Bryce Erickson

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

The drumbeats have been building for a couple of months now.  Finally, as commodity prices have risen and third quarter profit reports have rolled in, so have accusations of price gouging by oil and gas companies.  Senator Warren recently said as much on MSNBC.  She is wrong on this point, but certainly not alone by any means.  Politicians have made oil companies a proverbial punching bag on numerous fronts.  This is not news.  They have been rhetorical targets for decades.However, it is true that U.S. upstream producers (both oil and gas) have yet to momentously hasten new production and aggressive drilling plans.  It would make sense if they did, as it speaks to the core incentives of commodity-based businesses like oil and gas.  Yet the U.S. industry remains tentative and reticent.  In the meantime, the market remains in backwardation marked by continuing inventory draws and increasing prices.  Why?  The answer is found somewhere among supply and demand dynamics, rising costs, and capital headwinds.Supply & Demand Issues“We are encouraged by the restraint shown by U.S. upstream operators. By restricting capital expenditure, we are healing historic overproduction of both oil and natural gas. We believe investors will be attracted back into the E&P space if, as an industry, we continue on this path for at least a year or two more to deleverage balance sheets and return capital to investors.”  -Fed SurveyRespondent It was a rough 2020, but producers have turned a corner on drilling discipline, and have restrained on the drill bit compared to years past.  They also deleveraged balance sheets, and where possible, returned capital to shareholders.  During 2021 traffic patterns have normalized, and apart from jet fuel, demand growth has bounced back to pre-pandemic levels.  It is also creeping into winter and natural gas will be in season.  That’s good news. Energy consumption is a bellwether for economic activity.  However, that production discipline in both the U.S. and OPEC+ nations has resulted in crude oil inventories being 6% below the five-year average (2016-2020) overall.  The Biden administration just announced a 50-million-barrel drawfrom the Strategic Petroleum Reserve.  This imbalance started in Q3 2020 and has continued since, and is helping to keep prices high, though perhaps not for too long.  The U.S. Energy Information Administration (EIA) projects this to come back into balance by Q2 2022. OPEC+ is slowly, but steadily adding production to the markets, while U.S. shale producers, although increasing activity, have been lagging this year.  Futures markets suggest a similar outcome and prices are expected to steady according to NYMEX and EIA.  As the futures curves tail out, the 60 month premium from a year ago is higher, but the near term spread is even wider, thus giving firms pause before diving in headlong with massive new production initiatives. (Not all share this outlook – Bank of America sees oil at $120 by June 2022).  Still, producers went through a lot to discipline themselves, and expectations by investors have been clear for years now: less drills more bills. One other commodity that’s in demand which should impact oil and gas supply as well is the U.S. dollar.  The currency is strengthening, and this brings downward pressure on prices too. Costs Labor is causing major problems in staffing for the increase in activity. Wages are up 20 percent, and companies are poaching employees from competitors. We are finding it difficult to increase prices to match our increase in costs. – Fed Survey Respondent As oil and gas prices are going up, inflationary pressures are impacting the industry’s operations concurrently.  