. In order to calculate the value one must project the future expected cash flows and discounts them back at an appropriate discount rate. Expected cash flows must project both anticipated production of the resource and anticipated prices for the resource. However, a discounted cash flow analysis is only as good as its inputs and as we discussed in our previous blog post, NYMEX future prices are no more than informed speculation. Thus the discount rate must appropriately compensate for the risk.Market ApproachAnother method used to calculate the value of a royalty interest utilizes market transactions of royalty interests in similar oil and gas resource plays. This can be done in two ways: (1) observing direct transactions of royalty interests; and (2) publicly traded royalty trusts.As a primer for O&G royalty trusts, these trusts hold various royalty and net profit interests in wells operated by large exploration & production companies. These trusts have little in the way of operating expenses, have defined termination dates, and can be an investment to provide exposure to oil and gas prices. This Motley Fool article, from 2014, explains the pros and cons of investing in this sort of vehicle.Market indications are available in the form of publicly traded oil & gas (“O&G”) royalty trusts. There are approximately 17 oil and gas focused royalty trusts publicly traded, as of the date of this article.Market ObservationsRoyalty trusts, like the rest of the oil and gas industry, have been hit hard as the price of oil fell. Here is a comparison of the 17 publicly traded royalty trusts’ metrics today versus one year ago.Observations and disclaimers:Price to revenue and price to distributable income indicate, on average, the trusts are cheaper now than a year ago.Yields were higher last year as trailing yields had not caught up to the quickly falling market price (from August 2014 to July 2015, the group was down 40% to 60%).Market prices have leveled off and yields have had a chance to catch up, resulting in lower yields compared to a year ago.Price to PV 10 is higher this year compared to last, primarily the result of timing differences between the releases of reserve reports (end of fiscal year, which for most is calendar year) the mid-year date we captured and the market price.The remaining observations are for commodity prices, both current and futures contract for the 12 month.Disclaimer: no two of the above royalty trusts are alike. Differences abound in asset mix, asset location, term, resource mix, just to name a few. In future blog posts, we will explore each trust individually and discuss their uniqueness. Below is a chart of the market price performance for each royalty trust over the last two years. The above chart looks very similar to the performance of the price of oil and gas over the same time period. Royalty interest owners have seen their monthly payments move in the same manner, and possibly have not experienced the small rebound over the first six months of 2016. Uncertainty is high as operators have been forced to file bankruptcy after commodity prices have remained low for too long for them to survive. Depending on your situation, the current pricing environment may provide excellent planning opportunities as market prices are relatively low. With the Treasury Department attempting to change the way gift and estate planning can be performed, it is even more timely to execute a transfer plan. Contact Mercer Capital to discuss your needs in confidence and learn more about how we can help you succeed. End Note1 See the article, "Protecting Oil & Gas Royalties in the Event of Bankruptcy" from the Dallas Bar Association on the topic or the article, "Bankruptcy In The Oil Patch" by the Oil and Gas Financial Journal.
Will Marcellus E&P Companies Make a Comeback?
Will Marcellus E&P Companies Make a Comeback?
The Rio Olympics are underway, but the Road to Rio was more than a little rocky. Reports of disease, pollution, and protests left us wondering if they could pull it off. But a dazzling Opening Ceremony made us wonder, are the Rio Olympics the next comeback story?For the last two years we have been asking when will oil prices recover? But natural gas E&P companies have been asking this question for almost seven years. Analysts have worked to predict which companies will make a comeback once prices recover, but the road to recovery has been and will continue to be long and rocky.Natural gas consumption has steadily increased since prices fell in 2009, but consumption of natural gas has been unable to keep up with the increased production that resulted from the shale gas revolution. Over the last ten years, natural gas production increased by a compound annual growth rate of 4% while consumption growth lagged at less than 3% per year.Since 2012, the Marcellus and Utica provided 85% of the U.S.’ shale gas production growth as hydraulic fracturing techniques improved. But this fast growth led to excess supply. The American Oil and Gas Reporter commented, “Production in the Northeast is particularly abundant, with volumes increasing from 2 Bcf/d in 2008 to more than 18 Bcf/d in 2014. That astronomical growth rate is expected to continue, reaching 30 Bcf/d by 2020.” By November of 2015, the northeast was already producing 20.3 Bcf/d.E&P companies have increasingly used debt to finance capital expenditures in order to drive sales volume and maintain revenue in a falling price environment. While heavy debt financing allows companies to maintain revenue, it also threatens their liquidity when prices stay low. A prime example is the case of Rex Energy. Until recently Rex Energy was picked by many analysts as one of the E&P companies expected to make a large rebound. Analysts calculated the implied upside potential as 146% and thirteen analysts gave Rex a buy rating. Rex’s stock price declined at the end of 2008 during the finanical crisis when natural gas prices fell. But, Rex quickly recovered by investing in the Marcellus right before the peak of the shale gas revolution. Rex maintained a debt to equity ratio of less than 80% until mid-2013 when their stock price started to fall again. Since then, Rex’s debt to equity ratio has steadily risen, exceeding 1,320% by the end of the second quarter of 2016. Shares of Rex have been trading at sub $1 levels since early May of this year, placing the stock in danger of being delisted from the NYSE. In an effort to improve short term liquidity, Rex announced two weeks ago that they would exchange debt for common shares. The deal will take some of the immediate pressure off of the company by reducing interest expense by approximately $11.1 million, but the long term solvency of the company is still in doubt barring a significant price rebound. For almost two years analysts have waited for a comeback of Rex Energy, but Shale Experts now predicts that Rex is on the verge of bankruptcy. Rex Energy exemplifies why “cheap, abundant, and profitable” can’t last in the marketplace. As Art Berman explained, shale gas enthusiasts believe that shale is “cheap, abundant, and profitable thus defying all rules of business and economics. That is magical thinking.” Valuation multiples for E&P companies operating in the Marcellus fell over the last six years as natural gas prices declined and production increased.1 There have only been five reported transactions in the Marcellus this year compared with 28 in the Permian. While no one can pinpoint when the price of oil and gas will recover, analyzing supply and demand indicators can be helpful for predicting future price movements. The supply of natural gas is not expected to ease in the near future, but a recent uptick in natural gas consumption may help ease the downward trend in prices by narrowing the gap between demand and supply.  The EIA reported that in 2015 natural gas consumption increased more than any other source of power generation and that record consumption in July of 2016 led to an increase in net withdrawals from inventories. The chart below, shared by the EIA on August 8th inToday in Energy, demonstrates that demand is starting to catch up with production. Rex Energy may not be making the comeback that analysts once forecasted, but that does not mean hope is lost for all E&P companies in the Marcellus.  The current low price environment may squeeze out some of the highly levered companies, but less aggressively financed companies, such as Antero, have an opportunity to buy inexpensive acreage and expand operations in anticipation of a more favorable pricing environment in the future.  A comeback may still be possible for the companies that can last until the price rebounds. Have value questions in the oil and gas space, as an executive, investor, owner, creditor or other interested party? Utilizing an experienced oil and gas reserve appraiser can help in understanding valuation issues in this current environment. Contact Mercer Capital to discuss your needs and learn more about how we can help you succeed. End Note1 EV/ Production multiples are based on the multiples of companies who primarily operate in the Marcellus and Utica Shale.   For more information see Mercer Capital’s E&P Index by Mineral Reserve.
Captain Obvious: Location is Key in E&P
Captain Obvious: Location is Key in E&P
I was 14, playing a golf tournament in Austin, Texas. At the time, Hole 11 gave me fits and nightmares. My strength was accuracy and short game, and my weakness was driving distance. Unfortunately, Hole 11 required the participants to carry a rather large hazard, a distance which I could achieve about once every 82 attempts. To add to my frustration, there were no lay-up options, no bail outs, and no safe shots. This situation left me with one option to survive the drive, hit the perfect shot at the perfect time for each round of the tournament. This option had a very low probability of success. As any golfer can imagine, I felt exposed, angry and stuck in a bad situation. Clearly, I did not select a tournament where the course fit my strategy.In today’s energy climate, many exploration and production companies find themselves in a similar situation. Exposed with too much debt, angry with the oil price environment and stuck selling reserve assets at prices they are forced to take because their strategy did not fit their location. For me, I did not pay attention to the layout of the course before entering the tournament. For E&P Companies, the reserves location is playing a significant role on if they can succeed in the current economic environment. For some, their "core plays" continue to produce profitably and new well investment is economic. However, for others, the cost of production is too high and they find themselves stuck in a bad situation with few options, which include selling "non-core" assets before or during bankruptcy reorganization.According to our analysis of the major shale plays in the U.S. (Permian, Eagle Ford, Marcellus, Utica and Bakken), in general the breakeven costs to produce are highest in the Bakken and lowest in the Permian. The remaining plays range between the two. Due to its lower cost structure, the Permian is gaining significantly more attention from opportunistic market participants.Deal activity, while quiet in the first quarter of the year, has picked up significantly in the last four months. In the U.S., there were 103 transactions of oil and gas resource properties with a total disclosed value of $19.7 billion, according to Shale Experts. Approximately 27% of these deals were in the Permian Basin and accounted for 25% of the total dollar volume, or $5 billion dollars. However, activity in the Permian has increased. In the last two months, deals in the Permian accounted for 35% of the transaction volume and 43% of the total dollar volume, or $3.3 Billion for June and July. Therefore, 67% of the Permian’s year to date transaction dollar volume occurred in June and July.Pioneer (PXD) has been one of the more active companies making investments in the play. Although PXD had a large presence in the Permian already, two months ago Pioneer invested $435 million in an additional 28,000 net acres by purchasing the rights from Devon Energy (DVN). According to CEO, Scott Sheffield, PXD’s motivation was protection based:"Why we are acquiring 28,000 net acres in the Midland Basin from Devon…? It's simply because it's totally integrated among our acreage. We did not want somebody to come in… most of the competition couldn't bid on this because they couldn't get longer laterals. We have it, had it totally surrounded allocated $14,000 per acre. And what’s interesting right after we made the announcement on the acquisition, somebody is paying $58,000 per acre right next to this acreage."Clearly PXD has found itself in the right location at the right economic time and is using its recent strong performance and relatively low leverage levels to be aggressive when so many of its competitors are in the weaker position or changing strategies and "core assets", including their transaction counterpart, Devon.Additionally, PXD appears to benefit from successful placement of horizontal wells within their acreage rights, high production rates and operational efficiencies. This translates into favorable cost per BOE information. As CEO Sheffield explained in the 2Q16 earnings call:"What’s amazing to me is that the horizontal well operating costs, excluding taxes, are down to almost $2 per BOE. So definitely we can compete with anything that Saudi Arabia has."While that has the power to drive headlines in the media world (confession, I believe that is how I learned about it), it also appears to be a very selective disclosure. A Forbes article written by Art Berman sheds more light on the specifics of PXD’s cost per BOE. The short of it is, overall PXD has significantly higher cost per BOE company-wide, as in $19 per BOE. However, CEO Sheffield’s comments could be read as an indication that one or more of their wells is experiencing operating costs per BOE of approximately $2.00 (excluding taxes of course and perhaps a few other selective expenses). Regardless, the intimation from the comments is that the Permian is a productive and profitable play at current prices and some wells may produce so well that it can compete with the lowest cost producers in the world. This is also supported by the transaction activity of the stronger E&P companies buying up assets from the weaker entities and the existence of drilling activity in the Permian.However, each location in the Permian is different and the "sweet spots" are just that — spots. They are not everywhere in the Permian. As a result, the valuation implications of reserves and acreage rights can swing dramatically in resource plays. Utilizing an experienced oil and gas reserve appraiser can help to understand how location impacts valuation issues in this current environment. Contact Mercer Capital to discuss your needs and learn more about how we can help you succeed.
PV-X: WACCs for E&P Companies
PV-X: WACCs for E&P Companies
