Editor’s note: This is one in an occasional series of articles examining the state of major U.S. shale plays at the end of 2022.
The scene for U.S. shale in 2023 is setting up as a more dramatic iteration of the second half of 2022: more consolidation, higher inflation and more aggressive capital return programs.
Top analysts and market watchers anticipated growth in 2022 on the order of 1 MMbbl/d of oil. It didn’t happen in 2022, and it’s even less likely to occur in the year ahead. Most forecasts put growth around 500,000 bbl/d for both years.
There is no one issue that’s slowed growth. Rather, it’s a confluence of things: cost inflation; the corporate commitment to return cash to shareholders; a lower rate of reinvestment in operations; and the aging of even the most prolific plays, which is diminishing the production of some wells developed by some operators.
“We’re 15 years into this, and we’ve learned a lot along the way, but there’s not as much virgin rock out there as some people would like to think,” said Andrew Gillick, managing director and energy sector strategist at Enverus.
During past periods of shale weakness or operational hiccups, producers have innovated their way out of a slowdown. In 2017, Permian Basin pure-play Pioneer Natural Resources Co. shocked the market with a revelation during the second-quarter earnings season that its gas-to-oil ratio (GOR) in the Midland Basin was increasing. In short, the more a well produces, the more its pressure drops. Gas rises into the oil reservoir and dilutes the resource. Not a marketable proposition at the time for companies that largely viewed oil as the profit and gas as its byproduct.
Certainly, rising GOR wasn’t a Pioneer-specific problem. It was a shale drilling challenge that other players confronted too. A massive sell-off of Permian producers’ stock ensued.
Undaunted, Pioneer’s engineers went to work. The firm tested and retested spacing patterns and pad development. Field managers reworked the producer’s aggressive flowback strategy. Operations teams tweaked other elements of the development strategy.
The GOR panic passed, and Permian producers’ share prices popped back up.
Then came the angst of parent-child well interference. This is a phenomenon of secondary wells being placed so close to initial wells that they tap into the first flows, diminishing the returns of both.
Operators went back to the drawing board and found ways to modify well spacing to their advantage. The endeavor was so successful that “manufacturing mode” became a common refrain of earning calls. And indeed, as production records rose—peaking in 2019 at 12.3 MMbbl/d—the effort succeeded.
U.S. oil production is inching close to its pre-pandemic levels, but it’s a struggle.
With the falling leaves of the season in October, some of the largest U.S. oil producers in October signaled a slowdown productivity and volume gains in the top shale plays,
Pioneer leadership told investors the company will reshuffle its drilling portfolio in 2023 to target wells with potentially higher returns, a move to boost lagging productivity levels.
Chevron Corp. and Exxon Mobil Corp. also expressed caution against their Permian oil and gas volumes. Chevron’s full-year volume will be near the low end of its 700,000-boe/d to 750,000-boe/d guidance. Exxon Mobil dropped its 2022 forecasted gain to 20% from an earlier expectation of 25%.
“Productivity came in a little less than we anticipated, and we wanted to rectify that,” Pioneer president Richard Dealy said.
Nevertheless, the Pioneer team remains optimistic.
“We’re really just reshuffling the portfolio and bringing forward higher-return wells and deferring some of the wells that were great wells, but … we got higher thresholds that we can hit. And so, we’ve just deferred those and reallocated the capital,” Dealy said. “But the reality is we have high confidence that we’re going to achieve the results that we have laid out here.”
Bottling a lightning bolt
The U.S. energy business is rich with some of the most creative and innovative minds of any industry, Gullick told Hart Energy. And so, it’s conceivable that the next big thing could revive production.
“I’m not going to sell technology short. I’m not going to sell this industry short,” he said. “But I don’t think technology is going to find a new basin.”
If commodity prices remain high, there is more opportunity to develop lesser quality rock. But that doesn’t make the wells produce better, it only makes them somewhat profitable.
Indeed, operators may not have to invest as much in research as they might engage in strategy and planning to boost results, Gillick said.
“I think better planning might bail us out, but I’m looking at the industry now in this mature manufacturing mode where capital is being returned to shareholders. There’s a focus on ESG or on holistically running the companies in a way maybe that was different than before,” he said. “I’m not sure technology is going to save us.”
Still, the U.S. Energy Information Administration (EIA) estimates the nation’s oil production in 2023 will top 2019’s record 12.29-MMbbl/d output.
Meanwhile, there are steps operators can take to stem declines. Better budgetary planning for asset pace and development and tighter guidance to Wall Street could help.
Moreover, a handful of companies missed meeting production guidance because offset wells degraded their production.
“It’s either you’re not looking out the window to see what your neighbor is doing right next to you or you’re not following the permits or you’re not talking to your peers,” Gillick said. “I think that just comes down to planning.”
Some firms blamed supply chain issues for production disruptions. During the third-quarter earnings period, SM Energy Co. reset its second-half guidance downward by 10,000 bbl/d based on delays and offset activity.
Several companies advised investors of capital spending boosts mostly to manage growing inflation.
Producers can no longer plan for several years of $40 breakeven rates, Gillick said.
“There’s a couple of years, but that’s changing too, as costs go higher,” he said. “The rock is the same, but the well doesn’t cost $6 million anymore, it costs $8 million. So that changes your return profile. That low-cost breakeven inventory is evaporating every quarter as prices go up.”
In general, the 10% to 15% cost inflation rate producers reported in 2022 will likely carry forward into 2023, he said.
