Growing Up - Their Finances Now Stronger Than Ever, E&Ps Assess What's Ahead

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Wednesday, 04/19/2023  Published by: Sean Maher rbnenergy.com

The Shale Revolution transformed the U.S. oil and gas industry operationally and functionally in the late 2000s and early 2010s, but the most significant changes occurred years later. Through the middle and latter parts of the last decade, E&Ps continued to improve their drilling-and-completion techniques and significantly increased production as they gained experience. This production growth was enabled by — or driven by, depending on the perspective — midstream companies’ aggressive efforts to build out the pipelines, gas processing plants and other infrastructure required to handle higher production volumes and exports. More recently, capital market constraints, the Covid pandemic and a looming ESG narrative have propelled the industry into the next phase of its evolution, highlighted by fiscal discipline, which delivers improved shareholder returns through managed capital spending. But how long will this stage last — and what’s next? In today’s RBN blog, we examine the energy industry’s maturation and the differences between this transformation and those in other industries.

A long decline in U.S. oil and gas production was stemmed and reversed about 15 years ago with the expanded — and increasingly successful — use of hydraulic fracturing, which opened up the source rock in shale to ease the release of trapped hydrocarbons (see Square One, Part 4). “Fracking” wasn’t new. Its roots can be traced back to 1865. But George Mitchell, the founder of Mitchell Energy & Development Corp. and patriarch of modern fracking, breathed new life into the industry by using hydraulic fracturing in the Barnett Shale, initially focusing on natural gas production. Later, the technique was used to spur crude oil production too.

Following a steady 23-year decline in oil output from 1985 through 2008, the U.S. by 2015 was producing more crude oil than it had in 1985, and the growth in output had only just begun. With this “newfound” resource — and with U.S. and global demand for crude on the rise — E&Ps went all-in and a modern-day “land grab” was on in an effort to lock up the acreage perceived to offer the best potential. Consider what happened in the Permian. In 2011, an acreage package in its Delaware Basin sold for ~$3,200 per acre, up from ~$900/acre only a few months earlier. By 2016, prices were at $58,000/acre; in 2018, the per-acre value hit an extraordinary $70,000.

The land grab was funded by private equity, public equity and debt investors who erroneously believed that asset growth would be the primary driver of improved equity values in public markets. For many years after the Great Recession of 2007-09, the Federal Reserve kept interest rates near zero, meaning there was no risk premium to compensate for and investors (and E&Ps) had no reason not to “shoot the moon.” Not surprisingly, though, returns on invested capital fell significantly, and the energy business was about to learn a hard lesson: debt kills.

While still euphoric about their technological achievements — irrespective of cost — E&P companies began to improve the productive capacity of each well to maximize value. The more hydrocarbons per well, the lower the marginal cost of production, the faster the payback, and the higher the return — in theory. By 2021, the average lateral length had increased to 10,000 feet — double what it was just a few years earlier — and nearly 18% of the horizontal wells in the Permian had reached 15,000 feet, up from only 4% in 2017. (That’s almost 3 miles, or your average 5K run.) In 2014, 300 rigs drilled less than 20 million feet of lateral length; in 2021, fewer than 300 rigs hit 46 million feet of lateral distance.

The rush of infrastructure (and focus on growth) permeated from the upstream as midstream companies — historically low-volatility, long-lived cash generators — undertook multibillion-dollar investment programs to aid their producer customers. E&Ps had the resource and needed to monetize it. They signed contracts to incentivize the construction of large pipelines, processing plants and fractionation facilities to bring crude oil, natural gas and NGLs to market. Projects underwritten by acreage dedications alone (with no drilling) do not yield volumes to transport, however, and the midstream sector had to live with the overbuild. By late 2019 and early 2020, the midstream companies’ customers had slowed development programs and producer bankruptcies swelled in the early months of the pandemic, leading many midstream companies to cut their dividends and live within free cash flow. There was no market for external funding.

The most critical driver of behavioral change has been bankruptcies in the oil and gas industry, which totaled 109 in the 2019-21 period (red bar segments in the right half of Figure 2). The specter of failure spurred capital discipline, a conservative approach that flew in the face of how E&P management teams operated and were compensated over the past 10-plus years. Still, the E&P sector and the broader industry had no choice. It needed to learn to live on its cash flow.