In the oil and gas industry, standardized reporting and industry analysts typically use a 10% discount rate on projects’ future cash flows. In this post we explain how such a discount rate is calculated and its effects on valuation; and then discuss a model that provides the discount rates that exploration and production companies face in the current market. Exploration and production companies often use a standardized 10% discount rate in discounted cash flow analysis.  The rate appears in oil and gas companies’ reserve reports, where it is used to generate a PV-10 value (an estimate of the pre-tax discounted cash flow value of the company’s cash flows generated from its proved reserves).  This standardized discount rate also appears in other calculations where a quick, rough estimate of the present value of a project’s cash flows is needed. Having a sense of a company’s WACC, then, can lead to a more realistic assessment of the value of a company’s reserves.  Despite the prevalence of the 10% value, it is unclear how closely this discount rate aligns with reality. Even if the rate is a general benchmark for the industry as a whole, it is unclear how it varies from company to company and region to region.  Such information would help determine the oil and gas prices at which companies can justify raising funds for new drilling—at what point US drilling activity might start to recover.  The information would give investors a better sense of whether the PV-10 value is a fairly reasonable statement, an overstatement, or an understatement of value.  And for companies, it can help them in transactions to understand how they and another company might find very different value in the same reserves. There are several factors in the current market that might push the current discount rate higher or lower than the standard rate of 10%.  The first key factor is the low interest rate on government bonds.  Interest rates on debt are found by adding a credit spread based on the perceived financial health of the company to the risk-free government bond rate.  Thus when interest rates are low, the cost of borrowing is low.  Since equity investors compare the returns of the equity market to the debt market, a lower return on debt leads them to require less return on equity.   Therefore the low interest rate environment should be a strong force pushing the WACC below 10%.  At the same time, the recent volatility in oil prices has increased uncertainty and volatility in the industry, causing investors to require higher returns on investments and creating a higher cost of capital. AnalysisTo better understand the combined effect of these factors, and many others, on the cost of capital for oil and gas companies, we have analyzed WACC for seven groups of publicly traded oil and gas companies.1   We made one important assumption in our analysis—that the funding for the next project would not dramatically differ from a company’s current capital structure.  The model does not find optimal company WACCs, but attempts to estimate companies’ WACCs with their current capital structure.  With or without this assumption, finding the WACC for each company requires calculating the cost of equity and the cost of debt.  The CAPM model (required return on equity=risk-free rate + beta*equity risk premium) was used to calculate cost of equity.2We created two models, using different methodologies to calculate the cost of debt, in order to calculate the WACC. The first method of calculating the cost of debt is fairly standard for a WACC calculation.  The model multiplies the current effective interest rate (which is the interest expense divided by simple average of debt at the beginning of last twelve months and end of period) by one minus the company’s marginal corporate tax rate.The second method gives what we think of as a projected future cost of debt for long-term projects (such as oil and gas production).  It uses S&P’s company credit ratings, and S&P’s 20 year corporate bond yield curve for bonds of different ratings to assign an interest rate on new loans for a company.  The key advantage to this method is that it gives a pre-tax cost of debt based on what the debt market, or at least S&P, assumes it would cost to raise more debt, rather than generating a number based on historical rates.  However, these companies have never actually had to pay that amount for debt in the past. Because of this trade-off, the WACCs for companies were calculated using both this method and the standard WACC calculation.The Results The model’s outputs suggest that the standard 10% discount rate is a higher cost of capital than companies are actually facing in the current environment.  The unusually low government interest rates have lowered required returns so that even with the recent volatility in the industry, the oil and gas WACC is below what was once considered a reasonable standard.  However, how far off the 10% rate is depends on whether one looks at the WACC for these companies based on the standard cost of debt or the projected cost of debt using S&P ratings. A standard WACC cannot always account for the rapid rise in leverage some companies have experienced.  For companies producing primarily in North America or North American regions, the minimum standard WACC for each group is based on a company with debt representing over 80% of its capital structure. These companies have low WACCs because the calculation is based on interest rates they obtained in the past when they were less leveraged.  Now, due to falling oil prices, their equity values have shrunk and many companies’ remaining capital is mostly composed of old debt.  Therefore, that cost of capital appears quite low.  However, if the company were to try to raise new funds for a project, their current leverage—and the risk of default associated with it—would force them to pay a very high cost for either debt or equity.  Thus, using these numbers overstates the value of reserves, especially for struggling companies. A more contemporary picture of the value of companies’ proved reserves is provided by the S&P ratings based WACC.3 In the case of the Bakken, the most levered company, Halcón Resources, which by the standard measure has the lowest WAAC in the group (6.23%), now has the highest (13.15%).  This adjustment now appears particularly relevant as Halcón has filed for bankruptcy.  In the Permian, the company with the minimum WACC went from one with over 85% debt to one with only 12% debt.  At the same time, not all highly leveraged companies are automatically punished by this model and assigned the highest WACCs.  For some, this capital structure may be optimal, and other factors may bolster their S&P credit rating. The S&P rating based WACC model shows that right now a standard discount rate for North American E&P companies should be around 9.4%.  Using this rate in the Bloomberg break-even model drops the break-even price 2-3.5% depending on the area.  As for the PV-10 calculation: if it were instead a PV-9.4 calculation, those proved reserves included in the PV-10 calculation would be more valuable. Additionally, more reserves would be included in the PV- 10 calculation, as the engineers evaluating the reserves would include some reserves that were once not considered to be economically viable due to the PV-10 value.  Therefore a current PV-10 understates the present value of reserves relative to a PV-10 in periods where 10% is the average discount rate. For a more detailed discussion on the valuation process and how Mercer Capital can use its years of oil and gas valuation experience to help you, please contact a Mercer Capital professional. End Notes1 The seven groups include four groups of companies that generate over 50% of production from the Eagle Ford Shale, the Permian Basin, the Bakken, or the Marcellus Shale and Utica Shale; a group of companies having over 90% of production in North America but who are not concentrated in the previously mentioned regions; a global integrated group; and a group of global E&P companies. 2 We used the yield on twenty-year treasuries as our risk free rate. A two year Beta was used, because we feel investors considering an oil and gas company investment would base their decisions largely on what has happened since the fall in prices that began two years ago. Mercer Capital regularly reviews a spectrum of studies on the equity risk premium, as well as conducting its own study.  Most of these studies suggest that the appropriate large capitalization equity risk premium lies in the range of 4.0% to 7.0%.  The chosen equity risk premium of 5.50% represents a composite assumption which is consistent with this range. The model does not, however, apply a country specific risk premium for global companies, and so global companies’ WACCs are likely understated by the model. 3 Not all of the companies in our sample had S&P credit ratings so some were excluded from our analysis.  We ran a control group in order to test whether the exclusion of some companies would bias the model.  We estimated the ratings of companies without a rating based on the ratings received by other companies in the group with similar debt to enterprise value ratios. The results suggested the reduction in the number of companies did not significantly affect the model.
Oil and Gas Market Discussion: Part 2
Oil and Gas Market Discussion: Part 2
In May 2016, we attended a panel event discussing investment opportunities in the financially distressed oil and gas sector. The panel included a “who’s who” of oil and gas experts located in Texas. Two industry participants, two consultants, one analyst and one economist discussed the economic outlook for energy prices and then corporate strategy and investment opportunities given the economic outlook. This post, the second and last summarizing this panel discussion, will report opinions given on corporate strategy and investment opportunities. (To read more about the economic outlook please read here.)Corporate StrategyAfter discussing the price outlook, the panelists shifted the conversation to practical decision making based on our limited ability to forecast price changes. First, they looked at corporate strategy. Merger and acquisition activity has slowed. Once oil prices started to decline in mid-to-late 2014, the M&A market fell quiet for more than 12 months. This “silent period” is a normal reaction to high volatility periods. For corporations trying to make decisions for the long term, volatility creates an uncertain future, and thus an unfriendly environment for investment. However, the panelists believe the “silent period” is now reaching a breaking point as the amount of debt carried by some companies is beginning to force action. One panelist commented that while there are “no willing sellers in the market,” some transactions have occurred when a “forced seller” tries to avoid or prolong filing for bankruptcy protection.Those bankruptcies are happening more and more frequently, leading one participant to describe four types of energy companies in the market today:The “I need to restructure yesterday” company;The “In denial about restructuring” company;The “Racing to restructure” company (to be healthier when oil prices recover); andThe “Low leverage / healthy” company (looking for opportunities); By categorizing each active company in the oil and gas market into one of these four buckets, it is easier to interpret some companies’ actions, and therefore to interpret the direction of the market. This in turn enables wiser investment strategies.Investing OpportunitiesTwo areas of opportunity discussed were reserves and oil field services. A panelist who actively invests in “low risk, existing producing properties with PUD (proved undeveloped wells) rights” described the potential value of investing in reserves. In recent transactions, this particular panelist was able to pay a purchase price based only on the value of the given property’s PDPs (proved developed producing reserves). The only properties for which he may make an exception and allocate “a little” value for the non-producing areas are those located in the Permian Basin. The time horizon for this investment is definitely long term as the strategy depends on the price of oil recovering so that the PUD opportunities—which the investor pays nothing for in this current market—become valuable again. Thus, this strategy works well for experienced investors with enough cash to pull it off, such as investment funds or other E&P companies.The second investing opportunity is more easily accessible to the average retail investor than purchasing reserves. This simpler opportunity focuses on investing in “higher quality oil field service companies that live in the operating expenses of exploration and production companies.” There are a couple positives to this strategy. Since existing wells must be maintained, this strategy enables one to invest in a high quality company that receives regular business from E&P companies, while also taking advantage of the fact that most companies operating in the oil and gas sector are trading at discounted prices. Furthermore, if prices recover, more wells will be drilled and completed, and these too will need to be maintained. Thus, high quality oilfield service companies may offer low risk returns in the current environment while also offering considerable upside if oil prices increase. A market data point to monitor for this investment strategy is the drilled but uncompleted well count and the well completion count data. As discussed in the previous post, this information is more directly tied to future production than the commonly referred to rig count data, and an increase in completions will mean an increase in business for oil field services companies.SummaryOverall, this panel was a helpful reminder to stay focused on the basics during times of turmoil. Basic supply and demand factors world-wide are still driving the price of oil and gas. The only change has been the behavior of certain suppliers (OPEC) and doubts about future demand (country specific). Because of the way those changes have affected oil prices, overleveraged E&P companies will be forced to restructure their debt or be forced out of the market. After an 18 month “silent period,” more action is either expected in the near term as these debts become due. Lastly, having available, investable cash is critical in order to take advantage of certain investing opportunities in the market today. Certain strategies favor professional and institutional investors, while others can be enjoyed by retail investors. Overall, it is a very volatile time in oil and gas. The perspectives of these six experts in their respective fields provide guidance for strategy and investing in the near and long term. If you want to move forward either as a company interested in M&A activity or as an investor, utilizing an experienced oil and gas reserve appraiser can help to further lift the fog on valuation issues in this current, hazy environment. Contact Mercer Capital to discuss your needs and learn more about how we can help you succeed.
Bankruptcy: An Overview Part 3
Bankruptcy: An Overview Part 3
From January through May of this year, 39 E&P companies and 31 oilfield services companies had to file for bankruptcy. This post is the last in a series of three aimed at helping those companies, and any others who may face bankruptcy in the future, to understand the valuation-related aspects of Chapter 11 restructuring. In the first post we highlighted two reorganization requirements tied to valuation. First, the plan should demonstrate that the economic outcomes for the consenting stakeholders are superior under the Chapter 11 proceeding compared to a Chapter 7 proceeding. Second, upon confirmation by the bankruptcy court, the plan must not be likely to result in liquidation or further reorganization. In the second post we explored in depth the consequences of the first requirement. Here we examine the importance of the second requirement.Cash-Flow TestFor a company that has followed the steps explained in the previous post, this second requirement represents the last valuation hurdle to successfully emerging from Chapter 11 restructuring. Even if a company shows that the restructuring plan will benefit stakeholders more than liquidation will, the court will still reject the plan if it is likely to lead to liquidation or further restructuring in the foreseeable future. To satisfy the court, a cash-flow test is used to analyze whether the restructured company would generate enough cash to consistently pay its debts. This cash-flow test can be broken into three parts.The first step in conducting the cash-flow test is to identify the cash-flows that the restructured company will generate. These cash-flows are available to service all the obligations of the emerging entity. Remember the discussion in the second post—a stream of cash-flows is developed using the DCF method in order to determine the reorganization value. Thus, in practice, establishing the appropriate stream of cash-flows for the cash-flow test is often a straightforward matter of using these projected cash-flows in the new model.Once the fundamental cash-flow projections are incorporated, analysts then model the negotiated or litigated terms attributable to the creditors of the emerging entity. This involves projecting interest and principal payments to the creditors, including any amounts due to providers of short term, working capital facilities. These are the payments for each period that the cash-flow generated up to that point must be able to cover in order for the company to avoid another bankruptcy.The cash-flows of the company will not be used only to pay debts, and so the third and final step in the cash-flow test is documenting the impact of the net cash-flows on the entire balance sheet of the emerging entity. This entails modeling changes in the company’s asset base as portions of the expected cash-flows are invested in working capital and capital equipment; and modeling changes in the debt obligations of and equity interests in the company as the remaining cash-flows are disbursed to the capital providers. A reorganization plan is generally considered viable if such a detailed cash-flow model indicates solvent operations for the foreseeable future.ConclusionAlthough the Chapter 11 process can seem like no more than a burden, a rigorous assessment of cash-flows and a company’s capital structure can help the company as it tries to develop a plan for years of future success. We hope that these past three posts explaining the key valuation-related steps of a Chapter 11 restructuring help managers realize this potential.However, we also understand that executives of oil and gas companies going through a Chapter 11 restructuring process need to juggle an extraordinary set of additional responsibilities—evaluating alternate strategies, implementing new and difficult business plans, and negotiating with various stakeholders. Given executives’ multitude of other responsibilities, they often decide that it is best to seek help from outside, third party specialists. Valuation specialists can relieve some of the burden from executives by developing the valuation and financial analysis necessary to satisfy the requirements for a reorganization plan to be confirmed by a bankruptcy court. Specialists can also provide useful advice and perspective during the negotiation of the reorganization plan to help the company emerge with the best chance of success. With years of experience in both oil and gas, and in bankruptcy, at Mercer Capital, we are well positioned to help in both of these roles. For a confidential conversation about bankruptcy proceedings and how we can help, please contact a Mercer Capital professional.
