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Have Some In The Shale Patch Taken Cues From The Enron Playbook?

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The collapse of oil prices due to the price war and COVID-19 pandemic has exposed the financial underpinnings of the shale patch. Some journalists and short sellers have likened the collapses and pending collapses to the recipe followed by Enron in the 1990s: an unsustainable business model and overtly “optimistic” projections. While there are similarities, the results were predicted as they were with Enron, and these journalists and short sellers were late to react. They see the immediate collision with the iceberg but had earlier missed that the unsinkable ship was speeding in fog.

Enron’s business model and how to monitor its progress was detailed in “Hidden Risks” by the late Forbes journalist Toni Mack in 1993. To increase income year after year, Enron had to book ever increasing volumes of natural gas and electricity trades. Enron’s great success in developing these markets with liquidity and transparency led to ever decreasing profit margins per trade. Enron churned its trading shop to a frenzy to meet its projected income growth. When the music slowed, Enron created revenues and income by “selling” assets to itself, that is, to entities controlled by Enron management. That started with publicly-owned subsidiaries, as detailed by Harry Hurt III in Fortune  in 1996, and later with privately funded off-balance sheet vehicles to extend the charade.  Even the California Public Employees Retirement System, or CalPERS, eagerly provided investment for the notorious partnerships.

The 2001 collapse of natural gas prices stopped the music. The company declared bankruptcy in late 2001, executives went to prison, and Enron is no more.


Some producers in the shale plays across the U.S. have, like the top executives at Enron, been heralded as geniuses. The oil production from shale and other tight formations is possible due to horizontal drilling and advances in the technique of hydraulic fracturing, or fracking.  Following the success with the predominantly natural gas-rich Barnett Shale, the Bakken in North Dakota was the first major shale play for oil.  The Eagle Ford in Texas boomed next, followed by the Niobrara in the Denver-Julesberg Basin. The Permian Basin, a prolific area for conventional production for 100 years, has now become the leading shale basin.  Shale patch production soared from zero to more than 8 million barrels per day in the pre-pandemic world.  

The economics of the shale plays have not been in doubt. While some of the best core positions in the best basins are in the middle-and-even-top-third of global plays, many shale basins and flanking positions are among the highest-cost plays in the world. Because of this, and with apologies to playwright Tennessee Williams, many companies have always had to rely upon the kindness of strangers for their economic success. OPEC ceded market share at great expense to accommodate the U.S. shale plays in the global oil market. At 8 million barrels per day, the cost to OPEC producers at $60 per barrel is more than $175 billion per year. It is understandable that OPEC members would become annoyed with U.S. producers.

Shale patch wells decline very rapidly—producing as much as 70% of total production in the first year, with many wells abandoned after the fourth year.  It has been well-documented for more than 15 years that to continually increase production, companies must drill new wells at an ever increasing pace. And that assumes that the last well drilled is as productive as the first. This assumption was proven false.    

The public finally caught on with a well-researched January 2019 report by The Wall Street Journal that considered the production profiles of more than 16,000 wells.  The authors specifically called into question projections made by some publicly-traded companies and concluded that more than two-thirds of projections were overstated. Just as Toni Mack’s article upset Enron’s Ken Lay and led to a Harvard Business School case study that attempted to disprove her analysis, some shale patch CEOs complained loudly.  A further study of more than 49,000 wells by petrophysicist Scott Lapierre demonstrated that the WSJ had understated the problem. As at Enron, patch insiders already knew the math.

Data provided by WellDatabase illustrate the declining productivity of wells drilled in the Permian Basin (illustration above) and in the Eagle Ford (below). EUR, estimated ultimate recovery, is falling even as the wells grow longer (more lateral length) to expose more of the formation to each well (wells by first date of production since 2010 that have produced at least 100,000 barrels).

                                                        


Cash generated by the business of drilling in the shale patch has diminished over time. The burden of high access costs, lower oil prices and diminishing well production in the face of continued deployment of capital have left little for shareholders. The industry’s returns, pre-virus, have been among the most anemic of the Standard & Poor’s industrial sectors. Over the last 10 years, the industry has barely returned 20%, whilst the S&P 500 has returned more than 200%. How did capital continue to support the industry? Enter private equity. As this pool of capital grew ever larger and the pool of shale patch prospects inevitably shrank, prices were bid up and rates of return were bid down.   

Christine Idzelis in Institutional Investor has recently questioned how private equity managers in oil and gas could have market-beating returns while the public market performance, the best exit for private equity’s portfolio companies, has been poor. That is, how do the high valuation marks in private equity persist? Some managers are paid based on cash-on-cash returned to their investors, but others succeed largely because they get to set their own asset valuations and their limited partners believe them.

OPEC’s strategic price war of 2014-16 hammered the debt and equity of public and private companies alike. Some private equity managers doubled down and bought in the heavily discounted debt of portfolio companies. It is a valid Wall Street tactic, but it remains to be seen if pension funds and endowments will double down again in 2020. 

Today we see that private equity managers are also serving as directors of publicly traded companies. Often these directorships derive from the portfolio companies that are sold or merged into the public companies. However, these transactions result in the distribution of cash and shares to the pension funds and endowments, they are cashed out. Why do the private equity managers remain on the boards? 

The debt of some companies has been trading at default levels since last year, well before the pandemic. The steady pace of bankruptcies from 2015 is picking up, and as the management teams sink into bankruptcy, many are paying themselves huge bonuses.  Picture the captain of the Titanic demanding a bonus to salvage the ship just as the iceberg appears out of the fog. Apologists say that the bonuses are justified to keep the teams: “These are the executives who know these properties and can help maximize the sale value.” That justification fails in simple logic. If these executives knew the market and their properties so well, they would not have saddled them with unsupportable debt. And, what else would they do? Are Spencer Stuart or Korn Ferry KFY calling them with bigger and better jobs? With more than 150 companies in the Permian Basin alone, it is hard to believe that the basin needs more CEOs.   The list grows each day. The fired field engineers know the real truth.  The bankruptcy courts, trustees and creditors should know better.

For one oil industry event last October, the sponsors were restructuring firms and bankruptcy lawyers instead of the usual private equity firms and investment banks.  The pandemic is viewed as a blameless escape hatch for managements who were sunk already. With Enron, there was one easy target. With the shale patch, there may be quite a few.

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