Monday, November 28, 2022

"Why Won't Energy Companies Drill?"

[Previously from Goehring & Rozencwajg: Q2 (2022) Natural Resource Market Commentary, "The Distortions of Cheap Energy" and Goehring & Rozencwajg and Horizon Kinetics on Commodities.]

Highlights from Goehring & Rozencwajg's third quarter 2022 Natural Resource Market Commentary, "Why Won't Energy Companies Drill?":

  • Following Russia’s invasion of Ukraine, oil prices broke through $100 per barrel for the first time since 2014. Most analysts predicted that triple-digit oil prices – the highest in nearly a decade – would produce a strong response in drilling activity. However, thus far, that response has been muted. Even now, after six months with oil prices greater than $85 per barrel, the US oil-directed rig count remains at 533 – nearly 40% below the 2018 levels despite oil prices having nearly doubled.
  • [A] tight relationship has historically existed between oil prices and drilling activity. Between 2008 and 2018, the oil price alone explained 70% of the variation in drilling activity. Since 2020 however, this relationship has broken down. The industry should be turning 1,000 rigs; instead, they are stuck stubbornly at 533.
  • We estimate that a company with high-quality Permian acreage can generate $38 mm in undiscounted cash flow from a well given $80 WTI, compared with $8 mm in drilling and completion costs. Given more than half of a well’s cash flow is generated in its first two years, the IRR at today’s oil prices is well over 200%. Given these extremely attractive single-well economics, why are the companies not drilling more?
  • By keeping activity low, oil companies are simply responding to the signals sent from their three significant constituencies, all emphatically telling them not to drill. These constituencies are policymakers, investors, and their internal strategy teams.
  • Low valuations encourage companies to favor returning capital to shareholders over increasing drilling, despite strong single-well returns. Here’s why: The E&P sector trades at 0.8x its net-debt adjusted PV-10 per share. For those to whom this is unfamiliar, the SEC requires energy companies to publish their PV-10 value (or standard measure) annually in their 10-K. The companies must list their proven reserves and estimate the discounted cash flows using a given oil and gas price. Removing net debt and dividing by the share count yields the so-called “net-debt adjusted PV-10 value per share,” which we will refer to as NAV per share going forward. In the past, investors capitalized an energy company at a multiple of NAV, reflecting the future development potential not yet reflected in their proved reserve figure. The trick was to determine the appropriate multiple given the company’s assets.
  • We cannot recall a time when the entire industry traded for less than its NAV, and these extremely low valuations have tipped the scales away from drilling and toward dividends and share repurchases. Consider a hypothetical E&P company trading at 0.8x its net-debt adjusted PV-10 per share. Our hypothetical company has $1 bn of PV-10, 10 mm shares, and $200 mm of net debt. The company’s CEO can choose between spending $100 mm on new drilling or buying back stock. Assuming they can find and develop energy reserves for $15 per barrel of oil equivalent (boe), the company will book 6.7 mm boe of newly proved developed reserves for the $100 mm investment. At $80 crude and $5 gas, we estimate this investment would generate ~$130 mm in new PV-10. However, because the market capitalizes the company at only 0.8x NAV, the ending stock price would be virtually unchanged. On the other hand, if the company bought back $100 mm of its stock, its share count would fall by nearly 20%. Adjusting for net debt and dividing by the new lower share count implies the stock would rise by over 5% -- more than by drilling new wells. Therefore, the CEO that choses to return money to shareholders will enjoy a higher stock price and still have his best wells left undrilled. Under these conditions, no rational executive would rush to increase activity. Even though each well drilled would generate an IRR of nearly 80% in our example, the company is better off deferring development. The companies’ extremely low valuations explain this paradox. To summarize Edward Chancellor in “Capital Returns,” high multiples value growth and reward investment, while low multiples discount growth and encourage discipline.
  • We call this analysis a company’s “signal to drill,” and we believe it explains the industry’s reluctance to increase activity. Looking company by company, we estimate over 50% of the remaining undeveloped reserves in the US are in the hands of companies for whom it is better to return capital than to drill. Those companies with a clear “signal to drill” are growing production by 8%, while those without are shrinking by 4%. Pioneer Natural Resources (PXD) is an example of the former. PXD trades at a 100% premium to their NAV, and the company is growing production by almost 20%. In the latter category, Laredo Petroleum trades at a 70% discount to NAV, and its production is declining by 7%.
  • In 2018, the industry had a much clearer signal to drill despite lower prices. Oil averaged $51 per barrel in 2017 – 40% lower than today; however, we estimate the industry was valued at 4x NAV compared with 0.8x today. Using the same parameters as in the example above, drilling increases the stock price by 7%, whereas buying back stock at very high valuations would decrease the price by 10%. Even though a single well’s IRR is much better today than it was in late 2017, the difference in valuations back then pushed oil companies to drill. If oil companies traded at 3x NAV, everyone would have a positive “signal to drill,” and a considerable drilling boom would be underway. These same companies today are being told to defer drilling and development because of depressed valuations.