Oil and Gas Market Discussion: Part 1
Oil and Gas Market Discussion: Part 1
Like the first few holes on an early morning golf round, the current oil and gas market is very foggy. In golf, hitting a shot into the unknown can be peaceful, enjoyable, and exciting. However, in the oil and gas market, blindly taking investment shots is downright frightening. Uncertainty on the direction of the price of oil, the cause of the historical decline, the future of demand, leverage levels of E&P companies, and the value of oil and gas assets will delay many investment decisions. In May 2016, we attended a panel event discussing investment opportunities in the financially distressed oil and gas sector. The panel included a "who’s who" of oil and gas experts located in Texas. Two industry participants, two consultants, one analyst and one economist discussed the economic outlook for energy prices; and then corporate strategy and investment opportunities given the economic outlook. This post, the first of two summarizing this panel discussion, will report on the economic discussion.Economic Outlook for Energy PricesTo no one’s surprise, the outlook for energy prices depends on forecasts of future supply and demand, and those forecasts in turn depend on predicting the timing and interaction of complex global events. On the demand side, economists do not anticipate significant change in the near term. Many economists are hesitant to project growth as others indicate a global pull back is due. Even looking only at the U.S. we can see how the way we use oil has changed in the last 40 years. Oil was used to power houses, offices, and factories in the 1970's and 1980's, but environmental pressure since then has reduced the use of oil in favor of cleaner energy. Combine the changes to the power grid with efforts to help both the environment and consumers by increasing the energy efficiency of automobiles, and it appears pressure to reduce U.S. demand for oil will continue into the future. Therefore, it is difficult to argue convincingly that an increase in foreign or domestic demand will drive near-term oil price growth.On the supply side, the world is still reacting to OPEC’s increased production, which has enabled those countries to maintain market share by driving down prices. North American production, for instance, is anticipated to continue its decline in the near term — the result of a slow-down in investment over the past year and a half as many resource plays are no longer economically viable. While wells are continuing to produce oil, completion and drilling of new wells has been delayed. As hydrocarbons are a depleting resource, anything produced must be replaced by discoveries elsewhere. Without investment to replenish reserves, depletion becomes a significant hindrance on growth as inventory and reserve levels drop. It is now a waiting game for current wells’ production to decline enough to impact inventory levels. When this happens to companies across an entire region, oil prices may rise. One traditional market indicator frequently monitored by industry participants to determine investment levels is rig count. As rig counts fall, the indication is that new production will go down; as rig counts rise, the opposite is true. However, one panelist suggested, "Rig count is not as important to measure future production as the number of drilled but uncompleted wells." As the price of oil started to decline in 2014, many drillers chose to delay the completion of their wells, hoping for a rebound in price. This price rebound has yet to happen, but the number of uncompleted wells continues to increase. Since it takes less time to complete a well than it does to drill and then complete one, it seems reasonable to assume that companies might be more capable of quickly replenishing their depleted inventories than we would think from looking at the number of rigs. This will help U.S. companies to capitalize if prices start to rise, but also will keep in check any growth in oil prices as supply will increase faster than it normally would. In a shift away from the U.S. market, the panel then emphasized that one should not develop a narrow focus on investment and that production in the U.S. International production decisions, especially those of OPEC, will continue to drive much of the change in oil price going forward. For this international sector, the economist on the panel communicated the theme: "History doesn’t repeat but it does rhyme." He explained his point by highlighting one particular period in the oil industry’s last 50 years that can help us to understand the decisions OPEC is making now. From 1978-2003, the Saudi’s acted as the swing producer in OPEC to influence prices. At the end of this time period, they learned that the swing producer ultimately loses market share. They vowed never again to act in a manner that would shrink their market share. At the time, U.S. production was dropping consistently year over year, and so people paid little attention to the change in attitude. In the mid to late 2000s, however, fracking technology helped unlock significant U.S. inventory. This new technology made the U.S. energy independent, at least as long as oil prices remained above a certain price point needed for the main resource plays to be economical. Jump forward to 2014, and everyone was "shocked" when a significant drop in the price of oil was not met with an OPEC cut in production. From the perspective of Saudi Arabia and the rest of the OPEC nations, however, they simply kept their earlier vow. Deciding to produce at the same or increased levels would better enable them to fend off challenges to their market share from countries such as the U.S. who were starting to fulfill a larger share of the world’s oil needs. Ultimately, however, the economist ended the discussion of future prices by emphasizing that while certain trends can seem clear, especially in hindsight, there are many factors that can influence oil and gas prices. While people have their opinions, no one can consistently and accurately forecast all these complex factors, and thus "no one knows where the prices of oil and gas will go." All we can really say with reasonable certainty is that the "drivers impacting the price will be similar to the past ones." Although this explanation was not "ground breaking"material, we find it helpful to be reminded of the basics during times of turmoil. In the next blog post, we will look at how one can navigate this turmoil to find successful opportunities as either an investor or a business. If you want to discuss further how the current price outlook can shape asset valuations, and how one can project value when the future is so uncertain, please contact a Mercer Capital professional.
Bankruptcy: An Overview Part 2
Bankruptcy: An Overview Part 2
From January through May of this year, 39 E&P companies and 31 oilfield services companies had to file for bankruptcy. This post is the second of three aimed at helping those companies and any others who may face bankruptcy in the future to understand the valuation-related aspects of Chapter 11 restructuring. In the first post, we highlighted two reorganization requirements tied to valuation. Here we will explore the consequences of the first of those requirements:The plan should demonstrate that the economic outcomes for the consenting stakeholders (creditors or equity holders) are superior under the Chapter 11 proceeding compared to a Chapter 7 proceeding, which provides for a liquidation of the business.A Floor Value: Liquidation ValueIf a company can no longer pay its debts and does not restructure, it will undergo Chapter 7 liquidation. Thus, this law simply mandates that Chapter 11 restructuring only be approved if it is stakeholders’ best option.   Given this understanding of the law, the first valuation step in successful Chapter 11 restructuring is assessing the alternative, liquidation value. This value will be a threshold that any reorganization plan must outperform in order to be accepted by the court.The value in liquidating a business is unfortunately not as simple as finding the fair market value, or even a book value for all the assets. The liquidation premise contemplates a sale of the company’s assets within a short period. Any valuation must account for the fact that inadequate time to place the assets in the open market means that the price obtained is usually lower than the fair market value.In general, the discount from fair market value implied by the price obtainable under a liquidation premise is directly related to the liquidity of an asset. Accordingly, valuation analysts often segregate the assets of the petitioner company into several categories based upon the ease of disposal. Liquidation value is estimated for each category by referencing available discount benchmarks. For example, no haircut would apply to cash and equivalents, while reserves, and especially PUD and unproven reserves, would likely incur significant discounts. The size of this discount can be estimated by analyzing the prices commanded by comparable properties under a similarly distressed sale scenario. For instance, as mentioned in "Bridging Valuation Gaps: Part 1," the price Samson recently paid for properties in a distressed sale equaled the reserve report value of PDP and PDNPs. The discount was so steep that the company essentially received the PUD reserves for free.Reorganization ValueOnce an accurate liquidation value is established, the next step is determining whether the company can be reorganized in a way that provides more value to a company’s shareholders than discounted asset sales. ASC 852 defines1 reorganization value as:“The value attributable to the reconstituted entity, as well as the expected net realizable value of those assets that will be disposed of before reconstitution occurs. This value is viewed as the value of the entity before considering liabilities and approximates the amount a willing buyer would pay for the assets of the entity immediately after restructuring.”Typically the “value attributable to the reconstituted entity,” the new enterprise value for the restructured business, is the largest element of the total reorganization value. Unlike a liquidation, this enterprise value falls under what valuation professionals call a “going concern” value premise. This means that the business is not valued based on what one would be paid for selling individual assets, but rather the return that would be generated by the future operations of the emerging, restructured entity. To measure enterprise value in this way, reorganization plans primarily use a type of income approach, the discounted cash-flow (DCF) method. The DCF method estimates the net present value of future cash-flows that the emerging entity is expected to generate. Implementing the discounted cash-flow methodology requires three basic elements:Forecast of Expected Future Cash-flows. Guidance from management can be critical in developing a supportable cash-flow forecast. Generally, valuation specialists develop cash-flow forecasts for discrete periods that may range from three to ten years. Conceptually, one would forecast discrete cash-flows for as many periods as necessary until a stabilized cash-flow stream can be anticipated. Due to the opportunity to make broad strategic changes as part of the reorganization process, cash-flows from the emerging entity must be projected for the period when the company expects to execute its restructuring and transition plans. Major drivers of the cash-flow forecast include projected revenue, gross margins, operating costs and capital expenditure requirements. Historical experience of the petitioner company, as well as information from publicly traded companies operating in similar lines of business can provide reference points to evaluate each element of the cash-flow forecast.Terminal Value. The terminal value captures the value of all cash-flows after the discrete forecast period. Terminal value is determined by using assumptions about long-term cash-flow growth rate and the discount rate to capitalize cash-flow at the end of the forecast period. This means that the model takes the cash flow value for the last discrete year, and then grows it at a constant rate for perpetuity. In some cases the terminal value may be estimated by applying current or projected market multiples to the projected results in the last discrete year. An average EV/EBITDA of comparable companies, for instance, might be used to find a likely market value of the business at that date.Discount Rate. The discount rate is used to estimate the present value of the forecasted cash-flows. Valuation analysts develop a suitable discount rate using assumptions about the costs of equity and debt capital, and the capital structure of the emerging entity. Costs of equity capital are usually estimated by utilizing a build-up method that uses the long-term risk-free rate, equity risk premia, and other industry or company-specific factors as inputs. The cost of debt capital and the likely capital structure may be based on benchmark rates on similar issues and the structures of comparable companies. Overall, the discount rate should reasonably reflect the business and financial risks associated with the expected cash-flows of the emerging entity. The sum of the present values of all the forecasted cash-flows, including discrete period cash-flows and the terminal value, provides an indication of the business enterprise value of the emerging entity for a specific set of forecast assumptions. The reorganization value is the sum of that expected business enterprise value of the emerging entity and proceeds from any sale or other disposal of assets during the reorganization. Since the DCF-determined part of this value relies on so many forecast assumptions, different stakeholders may independently develop distinct estimates of the reorganization value to facilitate negotiations or litigations. The eventual confirmed reorganization plan, however, reflects the terms agreed upon by the consenting stakeholders and specifies either a range of reorganization values or a single point estimate. In conjunction with the reorganization plan, the courts also approve the amounts of allowed claims or interests for the stakeholders in the restructuring entity. From the perspective of the stakeholders, the reorganization value represents all of the resources available to meet the post-petition liabilities (liabilities from continued operations during restructuring) and allowed claims and interests called for in the confirmed reorganization plan. If this agreed upon reorganization value exceeds the value to the stakeholders of the liquidation, then there is only one more valuation hurdle to be cleared. This is an examination of whether the restructuring creates a company that will be viable for a long time—that isn’t likely to be back in bankruptcy court in a few years. We will address that process in our third and final blog post of this series. If you want to learn more about the valuation side of the bankruptcy process, and how we at Mercer can use our years of experience in bankruptcy and in the oil and gas industry to help you emerge from Chapter 11 well-prepared for future success, contact one of our valuation analysts for a confidential discussion. Footnote1ASC 852-10-20.
EP Third Quarter 2016 Region Focus Bakken
E&P Third Quarter 2016