The cost of oilfield services is rising quickly.  Lease operating expenses are increasing.  Delays are a problem as well, as 70% of the respondents to the latest Dallas Fed survey said they experienced delays of some sort in the last quarter.  This is partially a result of tight labor markets and it’s dampening enthusiasm somewhat. Also, as I have mentioned before, costs on development are going up as drilled but uncompleted (DUC) well inventories shrink.  They have continued their downward march and are at the lowest levels in seven years (November 2014). This leads to another less heralded point as well.  U.S. shale oil fields have been active for around a decade now.  Many of the best drilling locations have been developed.  Although there are a lot remaining, they haven’t been drilled yet for a reason.  Productivity per rig metrics have fallen slightly this year and it may have more to do with geology rather than technology making production growth more expensive and squeezing margins. Investment Headwinds“Oil, natural gas and natural gas liquids prices are greatly improved and appear to be sustainable for the coming months. The greatest headwind is skilled labor supply and access to expanding credit on our reserve base loan. Initial conversations with regional energy banks show increasing interest in advancing incremental credit. The money center banks continue to seek to reduce their commitments to oil and gas borrowers.” – Fed Survey Respondent Although economics have shifted quickly for producers this year, though investment sentiment not so much.  Capital providers are not only cautious, but fewer in number.  The multi-year souring on the oil and gas sector from several investment segments has not changed recently, leaving upstream producers with fewer options. On the debt side, some regional banks have shown a willingness to lend, but larger banks have not.  Some reasons for lending discomfort have included a wariness for shale’s ability to ramp up quickly and for margins to evaporate before loans can be paid back.  It’s worth a remind that U.S. production has a higher cost floor than OPEC+.  Larger banks appear not to be interested. Additionally, the shrinking pool of bankers has been mirrored by a shrinking pool of investors.  Firstly, returns must be carefully evaluated as many upstream producers have hedged their portfolios and some have limited their upsides to execute their strategies.  They are watching profit margins go elsewhere for the time being.  Also, as ESG concepts have gained momentum, many investors have weaned their appetite off oil and gas production.  There are simply fewer institutional and private equity investors evaluating and participating in the space.  According to a recent Wall Street Journalarticle, there are less than one-third of the firms and capital available in the space compared to 2018.  Simply put, it is harder for oil and gas producers to get expansion capital while they’re simultaneously paying much of it out. Talking heads and officials may be gaining political capital while talking about gouging, price controls and the like; but in a domestic industry populated with price takers and return oriented investors, prudence and temperance are driving decision making, not their ugly cousins – greed and avarice.  Thank goodness for that. Originally appeared on Forbes.com.