Top U.S. Shale Private Operators
|Operator||Gross boe/d (average 1H22)||Gross bbl/d (average 1H22)||Gross Mcf/d (average 1H22)||U.S. Rigs Running|
|Ascent Resources LLC||398,755||15,559||2,299,166||2|
|Rockcliff Energy II||220,779||347||1,322,573||4|
|Tug Hill Operating LLC||130,646||7,621||738,150||5|
|[21% total]||[11% total]||[27% total]||[20% total]|
For small operators and private producers, the rate of inflation could climb as high as 20%.
“They don’t have long-term contracts, so they get dinged now or even earlier, whereas the larger operators have longer-term contracts,” Gillick said. “They’re going to get dinged next year, and the average cost will be up 20%. But for some operators, it’s already more than that. For others, it’s not that much.”
Analysts anticipate the consolidation that began taking shape during the second half of 2022 will continue in 2023. After a lackluster first half, upstream oil and gas M&A jolted awake in the third quarter with $16 billion in announced transactions.
“Operators that are bigger, more liquid and with more inventory have seen much bigger capital inflows over the last six to 12 months than the smaller-cap operators with shorter inventory lives,” Gillick said. “If you think about the 2021 mantra, [investors] didn’t care about how much inventory you have; the idea was just return all the capital you can as fast as you can because nobody’s going to need crude oil in 2030.”
But then, he said, something happened during the past 12 months to shake the system.
“People, I guess, opened their eyes to realize, ‘Oh, we may need this crude oil stuff a little longer’,” he said. “And so that inventory question never came back.”
Consequently, the sector’s equities have outperformed the commodity almost 30%, he said.
“That means the long money that hasn’t been here—like the Fidelity long-term mutual fund money—is coming back.”
All of which points to continued consolidation, Gillick and other analysts have said. Companies must grow to continue returning capital to shareholders. Most will opt to do that through acquisitions that may rely on equity.
“If you’re a mid-cap, you’ll have to bite the bullet at some point and merge maybe with another small or mid-cap operator,” Gillick said.
Setting the scene for 2023
Despite some instances of faltering production, cost overruns and general volatility, the U.S. E&P space showed a robust market performance. At the end of November the sector was outperforming the S&P 500 by 77% and the front month Brent price by 47%, said analyst Neil Mehta at Goldman Sachs.
“As we position for 2023, while we still see attractive risk/reward in a firm oil macro environment, we believe that focus will shift to stock picking,” he said in a note to investors.
Companies such as EOG Resources Inc. and Hess Corp. surprised to upside on asset quality and execution, according to Mehta. Gas-weighted Antero Resources Corp. benefited from the return of capital thesis; on the large company side, ConocoPhillips Co.’s performance was a solid example of the market supporting those producers that elevated shareholder returns, he said.
Several executives lamented the undervalued state of their stocks, which traded at a valuation discount for much of the year. Among them, Chesapeake Energy Corp. and Ovintiv Inc. stood out. On the other side of the equation, Occidental Petroleum Corp. benefited from its balance sheet repair.
In its “Macro Forecaster,” Enverus Intelligence Research, a subsidiary of Enverus, reported that near-term recession risks, fallout from Russia’s war on Ukraine, COVID-19’s lingering depression on demand in China, and OPEC’s oil supply mechanizations will impact oil supply.
The group estimated those factors may coalesce in $100/bbl oil in 2023; Nymex natural gas may dip near $3.50 by summer.
Analysts at Goldman Sachs remain optimistic for oil prices in 2023, citing near-term potential for improving demand from China and lower U.S. shale growth based on capital discipline, tight services and inflation, and the impact of the OPEC+ quota reduction.
[Top cos/oil production list goes around here; we can cut it down if the list of 50 is awkward; but please ensure the gas cos list uses the same number]
Top 10 U.S. Shale Producers (by oil production)
|Rank||Operator||Gross bbl/d (average 1H22)|
|5||Pioneer Natural Resources||493,507|
“Longer term, we believe underinvestment will drive lower supply growth and keep oil prices higher,” Mehta said. “However, we note that E&Ps are increasingly already pricing in an improvement in oil prices relative to the current oil futures.”
Relative to consensus estimates and strip pricing, Goldman is slightly bullish. Goldman pegs strip prices for WTI oil at $105/bbl in 2023 before steadying at $85 for the next two years. Consensus estimates forecast 2023 oil in the lower $90s before finding equilibrium in the mid-$80s. Strip prices fall to $70/bbl in 2025 estimates.
Accounting for gas
In December, the EIA forecasted U.S. production of dry natural gas to average about 100 Bcf/d from December through March. Weather-related declines from freeze-offs and the potential for extreme winter weather anticipated in December dragged the estimate down some 0.5 Bcf/d from November expectations.
Top 10 U.S. Shale Producers (by gas production)
|Rank||Operator||Gross Mcf/d (average 1H22)|
The EIA raised its 2023 forecast for all U.S. natural gas production in a December “Short Term Energy Outlook” report by almost 1% from the November estimate.
The researchers said gas production in the Permian Basin is likely to be limited early in 2023 by insufficient pipeline capacity to bring associated natural gas production to market, but those constraints will be resolved in the spring.
Growth in LNG exports will likely increase in 2023, following a peak during the first half of 2022, the EIA said. Those exports are tracking for a new record close to 12.5 Bcf/d in March 2023 and reaching up to 12.7 Bcf/d by year-end.
Henry Hub spot price is expected to average more than $6/ MMBtu in the first quarter, up from November’s monthly average of about $5.50/MMBtu.
“We expect natural gas prices will begin declining after January as U.S. storage levels move closer to the previous five-year average, largely as a result of rising U.S. natural gas production,” the agency said in its report. “However, the possibility of price volatility remains high.”
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