Region Focus: Bakken

Region Focus: Bakken Oil prices trended up for the beginning of the third quarter but ended the quarter about where they started.
M&A Activity in the Bakken
M&A Activity in the Bakken
Crude prices in North Dakota are even lower than the already depressed price of WTI and Brent. This is largely due to region’s insufficient pipeline network. This creates high transportation costs, and in turn decreases realized wellhead prices. As of June 15th crude oil prices in North Dakota were almost 20% lower than the price of WTI and 21% lower than the price of Brent. On top of lower revenue per barrel, the Bakken faces higher initial drilling costs than many other mineral reserves. Together these factors mean that production is not economically feasible in the current low price environment. As of June 17, even as oil prices rose to above $45 per barrel, Baker Hughes reported that there were only 24 rigs operating in North Dakota. In order to survive, when producing is no longer economically feasible, production companies are selling “non-core” assets to generate the cash.In October of 2015, Occidental Petroleum Corporation sold its Bakken Assets to Lime Rock Resources. This sale marked the first exit of the downturn by a major oil company from the Bakken Shale formation. So far, M&A activity of Bakken assets has slowed in 2016, but most Bakken assets are selling for heavy discounts making them attractive to buyers. Some other recent transactions in the Bakken are highlighted below.The sale of Emerald Oil’s Bakken assets can help us understand the current pricing environment. Emerald Oil, an independent producer in the Williston Basin, filed for Chapter 11 Bankruptcy on March 22 and was delisted from the NYSE on March 24. During this time, Emerald had entered into a deal with Latium Enterprises to sell acreage at $1,740 per acre, but the transaction fell through.   Last month, Emerald Oil announced that CL Energy Opportunity fund would buy substantially all of their assets for $73 million which equates to less than $980 per acre. This represents a 44% haircut in just two months. What we see in this case is a continuing fall in the value of acreage as investors learn that assets in the Bakken can be bought at even lower discounts if they wait for the continuation of low oil prices to put more and more pressure on distressed buyers to make a sale.   While this is a stalking horse offer, they are not likely to get much higher on the final deal. As Emerald oil became more desperate to reorganize in order to avoid Chapter 7 bankruptcy, they became more willing to sell at a lower price.Oil Prices are expected to remain low into the third quarter of this year and possibly into the second quarter of 2017. As the price of oil remains depressed, many companies avoiding bankruptcy or reorganizing through Chapter 11 will be forced to sell non-core assets in order to generate cash. In a distressed market, it is extremely important to push for the best offer possible. Mercer Capital can help you understand the true value of your assets and can help you through the Chapter 11 Process.
Bankruptcy: An Overview
Bankruptcy: An Overview
On June 20th, 2014 the price for a barrel of crude oil on the NYMEX reached $107.26. Analysts’ beginning of the year predictions, which priced oil at over $100 for the year, appeared accurate. Few if any expected oil prices to fall, and then keep falling to a dip below $30. Even with hedges in place, this unexpected, sustained price drop has crippled oil E&P revenues. Natural gas E&Ps are suffering from low prices as well. Producers have been operating in a low price environment for five years, but the last time that we saw prices this low was in 2012 during the onset of horizontal drilling. Unlike in 2012, new production and discoveries, particularly in the Marcellus and Utica, mean the oversupply is here to stay. Henry Hub prices are not expected to exceed $4 per MCF for at least 5 years. Many investments in both oil and gas that once projected to generate strong positive cash flows and profits no longer can generate enough cash to support the debts used to fund the project. Thus, as prices remain low, more and more companies are running out of cash to support once manageable debts. 42 oil and gas E&P companies went bankrupt in 2015, and 39 have declared bankruptcy from the beginning of the year to May of 2016. Oilfield services, whose business depends on these E&P companies, have experienced a similar spike in bankruptcies.For these E&P and services companies, the decision to file for bankruptcy does not have to signal the demise of the business. Despite the sense of doom often associated with the word “bankruptcy,” if executed properly Chapter 11 reorganization in fact affords these financially distressed or insolvent companies an opportunity to restructure their liabilities and emerge as sustainable going concerns. Once a petition for Chapter 11 is filed with the bankruptcy court, the company usually undertakes a strategic review of its operations, including opportunities to shed assets or even lines of businesses. During the reorganization proceeding, stakeholders, including creditors and equity holders, negotiate and litigate to establish economic interests in the emerging entity. The Chapter 11 reorganization process concludes when the bankruptcy court confirms a reorganization plan that specifies a reorganization value and that reflects the agreed upon strategic direction and capital structure of the emerging entity.In addition to fulfilling technical requirements of the bankruptcy code and providing adequate disclosure, two characteristics of a reorganization plan are germane from a valuation perspective:1The plan should demonstrate that the economic outcomes for the consenting stakeholders are superior under the Chapter 11 proceeding compared to a Chapter 7 proceeding, which provides for a liquidation of the business.Upon confirmation by the bankruptcy court, the plan will not likely result in liquidation or further reorganization. Within this context, valuation specialists can provide useful financial advice in order to:Establish the value of the business under a Chapter 7 liquidation premise.Measure the reorganization value of a business, which outlines both the haircuts required of pre-bankruptcy stakeholders and the capital structure of the emerging entity. A reorganization plan confirmed by a bankruptcy court establishes a reorganization value that exceeds the value of the company under a liquidation premise.Demonstrate the viability of the emerging entity’s proposed capital structure, including debt amounts and terms given the stream of cash-flows that can be reasonably expected from the business. To learn more about these three steps, and how Mercer Capital’s decades of experience in both oil and gas and bankruptcy valuation can bring value to the company and its stakeholders in each step, read Bridging Valuation Gaps for Undeveloped and Unproven Reserves. Footnote1Accounting Standards Codification Topic 852, Reorganizations (“ASC 852”). ASC 852-05-8.
Bridging Valuation Gaps: Part 3
Bridging Valuation Gaps: Part 3
At Mercer Capital we recognize that the low price environment is forcing many E&P companies either to sell reserves to improve their cash balance, or to reorganize through Chapter 11 restructuring. This is the third and final post in a series aimed at helping E&P companies to navigate the sale of non-core assets and bankruptcy by examining how option pricing, a sophisticated valuation technique, can be used to understand the future potential of the assets most affected by low prices, PUDs and unproven reserves. In past posts we discussed the difficulties of valuing PUDs and unproved reserves in low-price markets, and when option pricing can provide a more accurate valuation. In this third and final post we want to delve into the specifics of adapting option pricing from shares of stock to oil and gas, highlighting some of the challenges and key steps of the process.Pitfalls and Fine PrintOption pricing, most often used in valuing stock options, can incorporate factors overlooked by a traditional DCF and enable a company to show to potential buyers or stakeholders the value of PUDs and unproved reserves even in low-price environments. There are, however, key differences in PUD optionality and stock options that create limitations to the model and can make it challenging to implement. Below are some areas where keen, rigorous analysis can be critical:Observable Market. The DCF is typically the best estimate of reserve value, followed by the market approach. This relationship flips when crude prices fall. Market participants understand that prices will eventually recover while it is more difficult to show this expectation using a terminal value for the DCF because the precise date of market recovery is unknown. However, today the prices have fallen so far for so long that the market approach is no longer accurate either. The oil and gas market is operating like a department store having a going out of business sale. In these moments an option pricing method is particularly useful, as it can more fully account for the volatility of oil and gas prices—which have both year to year supply and demand changes and significant seasonal swings.Risk Quantification. We have found that oil and gas price volatility benchmarks (such as long term index volatilities) are not all-encompassing risk proxies when valuing specific oil and gas assets. If not analyzed carefully, the model can struggle to capture some critical production profile and geologic risks that could affect future cash flow streams considerably. Risks include production profile assumptions; acreage spacing; localized pricing versus a benchmark (such as Henry Hub or West Texas Intermediate Crude); and statistical “tail risk” in the assumed distribution of price movements.Sensitivity to Capital Expenditure Assumptions. Analysis of an asset or a project’s cash flows can be particularly sensitive to assumed capital expenditure costs. In assessing capital expenditure’s role as both a cash flow input and an option model input, estimations of future costs can be very challenging, but are an important assumption to measure properly as they drive much of the calculated value.Drilling Resource Availability and Service Costs. When oil and gas prices fall, the availability of drilling resources tends to rise while the costs of drilling and oilfield services often fall precipitousl These factors can create an oscillating delta in both cost and timing uncertainties as the marketplace responds by investing capital into underdeveloped reserves while the fuse burns on existing lease rights.Time to Expiration. This input can require granular analysis of field production life estimates coupled with expiring acreage rights, and then adjusted for the drilling plans of an operator. The resulting time-weighted estimate can present problems with assumption certainty. The time value of an option can increase significantly if the mineral rights are owned; unconventional resource play reserves are included; there are foreign reserves; or the reserves are held by production. In these instances, the PUD and unproved reserve option to drill can be deferred over many years, making the option more valuable by increasing the chance of market fluctuations that will make the reserves profitable.SummaryUtilization of modified option theory is not in the conventional vocabulary of many oil patch dealmakers, but the concept is considered among E&P executives as well during transactions in non-distressed markets. This application of option modeling becomes most relevant near the bottom of historic cycles for a commodity. If the right to drill can be postponed for an extended period of time, (i.e. five to ten years), the time value of the out-of-the-money drilling opportunities can have significant worth in the marketplace.We caution, however, that there are limitations in the model’s effectiveness. Specific and careful applications of assumptions are needed, and even then Black Sholes’ inputs do not always capture some of the inherent risks that must be considered in proper valuation efforts. Nevertheless, option pricing can be a valuable tool if wielded with knowledge, skill, and good information, providing an additional lens to peer into a sometimes murky marketplace. Today’s marketplace is particularly murky, and an accurate appraisal is extremely valuable since establishing reasonable and supportable evidence for PUD, probable, and possible reserve values may assist in a reorganization process that determines the survival of a company. Given these conditions we feel that the benefits of using option pricing far outweigh its challenges.Mercer Capital has significant experience valuing assets and companies in the energy industry, primarily oil and gas, bio fuels and other minerals. Contact a Mercer Capital professional today to discuss your valuation needs in confidence.