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!

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)

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.

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

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

[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.

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.

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!

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!

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.

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.

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.

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.

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.

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!

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.

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.

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.

This following article was originally published by The Texas Lawbook.  It has been often discussed, particularly in recent years, that the value of privately held professional sports franchises is a newsworthy item. Analysts, investors, and fans alike have an interest in observing team owners buy and sell teams and watch the prices at which they trade. However, are team owners doing as well as some may portray? How about their investments as compared to their investing peers in the stock markets. We attempt to answer these questions based on some known data sources and return analytics over time. The answers are interesting but not entirely clear. There are two components to an investor’s rate of return: (i) interim returns in the form of cash flows or dividends, and (ii) price appreciation. Many commentators and writers have noted that some major league sports franchises have incurred operating losses in past years. For example, at one point it appeared that the MLB franchises on average had operating losses as players’ salaries increased faster than revenues. This was a big factor underlying the NFL and NHL lockouts in 2011 and 2012. There is a silver lining, however, and that appears to be the price appreciation realized from the increased values of these major league franchises. We traced over time the estimated appreciation (by league) of the values of sports teams, according to Forbes magazine. We also tracked the returns over the same time frames of several familiar equity market indices. The table below summarizes our findings. We tracked this data going all the way back to 1991.  We then sorted the returns over different decades – the 1990s, the 2000s, and our current decade.  We aggregated it for the 25 total years of data.1 We observe that equity markets outperformed league appreciation in the 1990s, but the leagues caught up in the 2000s and 2010s.  The biggest reason for the significant increase in the 2000s and the 2010s (among others) is television contracts – specifically, increases in national TV contracts for the NFL and NBA and regional and local contracts for MLB and NHL (and to a lesser degree the NBA as well). Consider a few examples: The NFL had its national TV contract increase dramatically in the last several renewals, most significantly, the most recent one.  The 2014 season was the first year of the NFL’s nine-year deal with Fox, CBS, and NBC.  The networks will pay about $3.1 billion in rights fees every season or 63% more than the previous TV deal.The NBA, which signed a nine-year deal with ESPN and Turner Broadcasting and other networks, had total fees worth $24 billion in 2014.  This skyrocketed to $3.6 billion a year, up from about $930 million in the contracts reached in 2007.  In addition, NBA teams have benefited from increased local TV rights that have usually doubled or even tripled in annual rights fees in the last 5 years.For MLB and NHL teams, the majority of the TV revenue comes from local TV contracts. These contracts have also appreciated substantially in the last five years increasing 3 to 5 times in comparison to the contracts signed 5 to 7 years ago. This increased TV revenue has been the primary driver of the very strong price appreciation in the 2000s and particularly in last five years (2011-2016). In the last five years (2011-2016), the MLB team values have increased on average 19.8% compounded according to Forbes.  The NBA Forbes value estimates increased by 27.6% for the same period.  The NFL increased 17.4% and the NHL 21.3%.  This short 5-year period has seen the highest percentage increase in the last 25 years.  The compounded increases are 10% to 13% for the four major sports leagues over a 25-year period (1991-2016). In comparison, the DOW increased 7.4% compounded, the NASDQ 10.1% the S&P 500 7.0% and the Russell 2000 8.2%. Therefore, solely from an appreciation point of view, an investment in a major league sports franchise appears to have been a very good return in the last 25 years, especially in the last five years.  Of course, these returns vary by team and nothing is guaranteed.  It is also notable that some teams have incurred operating losses that will offset a significant amount of the total return.  This can impact investments in the form of debt or even capital calls from investors.  This gets even more complicated when considering the value of minority interests in teams whereby the ability to monetize their returns is more uncertain.  In fact, minority interests typically trade (however infrequently) at lower value levels than what the pro-rata value of a franchise would otherwise be worth.  Therefore, appreciation returns that appear positive can come with drawbacks as well.  Critical analysis is important to investors to help them determine if their returns are worth the risks. Mercer Capital has arguably the most expertise in sports valuation and related stadium advisory in the country. For more information, contact one of our professionals.End Note1 We would note that Forbes does not have access to many team financials as teams are closely held (with the notable exception of the Green Bay Packers).Forbes relies on limited data and educated estimates of actual revenues and profits in order to make their estimated values.This is a limiting factor to properly value a single franchise at a single point in time.That said, as part of Forbes’ analysis they have interview access to a number of team owners to test the reasonableness of their valuations and key assumptions.In addition, their estimated values are adjusted year-to-year to account for actual sale prices of teams that sell.This is helpful when observing estimated aggregate values over a long period of time.

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.