The “glass-is-half-full” approach to the COVID pandemic is that it created an off-ramp to the treadmill of boom-and-bust capital spending. Shale wells generally have high initial production (IP) rates and a steady decline in output thereafter — more wells need to be drilled to maintain the same production level, much less any production growth. If producers stopped spending, production would fall — a lot — which is what happened in 2020, when U.S. production fell from ~13.0 MMb/d to 10.0 MMb/d in just a few months.

Once the band-aid was ripped off, many energy management teams focused on living within cash flow, paying down debt, and returning capital to shareholders through stock buybacks and dividends. While the market was skeptical of this newfound discipline, it was clear that there was a change in behavior within executive suites. As production fell, prices rose, and energy companies could develop existing resources more economically due to excess capacity in oil service equipment and midstream egress. As E&Ps returned capital to shareholders, their equity values rose, and they repeated the narrative.

Importantly, today, producers are benefiting from their recent discipline. Even though prices have fallen, their fiscal positions are generally strong and their drilling programs are intact. Producers see the real-time benefits of being disciplined during the excess, as price volatility will remain with long-term, capital-intensive industries. However, balance sheets are secure in the current downdraft, and companies are still contemplating some degree of return on capital. Capital discipline in the peak moments allows for thoughtful actions in the downturn. The energy industry is learning the long-term benefits of living within cash flow.

E&Ps were not alone in understanding this new market paradigm, because while production growth slowed, it still occurred. This production growth began to fill existing midstream facilities, which allowed midstream companies to charge progressively higher rates or retain the capacity for their systems. It also saw an increase in the rig count, bringing higher day rates. That said, midstream and oil service companies were also disciplined. Without long-term contracts, there would be no speculative spending, new facilities would not be built, and production growth would remain measured.

Investors have rewarded this discipline, and as the cyclicality of the global energy industry continues, these businesses should be able to return more capital to shareholders over extended periods — even when oil and gas prices sag, as they did in recent weeks until the Saudis and other members of OPEC announced production cutbacks. Additionally, as leverage ratios have fallen, still more of the incremental cash flow E&Ps generate in the future will be returned to shareholders and will no longer be needed to refund debt liabilities accrued in the growth stage.

The recent shift in focus to returning capital to shareholders is real. While E&P capital expenditures by a subset of U.S. E&Ps (red line in Figure 3) have been rising modestly since the depths of COVID, consistent with increases in oilfield services costs, their free cash flow (green line) has been growing faster. This increase in free cash flow is being returned to the investor — the gray-shaded area shows dividends and share repurchases, which have soared over the past two years. As you can see, aggregate quarterly payments to dividends and share repurchases by these E&Ps have grown more than eightfold since 2017: from $3.6 billion back then to $30 billion in 2022. E&P leverage ratios for the same producers are well below their 2017 levels, declining from 3.9x in Q1 2017 to 0.8x as of Q4 2022.

Unlike other industries that were forced to “reinvent” themselves to reflect changing public demand — i.e., Netflix (DVDs to streaming), Pepsi (soda to snack foods), Microsoft (desktop to cloud), Apple (computers to iPhones to iPads), and banks (branches to online) — energy companies needed to change how they developed their assets and resources, not how they were used. Put another way, energy company executives control their destiny, a powerful but potentially dicey position.

The hydrocarbons trapped in U.S. shale are a vast but ultimately finite resource. With the majority of the best, most productive acreage and stacked plays already identified, E&P companies have largely morphed into P (producer) companies, with the E (exploration) part playing only a minimal role. Optimizing the P through technology, efficiency, and asset integration will be the model of success in the future.

A couple of points are worth making here. One is that the capital discipline and carefully managed growth that has become E&Ps’ mantra continues to work well for them, even when oil and gas prices sag. The other is that the world is realizing that oil and gas will remain leading and critically important elements of the global energy mix for many decades. With this in mind, E&Ps can decide for themselves whether to maintain their sole focus on oil and gas or expand into alternative sources of energy as well. We’ll discuss the challenges associated with the latter in an upcoming blog.