Bridging Valuation Gaps: Part 2
Bridging Valuation Gaps: Part 2
The current low price environment is affecting the finances of many E&P companies. At Mercer Capital we recognize that whether companies are looking to sell reserves to improve their cash balance, or are trying to generate reorganization cash flow projections during a Chapter 11 restructuring, understanding how to value PUDs and unproven reserves is crucial to survival in a down market.Option PricingOne of the primary challenges for industry participants when valuing and pricing oil and gas reserves is addressing PUDs and unproven reserves. As discussed in the first post of this installment, if one relied solely on the market approach many of these unproven reserves would be deemed worthless. Why then, and under what circumstances, might the unproven reserves have significant value?The answer lies within the optionality of a property’s future DCF values. In particular, if the acquirer has a long time to drill, one of two forces come into play: either the PUDs potential for development can be altered by fluctuations in the current price outlook for a resource, or, as seen with the rise of hydraulic fracturing, drilling technology can change driving significant increases in the DCF value of the unproven reserves.This optionality premium or valuation increment is typically most pronounced in unconventional resource play reserves, such as coal bed methane gas, heavy oil, or foreign reserves. This is additionally pronounced when the PUDs and unproven reserves are held by production. These types of reserves do not require investment within a fixed short timeframe.Current Pricing Environment: Challenge = OpportunityAs oil prices have dropped—the high WTI price over the past six months was under $50 and the low under $30—PUD values may drop from 75 cents on the dollar to 20 cents on the dollar or less. After the last Recession, some PUDs faced a similar, yet more modest, decline in prices. The price level recovery for PUDs in 2011 was partly attributable to the recovery in the U.S. and global economies, and partly due to increases in the price of oil. Valuation would be made easier if we could determine when oil prices would rise again. Let us look then to see what might change prices going forward. The consensus is that five main factors have significantly increased the world supply of oil and driven down prices: The continued success of shale drillers in the U.S.OPEC’s choice to increase and hold production levels.The U.S.’s elimination of restrictions on crude oil exports.The recent lifting of Iran’s sanctions and the anticipation of additional supply from war-torn countries of Libya and IraOil consumption slowing down in countries like China. While this sounds promising, we must remember the crash in oil prices in 1985 that remained below $20 until 2003. Every analyst has a best guess of what will happen, but there are simply too many variables involved in shifting oil prices to make accurate forecasts. Changes in any of the five drivers of low oil listed above could dramatically impact oil prices; and some of those drivers, such as the relationship between Iran and Saudi Arabia or China’s growth—contain thousands of variables that make them almost impossible to predict. In addition to all these considerations, the potential for technological changes creates another unpredictable component. A common solution in DCF models is to use the NYMEX WTI futures to project price. However, studies show that, even though buyers are estimating the value of this option into the prices they are willing to pay, this too is not a very accurate predictor of the future. When NYMEX forecasts $35 per barrel it could actually be $45 when that future date rolls around. Experienced dealmakers realize that the NYMEX future projections amount to informed speculation by analysts and economists which that many times vary widely from actual results. Note in the chart above how much the future forecasted prices changed in only one year. So what actions do acquirers take when values are out of the money in terms of drilling economic wells? Why do acquirers still pay for the non-producing and seemingly unprofitable acreage? In many cases they are following an options framework. Real Options: Valuation FrameworkPUDs are typically valued using the same DCF model as proven producing reserves after adding in an estimate for the capital costs (capital expenditures) to drill. Then the pricing level is adjusted for the incremental risk and the uncertainty of drilling “success,” i.e., commercial volumes, life and risk of excessive water volumes, etc. This incremental risk could be accounted for with either a higher discount rate in the DCF, a RAF or a haircut. Historically, in a similar oil price environment as we face today, a raw DCF would suggest little or no value for the PUDs or unproven reserves.In practice, undeveloped acreage ownership functions as an option for reserve owners; they can hold the asset and wait until the market improves to start production. Therefore an option pricing model can be a realistic way to guide a prospective acquirer or valuation expert to the appropriate segment of market pricing for undeveloped acreage. This is especially true at the bottom of the historic pricing range occurring for the natural gas commodity currently. This technique is not a new concept as several papers have been written on this premise. Articles on this subject were written as far back as 1988 or perhaps further, and some have been presented at international seminars.The PUD and unproved valuation model is typically seen as an adaptation of the Black Scholes option model. It is most accurate and useful when the owners of the PUDs have the opportunity, but not the requirement, to drill the PUD and unproven wells and the time periods are long, (i.e. five to 10 years). The value of the PUDs thus includes both a DCF value, if applicable, plus the optionality of the upside driven by potentially higher future commodity prices and other factors. The comparative inputs, viewed as a real option, are shown in table below. When these inputs are used in an option pricing model the resulting value of the PUDs reflects the unpredictable nature of the oil and gas market. This application of option modeling becomes most relevant near the bottom of historic cycles for a commodity. In a high oil price environment adding this consideration to a DCF will have little impact as development is scheduled for the near future and the chances for future fluctuations have little impact on the timing of cash flows. At low points, on the other hand, PUDs and unproved reserves may not generate positive returns and thus will not be exploited immediately. If the right to drill can be postponed for an extended period of time, (i.e. five to ten years), those reserves still have value based on the likelihood they will become positive investments when the market shifts at some point in the future. In the language of options, the time value of the out-of-the-money drilling opportunities can have significant worth. This worth is not strictly theoretical either, or only applicable to reorganization negotiations. Market transactions with little or no proven producing reserves have demonstrated significant value attributable to non-producing reserves, demonstrating the recognition by some buyers of this optionality upside. All that said, there are some challenges and dangers in applying the options model to reserves. These issues will be covered in part three of this series. To learn more about option pricing, and whether it could help your company reach optimal results either in sales or bankruptcy negotiations, please contact Mercer Capital. Conversations are in confidence, and our experts combine decades of experience in both oil and gas and bankruptcy to help you succeed.
Bridging Valuation Gaps: Part 1
Bridging Valuation Gaps: Part 1
Due to a precipitous drop in oil prices since June 2014, oil exploration and production companies in the U.S. have struggled to pay their debts and in many cases have had to file for bankruptcy. This is the first post in a three part series examining how option pricing, a sophisticated valuation technique, can be used to understand the future potential of the assets most affected by low prices, PUDs and unproven reserves. Whether companies are looking to sell these reserves to improve their cash balance, or are trying to generate reorganization cash flow projections during a Chapter 11 restructuring, understanding how to value PUDs and unproven reserves is crucial to survival in a down market.This first post looks at the traditional DCF valuation method and market approach method and how they underestimate value in down markets. The subsequent two sections will focus on one potential method to use in place of the DCF, the option pricing method, and will explore both its advantages in down markets and the dangers of adopting option pricing models for oil and gas.The Problem: Traditional Valuation in Distressed MarketsThe petroleum industry was one of the first major industries to widely adopt the discounted cash flow (DCF) method to value assets and projects—particularly oil and gas reserves. These techniques are generally accepted and understood in oil and gas circles to provide reasonable and accurate appraisals of hydrocarbon reserves. When market, operational, or geological uncertainties become challenging, such as in today’s low price environment, the DCF can break down in light of marketplace realities and “gaps” in perceived values can appear.While DCF techniques are generally reliable for proven developed reserves (PDPs), they do not always capture the uncertainties and opportunities associated with the proven undeveloped reserves (PUDs) and particularly are not representative of the less certain upside of possible and probable (P2 & P3) categories. The DCF’s use of present value mathematics deters investment at low ends of pricing cycles. The reality of the marketplace, however, is often not so clear; sometimes it can be downright murky.In the past, sophisticated acquirers accounted for PUDs upside and uncertainty by reducing expected returns from an industry weighted average cost of capital (WACC) or applying a judgmental reserve adjustments factor (RAF) to downward adjust reserves for risk. These techniques effectively increased the otherwise negative DCF value for an asset or project’s upside associated with the PUDs and unproven reserves.At times, market conditions can require buyers and sellers to reconsider methods used to evaluate and price an asset differently than in the past. In our opinion, such a time currently exists in the pricing cycle of oil reserves, in particular to PUDs and unproven reserves. In light of oil’s low price environment, coupled with the forecasted future price deck, many, if not most, PUDs appear to have a negative DCF value.Some non-core asset transactions in today’s market seem to concur with this assessed zero value for all categories of unproven reserves and PUDs. An example of this is Samson Oil and Gas’s recent purchase of 41 net producing wells in the Williston Basin in North Dakota and Montana. The properties produce approximately 720 BOEPD, and contain estimated reserves of 9.5 million barrels of oil equivalent. Samson paid $16.5 million for the properties in early January 2016 and estimates that within five years they can fund the drilling of PUDs. Samson’s adjusted reserve report, using market commodity prices at the time of the transaction, indicated PDP reserves worth $15.5 million, PDNPs worth $1 million, and PUDs worth $35 million—a total of $52 million in reserves present valued at 10%. This breakdown indicates dollar for dollar value was given on the PDP and PDNP reserves, but zero cash value given on the PUDs.Significant decline and volatility in oil prices from (1) uncertain future demand and (2) current excess supplyDebt level pressures with (1) loan covenant requirements and (2) cash flow requirementsA low deal volume environment as market participants have been in a “wait and see” stance since oil prices began declining over twelve months ago. Essentially there are few buyers in the current market place and many sellers desperate for cash. Since those sellers need cash quickly to sustain their business, they have to lower their asking prices to levels that will continuously attract bidders. The gap between an asset’s sale value and what it is worth to the new asset holder widens considerably. What does this mean for the E&P companies looking to reorganize under a Chapter 11 Bankruptcy? There are five key concepts for management teams and their advisors to be familiar with to understand how reserve valuation impacts Chapter 11 reorganization.Liquidation vs. Reorganization. The proposed reorganization plan must establish a “reorganization value” that