[August 2016] The IRS released its long expected proposed regulations in regards to Section 2704 on August 2. The substance of this proposal, according to the IRS, is to regulate treatment of entities for estate and gift tax purposes. According to the summary the proposal is:“…concerning the valuation of interests in corporations and partnerships for estate, gift, and generation-skipping transfer (GST) tax purposes. Specifically, these proposed regulations concern the treatment of certain lapsing rights and restrictions on liquidation in determining the value of the transferred interests. These proposed regulations affect certain transferors of interests in corporations and partnerships and are necessary to prevent the undervaluation of such transferred interests.”Before we delve any deeper on this article, let’s clarify a few things up front:We are appraisers, not lawyers and we are neither qualified nor particularly interested in dissecting the proposal from a legal perspective. Our friends in the legal community can address that.This is a proposal that, as of the writing of this article, is not in effect, could change, or might never go into effect. (Nonetheless we aim to comment from a valuation perspective as if it does). With that said – what we hope to do in this post is to (i) give readers some context about the impetus of these proposed Section 2704 changes, (ii) share what these proposed changes are, and (iii) share what this might mean from a valuation standpoint.Background of the ProposalAccording to the IRS, treatment by taxpayers in regards to certain rights and transfers, as well as rulings of the Tax Court in regards to these rights and transfers have allowed taxpayers to avoid application of Section 2704. Representative of this sentiment, Page 6 of the proposal puts it this way when referencing Section 2704(b):“The Treasury Department and the IRS have determined that the current regulations have been rendered substantially ineffective in implementing the purpose and intent of the statute by changes in state laws and by other subsequent developments.”The areas that the IRS cites as no longer ineffective fall into three primary areas:2704(a). Specifically the area covering so-called “Deathbed Transfers” – whereby liquidation rights lapse upon death. The IRS cites Estate of Harrison v. Commissioner as an example of this. The IRS claims that such transfers generally have minimal economic effects, but result in a transfer tax value that is based on less than the value of the interest.2704(b). Inter-family transfers and specifically restrictions on liquidation for family interest transfers. Reasons for this include that courts have concluded that Section 2704 applies to restrictions on the ability to liquidate an entire entity, and not on the ability to liquidate a transferred interest in that entity. Also the IRS says state laws and utilization of “assignees” have allowed taxpayers avoid 2704.2704(b). Granting of insubstantial interests to non-family members (such as a charity or employee) to avoid application of the statute. The IRS says this needs to be changed, because, in reality, such non-family interests generally do not constrain a family’s ability to remove a restriction on an individual interest.Proposed Changes and AmendmentsIn light of this perceived avoidance and ineffectiveness of certain provisions in 2704, the IRS has proposed a number of new regulations including:Change the definition of a “controlled entity” to be viewed through the lens of an entire family including lineal descendants as opposed to individual(s).Amend the regulations to address what constitutes control of an LLC or other entity that is not a corporation, partnership, or limited partnership.Amend the regulations to limit the use of eliminating or lapsing rights (voting or liquidation rights) and limit the exception to transfers occurring three (3) years or more before death.Ignore transfer restrictions for minority interests and thus assume that they would be marketable, regardless of governing documents and/or state laws.Ignore the presence of non-family members with less than 10% of the overall equity value.Valuation ImpactThe IRS is not proposing changing the definition of fair market value. However, when applying fair market value under the constructs as contemplated in the proposed 2704 changes, there would be a smaller (or perhaps no) value delineation for minority interests as compared to enterprise value of an entity. According to the IRS’s position, this would prevent taxpayers from “undervaluing” transferred interests among family members. This, of course, runs in stark contrast to the marketplace, of which fair market value is supposed to be a reflection. The marketplace’s long track record on this is abundantly clear - it differentiates for minority interests as compared to the value of entire enterprises. Thus the proposed regulations essentially circumvent the levels of value for family members as defined in a “controlled entity.”If the proposal is adopted as contemplated, there will be a powerful incentive for families with businesses and investment holding entities to initiate or complete transfers before these regulations take effect (which is thought to be December 2016). If Mercer Capital can be of any assistance in light of this development, please contact us.