  • The last group signaling energy companies to keep development muted are their strategy teams: petroleum engineers, rig crews, and project managers. The reason is resource depletion. We have long argued that Eagle Ford and Bakken producers have drilled out most of their best wells, so production would likely plateau and decline. Over the past years, several companies have gotten into serious trouble by running out of high-quality inventory. As recently as 2017, Oasis Petroleum, a sizeable Bakken driller, claimed they retained 20 years of top-quality Tier 1 drilling locations. However, only a few months later, they tacitly acknowledged they were running out by closing a high-priced Permian acquisition to exit the Bakken and forestall future production declines. The strategy did not work, and Oasis declared bankruptcy in September 2020.
  • When you think about the challenges now being faced by the industry in these terms, you can easily see why oil company executives would keep the pace of development subdued. On the one hand, you could increase activity, risk attracting the ire of policymakers, have your stock price go down, and deplete your irreplaceable asset. On the other hand, you could return capital to shareholders, stay under the radar of policymakers, have the market reward your capital discipline, and keep your Tier 1 assets for a later time when the market will better value them.
  • In past cycles, the “signal to drill” has often been determined by the oil and gas price. When oil prices fell from $100 to $27 between 2014 and 2016, the industry laid down rigs because they could not generate a return on drilling. As prices recovered in 2016 and into 2018, the rig count rebounded by 600 rigs. Because of record low valuations, this is the first time we can recall where the “signal to drill” is driven by valuation instead of oil price. As a result, higher prices have not incentivized increased activity. Until investors allocate capital to the
    space and valuation improves, we expect drilling activity to remain subdued and oil shale supply disappointments to continue.
  • [W]e believe OPEC’s current output, at 29.9 mm b/d, represents its maximum capacity. Not only is OPEC pumping less than 2 mm b/d below their quota, but we believe Saudi Arabia’s current production (~ 11mm b/d) is putting strain on their fields and is unsustainable -- a subject we have covered in the past. With any contrarian thesis, we lay out roadmaps that try and predict what we should expect to see if we are heading in the right direction. In 2019, when Saudi Aramco released its first reserve report in nearly 50 years, we predicted their production could not exceed 10.5 m b/d for any sustainable period without incurring material field damage. As a “mile marker,” we stated that anytime Aramco pumped above 10.5 m b/d, they would quickly announce an unexpected production cut. These “surprise” curtailments occurred in 2019, 2020, and again today. In today’s example, weak oil demand has given the Saudis cover to slow production once again. We continue to believe the real reason they slowed production is field exhaustion.
  • Assuming our models are correct and the Saudis cannot pump more than 10.5 mm b/d, OPEC pumping capacity is much lower than stated. Nearly every other OPEC member cannot achieve their quotas, and the 1.5 m b/d of unused Iranian capacity remains sanctioned. Since Iranians are now providing weapons to Russia, the probability of the US lifting its sanctions is quite remote. Considering these, we believe OPEC’s pumping capacity is only 31 m b/d and not the commonly stated (and accepted) 34 m b/d. With demand now pushed up against total pumping capability, the only thing keeping inventories from continuing their multi-year plunge has been the 1.5 mm b/d of coordinated releases from US, European, and Japanese strategic petroleum reserves. The world has become addicted to SPR sales to keep global markets balanced and prices from soaring. The Biden administration has stated that SPR sales will continue into December, but they cannot go on forever. As of today, the US SPR has already fallen by 32% and, at current rates, will be entirely depleted within 17 months.
  • Although the continued growth in gas supply combined with the loss of Freeport LNG demand has pushed out our thesis concerning the convergence of US and international gas prices, we still have great confidence this will occur at some point in 2023. It appears the Marcellus is in the process of rolling over, which is very much in line with our models. Those same models suggest we will see a significant slowdown in the Hayneville’s growth very soon. The Haynesville rig count has doubled since the 2020 COVID-related bottom but has stagnated over the last 10 months.

A correspondent writes in to share a link,

I think it's pointing to why everyone shorting energy according to the "recession playbook" is going to be blown out. Energy was in a nearly decade-long retreat and then was finally clubbed to death in 2020. Equities have recovered, but are still at a discount. Managers shorting XLE according to the usual recession rules are committing the recency bias error. They are missing the fact that energy stocks were clubbed in 2020, and only came off historic lows in 2021. They are looking at 2022 in isolation and thinking "sell energy," as if it's 2008, 1998, or 1980 and energy is going to return to 2020/2021 prices without realizing how impossibly cheap 2020/2021 valuations were. or that energy companies have been deleveraging like mad the last 12 months. Equities have even more earnings power now than they did last year. 

We pointed this out on Twitter:

It appears that many investors think that shorting energy is a smart way of hedging recession risk in their “software eating the world” tech portfolios. The top 800 hedge funds are long "tech" and short energy, still, a full two years after tech versus energy peaked.

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