provides superior outcomes for shareholders relative to a Chapter 7 liquidation proceeding.Liquidation Value. This premise of value assumes the sale of all of the company’s assets within a short period of time. Different types of assets might be assigned different levels of discounts (or haircuts) based upon their ease of disposaReorganization Value. As noted in ASC 852, Reorganizations, reorganization value “generally approximates the fair value of the entity before considering liabilities and approximates the amount a willing buyer would pay for the assets of the entity immediately after the restructuring.” Reorganization values are typically based on discounted cash flow (DCF) analyses.Cash-Flow Test. A cash-flow test examines the viability of a reorganization plan, and should be performed in order to determine the solvency of future operations. In practice, this test involves projecting future payments to creditors and other cash flow requirements including investments in working capital and capital expenditures.Fresh-Start Accounting. Upon emergence from bankruptcy, fresh-start accounting may be required to allocate a portion of the reorganization value to specific identifiable intangible assets such as tradename, technology, or customer relationships. Fair value measurement of these assets typically requires use of the multi-period excess earnings method or other techniques often used in purchase price allocations following a business combination. If recent market transactions are utilized to establish a liquidation value, then it stands to reason that very little, if any, value will be given to the PUD reserves. For a company trying to avoid liquidation in a distressed market where sale prices do not indicate true value, there may still be a way to show significant value if reserves are retained in reorganization. However, that reorganization value has typically been based on a DCF. It is possible that the DCF may capture significant value in PUD reserves, because in reorganization debt levels are adjusted. When debt levels are adjusted the cash flow PUD reserves need to generate to be viable is much lower. This will provide two significant benefits: more time and possibly more cash. More time may allow the global oil and gas prices to increase while the additional cash flow from lower interest payments may allow investment in future PUD wells. Unfortunately, it is still the case that the present value calculation is strongly tied to current market conditions, and thus even for companies with reasonable leverage, many PUD and unproven reserves show negative cash flow. The presence of some sizable transactions made without significant PDPs shows that there are buyers who disagree with this assessment and see value in these reserves. The issue is demonstrating that value in either a sale or bankruptcy negotiation. An option pricing model is one solution that more accurately accounts for the value of the increased time provided by restructuring the debt. In the next two posts we will look at times when option pricing may be a better model, and examine its potential issues. For a more detailed explanation of bankruptcy, DCF methods, or option pricing, please contact one of our valuation experts.
How Sweet It Was
How Sweet It Was
In 2015 the United States consumed over 3.6 billion gallons of tea. There’s nothing like a cold glass of sweet tea on a hot day in Memphis, where the average humidity is over 80%. But too many glasses of sweet tea leads to a sugar crash that makes you feel worse than before.Until December, the amount of sweet light crude in the U.S. almost exceeded the amount sweet tea at any Southern picnic. The Shale revolution changed the domestic oil and gas industry. As the stockpiles of sweet light crude increased, and the price of WTI fell, refiners purchased cheap crude in the domestic market. Until December 2015, refiners could buy domestic crude in the U.S. at a price approximately 10% cheaper than the rest of the world, sell refined products in the global petroleum market where prices were dictated by world demand and supply, and realize juicy margins. While the oversupply of sweet crude was at first a blessing for refiners, their sugar crash may be a permanent one.Brent WTI SpreadThe shale revolution, in conjunction with the export ban, created an oversupply of light, sweet crude in the U.S., which put downward pressure on the price of domestic crude oil. This pressure can be seen by examining the WTI – Brent oil price spread. One year ago the European benchmark, Brent crude, sold for $6.33 more than its American counterpart, WTI. The lifting of the export ban has narrowed the Brent WTI spread to less than $1 per barrel today.Refiner Marker MarginThe refiner marker margin (RMM) is a general indicator, calculated quarterly by BP, which shows the estimated profit refiners earn from refining one barrel of crude. Refiners’ margins increased dramatically in the second and third quarters of 2015 as the price of crude fell and the price of refined petroleum products remained high. Refiners in the U.S. were on average making $25 per barrel of oil, while global profit margins barely reached $20 per barrel.Refiners anticipated crude oil exports would increase when the export ban was lifted which reduced excess supply in the U.S. and relieved the downward pressure on market prices. Once the price of crude increased in the U.S., refiners profit margins shrink. As you can see in the graph below, profits shrank as expected. But with falling crude prices worldwide, the compression of downstream margins cannot be explained by the story refiners expected. If the export ban had been lifted in early 2014, before global crude prices started falling, the story would have played out as expected. However, when the export ban was lifted, the U.S. producers were then open to compete in a market which was swimming in crude oil. At year end, there were approximately three billion barrels of excess supply inventory across the globe. No one wanted our excess crude. Exxon Mobil’s downstream earnings were down 67% from this time last year to $187 million for the three months ended March 31, 2016. The reduced downstream margin is driving much of that change, as the company attributes $470 million of their drop in revenue from Q4 2015 to Q1 2016 to this falling margin. On their most recent earnings call VP of Investor relations explained that in order to understand refiner’s current situation, you have to look at the macro level of supply and demand. Thus decline in downstream profits was a result of excess global supply and the decreasing price of petroleum products around the globe. The export ban was lifted and U.S. raw crude oil exports initially declined relative to last year. U.S. Crude exports were down 26% in January and 13% February compared to the previous year. However, as the price of oil rebounded slightly, we have seen a 22% year over year increase in crude oil as of March 2016. When the market readjusts and crude prices rise, E&P profits may increase back to what they were, however refiners may never see the same fat margins they used to as they are now operating in a global market place. Refiners may have to adjust to a new normal. What Does This Mean for Valuation?While E&P companies have been struggling for over twelve months now in the current low price environment, refiners are just starting to feel the pressure. Although the valuation implications are not expected to be as extreme, we expect to see similar valuation issues in upcoming months as we have seen for E&P companies over the last year. As margins compress and cash flows decrease, valuation multiples are expected to fall.Mercer Capital has been valuing oil and gas companies for over 20 years. We understand the volatility of the oil and gas market and can help your company understand the value of your company beyond this year’s cash flows.
The Oil and Gas Shift is Impacting the Industry in a Few Key Areas
The Oil and Gas Shift is Impacting the Industry in a Few Key Areas
Anybody who has been to a gas pump in the last several months can tell you that the energy industry is currently in the throes of change. Prices are falling to lows that they haven’t seen in almost a decade and the industry itself is being impacted in a large number of different ways. The changing face of economics and the marketplace has presented an entirely new set of challenges that businesses will have to adapt to in order to thrive well into the future.The Changing Face of Economics and the MarketplaceAnother significant change that will impact the oil and gas industries in 2015 and beyond has to do with current market fluctuations that will affect profitability. It’s no secret that oil prices started plummeting in 2014 and show no signs of slowing down. Bernstein Research, for example, estimates that a full 1/3 of all shale projects in the United States become unprofitable once prices fall below $80.This is a case-by-case basis, however, and is not blanket fact. The Bakken formation in North Dakota, for example, will still be profitable so long as prices do not fall below $42 per barrel – according to the IEA. ScotiaBank’s own research indicates that prices have to stay between $60 to $80 per barrel for the Bakken formation to remain profitable.Changes in Production and DemandA large part of the reason why oil prices are continuing to fall has to do with two other significant changes that are impacting the industry: namely, changes to the total amount of oil that the United States and Canada are producing, as well as changes to the demand for oil in areas of the world like Europe and Asia.According to the International Energy Agency (also commonly referred to as the IEA), shale production in the United States is expected to shift dramatically in the coming years. In scenarios both where oil prices remain roughly where they are and where they continue to fall even farther, the IEA predicts that shale production will still continue to grow, just at a much slower rate than it has been in the last several years. To put that into perspective, production is still expected to increase an additional 950,000+ barrels per day throughout the entirety of 2015.Another important factor to consider has to do with infrastructure with regards to existing investments. There are a large number of energy companies that have already paid a great deal of money purchasing land, obtaining necessary permits and performing other tasks necessary to drilling. Even if oil prices continue to fall, these companies can’t necessarily curb back on their production or they fear losing an even greater investment than initially feared. In these types of situations, the true “break even” price in production varies depending on the operator and their tolerance versus the amount of debt that they’ve taken on. Even still, it may be too early to tell in many cases how firm those tolerances really are.The boom in increased oil production in the United States and Canada has created something of a tricky situation for the industry as a whole. After sinking a huge amount of money into infrastructure over the last several years, businesses now have to contend with falling prices that show no signs of slowing down. In order to adapt they will have to look for ways to embrace new technology and streamline production in order to stay profitable well into the future and to break through into a bold new era for the industry as a whole.This article was originally published in Valuation Viewpoint, January 2015.
Bridging Valuation Gaps for Undeveloped and Unproven Reserves
Bridging Valuation Gaps for Undeveloped and Unproven Reserves