In a recent article Mark Cuban commented how media revenues will push National Basketball Association (“NBA”) valuations far higher than they are currently. “If we do this right, it’s not inconceivable that every NBA franchise will be worth more than $1 billion within ten years,” he was quoted as saying. While that observation could be on the money, it’s not the only engine that drives NBA team values. NBA franchises are unique properties that are often among the most attractive and reported upon assets in the US (and globally for that matter thanks to Mr. Prokhorov). The undergirding economics of these teams are complex and nuanced. When value drivers align, good things happen and value is unlocked. Like a flywheel with momentum, certain dynamics can push values upward quickly. However, the same dynamics can push the flywheel off its hinges, bringing values crashing down. It’s an exciting property that doesn’t always follow the path of conventional valuation theory, which might be a reason why a Maverick like Mark Cuban loves it so much.NBA franchise values have recently gone in an upward direction as evidenced by the Sacramento Kings’ $534 million sale in January 2013. That’s quite a figure for the 27th ranked metropolitan statistical area (“MSA”) in the country. This transaction is especially fascinating in light of the Philadelphia 76ers (5th largest MSA) selling for only $280 million just 18 months earlier. What fuels such a vast difference? We explore three issues that contribute considerably to these variances – media rights, arena lease structure, and the NBA’s collective bargaining agreement (“CBA”). Some of these factors are more within an owner’s control than others, but all of them contribute to situational changes that valuations hinge upon. We’ll also explore the tale of two transactions: the 76ers and Kings, to see why and how these factors influence the purchase price.Media Rights: The Quest for Live ContentIt is important to note the majority of NBA team revenues come from local sources, (i.e. game day revenues and local media contracts). The most dynamic (and thus value changing) of these sources in the past few years has been local media rights. National media revenues in NBA are significant but are a much lower percentage of total revenues than the biggest league in North America, the NFL. According to Forbes, the 30 NBA teams collectively generated $628 million from local media last season (about $21 million average per team). In addition, national revenues from ESPN, ABC & TNT total $930 million per year and these deals expire in 2015-2016. It’s a relatively balanced mix compared to the other major leagues. NHL & MLB’s media revenues are more locally focused, while the NFL is nationally dominated.Basketball’s popularity has grown in recent years. This, coupled with intense media competition for quality live content, has fueled increased media contracts in many markets at unprecedented levels (300% to 500%) over prior contracts.Live sports programming has a relatively fixed supply and is experiencing increased demand from networks looking for content those viewers will watch live. This commands higher advertising dollars compared to content that is consumed over DVRs and online forms (Netflix, Hulu Plus, Amazon Prime, etc.). Content providers also covet the low production costs and favorable demographics of younger fans. These factors, among other variables, have helped fuel the rapid price increases for sports media rights.Recently, new media rights contracts across all sports programming have soared to record high annual payout levels. The NHL signed two new TV deals in April 2011 which more than doubled the league’s previous annual payouts with an upfront payment of $142 million. Even the media rights for Wimbledon have seen an increase in the amount of suitors. The NBA’s current national deal expires in a couple of years (2016). Many people expect that the next deal’s value will at least double the current agreement. [Side note: In negotiations that date back to the 70’s ABA/NBA merger, two brothers – Ozzie and Daniel Silna, received a direct portion of the NBA’s national TV revenues – in perpetuity. That’s right…perpetuity. In January 2014 they agreed to a $500 million upfront payment from the NBA and a pathway to eventually buy them out completely. The old transaction has withstood litigation and it has been termed as ‘the greatest sports business deal of all time’]      At the local level, in 2011 the Los Angeles Lakers signed the richest television deal in the NBA which dwarfs other teams. The contract reportedly averages $200 million per year for 20 years. The upper tier NBA franchises historically have received $25 to $35 million annually.   Some big market teams have expiring contracts in the next few years, such as the Mavericks. While bidding has not yet begun, it’s reasonable to expect Mr. Cuban and his Mavericks to anticipate a healthy bump in rights fees in the future assuming good counsel and creative structuring.How did these factors translate to the Kings and 76ers? Even with substantial MSA differences, they were at opposite ends of the media spectrum. The Kings’ deal with CSN California expires after this season, which put ownership in strong position to negotiate a new deal at the time of the transaction. The 76ers signed a 20 year contract in 2009 with Comcast Sports Net, which was reported by Forbes to be “undervalued” from the 76ers perspective, reportedly paying the team less than $12 million the season prior to purchase. That’s quite a difference and it almost surely played a pertinent role the Kings’ and 76ers’ valuations.Arena Lease and Structure: Slicing Up the Game Day PieIn the NBA, game day and arena revenue typically make up the lion’s share of a franchise’s income. These revenue streams