The petroleum industry was one of the first major industries to widely adopt the discounted cash flow (DCF) method to value assets and projects—particularly oil and gas reserves. These techniques are generally accepted and understood in oil and gas circles to provide reasonable and accurate appraisals of hydrocarbon reserves. When market, operational, or geological uncertainties become challenging, however, such as in today's low price environment, the DCF can break down in light of marketplace realities and "gaps" in perceived values can appear.While DCF techniques are generally reliable for proven developed reserves (PDPs), they do not always capture the uncertainties and opportunities associated with the proven undeveloped reserves (PUDs) and particularly are not representative of the less certain upside of possible and probable (P2 &P3) categories. The DCF's use of present value mathematics deters investment at low ends of pricing cycles. The reality of the marketplace, however, is often not so clear; sometimes it can be downright murky.In the past, sophisticated acquirers accounted for PUDs upside and uncertainty by reducing expected returns from an industry weighted average cost of capital (WACC) or applying a judgmental reserve adjustments factor (RAF) to downward adjust reserves for risk. These techniques effectively increased the otherwise negative DCF value for an asset or project's upside associated with the PUDs and unproven reserves.At times, market conditions can require buyers and sellers to reconsider methods used to evaluate and price an asset differently than in the past. In our opinion, such a time currently exists in the pricing cycle of oil reserves, in particular to PUDs and unproven reserves. In light of oil’s low price environment, coupled with the forecasted future price deck, many—if not most—PUDs appear to have a negative DCF value.Distressed MarketsIn the past, we have analyzed actual market transactions to show that buyers still pay for PUDs and unproven reserves despite a DCF that results in little or no value. In today’s market, however, asset transactions of “non-core assets” indicate zero value for all categories of unproven reserves. A highlighted example of this is Samson Oil and Gas’s recent purchase of 41 net producing wells in the Williston Basin in North Dakota and Montana. The properties produce approximately 720 BOEPD and contain estimated reserves of 9.5 million barrels of oil equivalent. Samson paid $16.5 million for the properties in early January 2016 and estimates that within five years they can fund the drilling of PUDs. Samson’s adjusted reserve report, using the most current market commodity prices, indicated PDP reserves worth $15.5 million, PDNPs worth $1 million and PUDs worth $35 million—a total of $52 million in reserves present valued at 10%. This breakdown indicates dollar for dollar value was given on the PDP and PDNP reserves, but zero cash value given on the PUDs.Is this transaction the best indication of fair market value or fair value?We believe there is a convincing argument to be made that the Samson transaction and a handful of other asset deals in the previous six months are not the best indication of asset value. In short, these sales could be categorized as distressed or “fire sale” transactions for the following reasons:Significant decline and volatility in oil prices from (1) uncertain future demand and (2) current excess supply.Debt level pressures with (1) loan covenant requirements and (2) cash flow requirements.The low deal volume environment as market participants have been in a “wait and see” stance since oil prices began declining over twelve months ago. In this low price environment, buyers don’t have to blink first. These factors indicate that some companies may feel pressure to lower their asking prices to levels that continuously attract bidders. The market looks distressed. What does this mean for the fair market value/fair value of oil and gas assets? The definitions of fair market value and fair value require buyers and sellers to operate in a “distress-free” environment. When the marketplace is not distress-free, perhaps non-market methods should be utilized to estimate the real value of PUDs and unproven reserves. In these scenarios, one useful method to price these assets is the use of option theory.Option PricingIf one solely relied on the market approach, it appears much of these unproven reserves would be deemed worthless. Why then, and under what circumstances, might the unproven reserves have significant value?The answer lies within the optionality of a property's future DCF values. In particular, if the acquirer has a long time to drill, one of two forces come into play: either (1) the current price outlook can change radically for a resource, and subsequently alter the PUDs or (2) drilling technology can change, such as the onslaught of hydraulic fracturing, and the unproven reserves accrue significant DCF value.This optionality premium or valuation increment is typically most pronounced in unconventional resource play reserves, such as coal bed methane gas, heavy oil, or foreign reserves. This is additionally pronounced when the PUDs and unproven reserves are held by production. These types of reserves do not require investment within a fixed short timeframe.Current pricing environment: challenge = opportunityOne of the primary challenges for industry participants when valuing and pricing oil and gas reserves is addressing PUDs and unproven reserves. As oil prices have dropped over 50% in the last six months, reaching 12 year lows, it should be anticipated that PUD values may drop from 75 cents on the dollar to 20 cents on the dollar or less. After the Great Recession, some PUDs faced a similar, yet more modest, decline in price. The price level recovery for PUDs in 2011 was partly attributable to the recovery in the U.S. and global economies, and partly due to increases in the price of oil. Five main factors have significantly increased the world supply of oil and driven down prices: The continued success of shale drillers in the U.S.OPEC’s choice to continue to increase production.The U.S.’s elimination of restrictions on crude oil exports.The recent lifting of Iran’s sanctions.Oil consumption slowing down in countries like China. In August of 2015, it was estimated that Iran’s return to the global oil market would add approximately one million barrels of oil a day to the market and decrease the price of oil by $10 per barrel. Iran is currently ready to increase exports by half a million barrels of oil per day, and the fear of further over-supply pushed the price of oil below $30 on Friday, January 15. Now, the question is when will oil prices recover? The Chief of the IEA estimated that oil prices will recover in 2017. Prices are predicted to remain low in 2016 as expected demand for oil is growing at lower rates than in the past thanks to economic slowdowns in China, India, and Europe. However, the growth in oil supply is predicted to slow in 2017 as the current cuts in research and development catch up with many exploration and production companies. We must also remind ourselves of the crash in oil prices in 1985 that remained below $20 until 2003. As previously mentioned, PUDs are typically valued using the same DCF model as proven producing reserves after adding in an estimate for the capital costs (capital expenditures) to drill. Then the pricing level is adjusted for the incremental risk and the uncertainty of drilling “success,” i.e., commercial volumes, life and risk of excessive water volumes, etc. This incremental risk could be accounted for with either a higher discount rate in the DCF, a RAF or a haircut. Historically, in a similar oil price environment as we face today, a raw DCF would suggest little or no value for the PUDs or unproven reserves. Interestingly, market transactions with similar reserves (i.e., with little or no proven producing reserves) have demonstrated significant amounts attributable to non-producing reserves, thus demonstrating the marketplace's recognition of this optionality upside. Studies have shown that NYMEX futures are not a very accurate predictor of the future, and yet buyers are estimating the value of this option into the prices they are willing to pay. When NYMEX forecasts $35 per barrel, it could actually be $45 when that future date rolls around. So what actions do acquirers take when values are out of the money in terms of drilling economic wells? Why do acquirers still pay for the non-producing and seemingly unprofitable acreage? Experienced dealmakers realize that the NYMEX future projections amount to informed speculation by analysts and economists which many times vary widely from actual results. Note in the chart above how much the future forecasted prices changed in only one year. Real Options: Valuation FrameworkIn practice, undeveloped acreage ownership functions as an option for reserve owners; therefore, an option pricing model can be a realistic way to guide a prospective acquirer or valuation expert to the appropriate segment of market pricing for undeveloped acreage. This is especially true at the bottom of the historic pricing range occurring for the NG commodity currently.This technique is not a new concept as several papers have been written on this premise. Articles on this subject were written as far back as 1988 or perhaps further, and some have been presented at international seminars.The PUD and unproved valuation model is typically seen as an adaptation of the Black Scholes option model. An applicability signal for this method is when the owners of the PUDs have the opportunity, but not the requirement, to drill the PUD and unproven wells and the time periods are long, i.e. five to 10 years. The value of the PUDs thus includes both a DCF value, if applicable, plus the optionality of the upside driven by potentially higher future commodity prices and other factors. The comparative inputs, viewed as a real option, are shown in table below.Pitfalls and fine printThere are, of course, key differences in PUD optionality and stock options as well as limitations to the model. Amid its usefulness, the model can be challenging to implement. Below are some areas in particular where keen rigorous analysis can be critical:Observable market – Unlike a common stock, there is no direct observable market price for PUDs. The inherent value of a PUD is the present value of a series of cash flows or market pricing for proven reserves, if available. All commodity prices are volatile, but oil and gas prices are more volatile than most since they have both year-to-year supply and demand changes in addition to significant seasonal swings.Risk quantification – We have found that oil and gas price volatility benchmarks (such as long term index volatilities) are not all-encompassing risk proxies when valuing specific oil and gas assets. If not analyzed carefully, the model can sometimes have trouble capturing some critical production profile and geologic risks that could affect future cash flow streams considerably. Risks can include items such as (1) production profile assumptions; (2) acreage spacing; (3) localized pricing versus a benchmark (such as Henry Hub or West Texas Intermediate Crude); and (4) statistical “tail risk” in the assumed distribution of price movements.Sensitivity to capital expenditure assumptions – Underlying analysis of an asset or a project’s economics can present particular sensitivity to assumed capital expenditure costs. In assessing capital expenditure’s role as both (1) a cash flow input and (2) an option model input, estimations of future costs can be very acute, yet challenging, assumptions to properly measure.Time to expiration – This input can require granular analysis of field production life estimates coupled with expiring acreage, then filtered within the drilling plans of an operator. The resulting weighted time estimate can present problems with assumption certainty. The availability of drilling resources tends to decline while the costs of drilling and oilfield services tend to rise, often precipitously, when oil and gas prices rise. These factors can present an oscillating delta in both cost and timing uncertainties as the marketplace responds by investing capital into underdeveloped reserves while the fuse burns on existing lease rights. The time value of an option can increase significantly if (1) the mineral rights are owned; (2) unconventional resource play reserves are included; (3) there are foreign reserves; or (4) the reserves are held by production. In these instances, the PUD and unproved reserve option to drill can be deferred over many years, thereby extending the option.SummaryUtilization of modified option theory is not in the conventional vocabulary among many oil patch dealmakers, but the concept is clearly implicitly considered (as evidenced in many market transactions). This application of option modeling becomes most relevant near the bottom of historic cycles for a commodity. Here, the DCF will often yield little or no value even though transactions are being made for substantial values, thereby validating our belief that option theory is being utilized in the marketplace either directly or indirectly. If the right to drill can be postponed an extended period of time, i.e. five to ten years, the time value of those out of money drilling opportunities can have significant worth in the marketplace.We caution, however, that there are limitations in the model’s effectiveness. Black Sholes’ inputs do not always capture some of the inherent risks that must be considered in proper valuation efforts. Specific and careful applications of assumptions are musts. Nevertheless, option pricing can be a valuable tool if wielded with knowledge, skill, and good information, providing an additional lens to peer into a sometimes murky marketplace.Mercer Capital has significant experience valuing assets and companies in the energy industry, primarily oil and gas, bio fuels and other minerals. Contact a Mercer Capital professional today to discuss your valuation needs in confidence.
EP First Quarter 2016 Region Focus Eagle Ford
E&P First Quarter 2016

Region Focus: Eagle Ford

Region Focus: Eagle Ford The collapse of oil prices in late 2014 had immediate effects on the exploration and production industry.
EP Second Quarter 2016 Region Focus Permian Basin
E&P Second Quarter 2016

Region Focus: Permian Basin

Region Focus: Permian Basin After collapsing in late 2014, oil prices reached historic lows in the first quarter of 2016 but have since started to show signs of recovery.
Refining Second Quarter 2016 Refining Overview
Refining Second Quarter 2016

Refining Overview: The refining industry is surrounded by uncertainty.  Refiners’ inputs and products are both commodities, which means that the price they pay for inputs and the prices they receive for their products are generally determined by the market.

Refining Overview: Permian Basin After collapsing in late 2014, oil prices reached historic lows in the first quarter of 2016 but have since started to show signs of recovery.
Third Quarter 2015
Third Quarter 2015

Value Focus: Energy

As the 4th quarter begins, uncertainty is rife within the Exploration and Production (E&P) industry.
First Quarter 2015 Energy Industry Sector Focus Exploration Production
First Quarter 2015 Energy Industry

Sector Focus: Exploration & Production

Sector Focus: Exploration & Production: In 2015, oil and gas exploration & production activities in the US are expected to generate $320.0 billion in revenue.
Fourth Quarter 2014 Energy Industry Sector Focus Oilfield Services Equipment
Fourth Quarter 2014 Energy Industry

Sector Focus: Oilfield Services & Equipment

Sector Focus: Oilfield Services & Equipment: In 2014, the oilfield services & equipment industry is expected to generate $133.6 billion in revenues in the United States.
Third Quarter 2014 Energy Industry Sector Focus Alternative Energy
Third Quarter 2014 Energy Industry

Sector Focus: Alternative Energy

In 2013, energy from renewable sources represented just under 10% of U.S. energy consumption.
First Quarter 2014 Energy Industry Sector Focus Exploration Production
First Quarter 2014 Energy Industry

Sector Focus: Exploration & Production

In 2013, the oilfield services & equipment industry generated an estimated $131.7 billion in revenues in the United States.
Fourth Quarter 2013 Energy Industry Sector Focus Oilfield Services Equipment
Fourth Quarter 2013 Energy Industry

Sector Focus: Oilfield Services & Equipment

In 2013, the oilfield services & equipment industry generated an estimated $131.7 billion in revenues in the United States.
Out of the File Cabinet: The Ideal Time to Review Your Buy-Sell Agreement
Out of the File Cabinet: The Ideal Time to Review Your Buy-Sell Agreement
Almost every privately owned company with multiple shareholders has a buy-sell agreement (or other agreement that acts as a buy-sell agreement).If your business is like most companies, then you have one too. You likely had an attorney draft the document for you several years ago. You and your fellow shareholders might have had some discussions about the specifics of the buy-sell language at the time, but these discussions were likely minimal. You then signed the document, put it in a file cabinet in the office and have not looked at it or thought much about it since.True? Well, this might be an extreme example, but it highlights an important issue – most business owners do not have a current understanding of the details and potential pitfalls that lurk within their own buy-sell agreements. Most view these agreements as obligatory legal documents that can be forgotten about until needed. Unfortunately, when a buy-sell agreement is needed it is too late to fix any problems within the agreement.For the past several years, Chris Mercer, the CEO of Mercer Capital, has used the image of a ticking time-bomb as a metaphor of what might be awaiting some business owners within their buy-sell agreements. Would you ignore an actual bomb that was ticking away in your file cabinet? Of course not, and you should not ignore your buy-sell agreement either.The Ideal Time to Review Your Buy-Sell AgreementThe time for a comprehensive review of your buy-sell agreement is not this year or this month – it is right now. You have finished the first quarter of the year. Make it a priority now to get your buy-sell agreement out of that file cabinet and review it with your partners and appropriate professional advisors.Things to Look for When Reviewing Your Buy-Sell AgreementAs you review your buy-sell agreement, it is important to understand what the document is and what it is intended to accomplish.Buy-sell agreements are legal documents, but they are also business and valuation documents. These agreements govern how ownership will change hands if and when something significant, often called a trigger event, happens to one or more of the shareholders. Buy-sell agreements are intended to ensure the remaining owners control the outcome during critical transitions. They do this by specifying what happens to the ownership interest of a fellow owner who dies or otherwise departs the business, and mandating that a departing owner be paid, hopefully reasonably, for his or her interest in the business.Some buy-sell agreements call for fixed pricing or value the shares based on a set formula, while others lay out a specific appraisal process to develop the value of the subject interest.Fixed Price Agreements Are Typically Never UpdatedFixed price agreements are simple to start. The actual dollar price of the stock is set out in the buy-sell agreement and is intended to be updated on some regular basis based on agreement amongst the shareholders.The problem with these agreements is that they are almost never updated. When it comes time that an update must be done, such as at a trigger event, the interests of the parties may have diverged and agreement could be difficult, if not impossible.Formula Agreements Often Outgrow Their FormulaFormula agreements attempt to remove uncertainty by establishing a set calculation through which value will be determined at the appropriate date. The primary disadvantage of formula agreements is that no single formula can capture all of the complexities of change and provide reasonable and realistic conclusions over time. If your buy-sell agreement has a formula mechanism, when was the last time the formula was calculated?Valuation Process Agreements Are Often the Most WorkableBuy-sell agreements that lay out a specific valuation process as the means of valuing the shares at the appropriate date (“process agreements”) are typically preferable and tend to provide the most efficient means of achieving a fair resolution for all parties.There are different varieties of process agreements. Multiple appraiser agreements outline processes by which two or more appraisers are employed to determine value. Generally, each party will hire their own appraiser and, if needed, will jointly hire a third appraiser to either select the appropriate value from the first two appraisers or deliver their own binding conclusion of value. Single appraiser buy-sell agreements outline processes by which a single appraiser is employed to determine the price.We suggest a Single Appraiser - Select Now, Value Now process. For more information on this valuation process, see this article.Six Things That Should Be Clear in Any Valuation Process AgreementRegardless of whether a valuation process involves multiple appraisers or a single appraiser, there are six defining elements that must be in a buy-sell agreement in order for the valuation process to work smoothly and reasonably. If you have a valuation process as part of your buy-sell agreement, make certain that each of these six elements are present.While the six defining elements of a valuation process may seem obvious, they are prominent in their absence or unclear treatment in many buy-sell agreements.Standard of value. The standard of value is the identification of the type of value to be used in a specific valuation engagement. The proper identification of the standard of value is the cornerstone of every valuation. Will value be based on “fair market value” or “fair value” or some other standard? The parties to the agreement should select that standard of value. If they do not, the appraisers will have to select it and the parties may not like their choices.Level of value. Will the value be based on a pro rata share of the value of the business or will it be based on the value of a particular interest in the business? This distinction is critical to any appraisal process and to the shareholders of any business who are parties to its buy-sell agreement. If knowledgeable choices are not made by the parties to the agreement, someone else, i.e., the appraiser(s), will make it for them. The problem is that many agreements are written such that they are subject to differing interpretations regarding the appropriate level of value.The “as of” date. Every appraisal is grounded at a point in time. That time, referred to as the “as of date” or “valuation date”, provides the perspective, whether current or historical, from which appraisals are prepared. Unfortunately, some buy-sell agreements are not clear about the valuation date which should be used by appraisers. Because value changes over time, it is essential that the “as of” date be specified.Qualifications of the appraiser(s). If the parties do not decide on the kind of appraiser(s) they want to help for their buy-sell agreements, then, unfortunately, almost anyone can be named by either party to the agreement. Do you want a college professor who has never done an appraisal as the appraiser? How about an accountant who has no business valuation training? How about a broker who has no business valuation experience unrelated to transactions? How about a shareholder’s brother who has an MBA but has never valued a business before? The picture is clear. Buy-sell agreements must specify the qualifications of appraisers who may be called when trigger events happen.Appraisal standards to be followed. It is in the interest of all parties to ensure that selected appraiser(s) follow accepted business valuation standards. Some buy-sell agreements do this by naming the specific business appraisal standards that must be followed by the selected appraiser(s). Business appraisal standards provide minimum standards (criteria) to be followed by business appraisers in conducting and reporting their appraisals.Funding mechanisms. The funding mechanism is thought of separately from valuation yet is an important aspect of any buy-sell agreement. Why? Because life insurance is often purchased on the lives of one or more owners of companies having buy-sell agreements. Does the agreement tell the appraisers how the parties want the proceeds to be treated in their valuations? Appraisers will develop potentially widely divergent valuation conclusions depending on whether the life insurance is a funding vehicle (and not considered in reaching a value conclusion) or a corporate asset (and added to value prior to determining price for the agreement).A Tool to Help in Reviewing Your Buy-Sell AgreementBuy-sell agreements are important legal documents. They are also important business and valuation documents. How they operate when triggered can have huge consequences for business owners, their family, and the business. Unresolved problems within a buy-sell agreement truly are like ticking time-bombs.Do not wait for the countdown to run out, review your buy-sell agreement now with your partners and professional advisor(s). It will be far easier to get agreement on revisions made today than it will be after a trigger event.