filter up from a multitude of sources. Aside from regular ticket sales there are club seats, suites, naming rights, parking, concessions, merchandise, and sponsorship revenue. In addition there are non-game revenues such as concerts, events and meetings. On the expense side there’s rent (fixed or variable), revenue sharing (or a hybrid arrangement), capital expenditures, maintenance, overhead allocation and more. All of these aspects are negotiable among the business, municipal, and legal teams involved.Arena deal structures vary across the board. For example, the Detroit Pistons own The Palace at Auburn Hills while the Golden State Warriors are tenants at Oracle Arena (probably until 2017/2018 anyway). Most arena structures involve some form of public/private partnership. One common theme is public ownership, usually financed via local bonds, with the sports franchise as a tenant paying rent of some form. The chief aspect to consider for legal teams is how to structure agreements for the various revenue streams, expense and capital items.Historically, some of the most negotiated aspects to the arena lease are how proceeds from certain items as defined by the CBA are allocated. For example, while players as a group receive a flat percentage of basketball related income (“BRI”), they receive reduced percentages of others, such as luxury suites and arena naming rights. This nuance represents an opportunity for team ownership to retain a larger portion of these revenues and legal teams to employ shrewd negotiating tactics. In addition, as the arenas age and significant maintenance costs are required, cost sharing between the public/private partnerships can become an issue. Lease structure also can make outright ownership of a stadium appear less attractive without a partner to share or bear costs.Again as we examine the Kings and 76ers a contrasting picture emerges. Prior Kings’ ownership (the Maloofs) and the city could not reach an agreement on a new stadium lease after nearly a decade of negotiations. Initially there was a buying group that planned to move the team to Seattle, but then, new local ownership purchased the team (with substantial input from the NBA). This agreement included an agreement for a new $447 million stadium (the majority funded publicly) and a guarantee to keep the team in Sacramento. This new deal was reported to be more favorable to ownership and gives the franchise an opportunity to attract more fans and create refreshed revenue channels. The 76ers on the other hand had already been locked into a long term lease at less favorable terms that were more geared towards revenue sharing with Comcast. Again, the Kings’ new opportunity appears more attractive than the 76ers existing arrangement.Collective Bargaining Agreement: Leveling the Playing FieldOn December 8, 2011, after a 161 day lockout, the NBA and its player union reached a new collective bargaining agreement. This agreement brought about meaningful changes to the salary structures, luxury tax, BRI, and free agency (among other things). Although the CBA is not under direct control of a franchise owner, its impact on competiveness, team operational strategy and expense management is significant.The changes were important for owners, who had reportedly lost over $300 million annually as a group in the three prior years to the negotiations. From a valuation perspective three items deserve focus: (i) length, (ii) BRI, and (iii) luxury tax provisions. Prior to the agreement, there was a great deal of uncertainty as to how negotiations would play out. Uncertainty infers risk and where there’s more risk, values usually fall. The 10 year agreement (with a 2017 opt-out) brings stability to both players and owners as to what operating structure they can plan for the near to intermediate term future. In addition, BRI revenue splits to the players were lowered from 57% of BRI to around 50% for most of the contract. This split brings cash flow relief (but not competitive relief) to owners across the league. Lastly, the luxury tax structure became much more punitive for big-spending owners, like Cuban. In fact, it economically functions similarly to a hard salary cap that the NFL and NHL employ. In light of this change, NBA franchises have committed an enormous amount of time and resources to understand and execute an appropriate competitive strategy. The luxury tax provisions even the competitive playing field for smaller market teams such as Sacramento and the Memphis Grizzlies (who sold for a reported $377 million in October 2012) and constrains the spending of larger market teams such as the Mavericks, Lakers or Knicks.How did this facet play out with the Kings and 76ers? All one needs to know is that the 76ers were sold before the new CBA was agreed (Summer 2011) to and the Kings were sold after the CBA was in effect (January 2013). Timing, coupled with the Kings small market status, has an increasingly positive effect on them compared to the 76ers. Advantage: Kings.Takeaway: NBA Boats Don’t Necessarily Need the Tide to Rise (or Fall)NBA franchise values are on the rise. There is a buzz around the league that if there were teams on the market the price would be robust right now. The values are driven by a number of different factors (TV, arena rights, CBA), some that cannot be controlled by owners and their advisory teams, but others that can be. Don’t be fooled by market size. A value creation scenario can occur in almost any market. In one of the smallest markets in the country, Tom Benson paid more for the Hornets than Josh Harris’ group did for the 76ers. However, owner involvement, savvy counsel and careful negotiations are a must; because as some transactions have shown, there are no guarantees.This article was originally published in The Texas Lawbook in March 2014.