The words “volatility” and “uncertainty” topped most earnings calls as chief executives of the largest U.S. producers reported on their first-quarter performance and tempered expectations for the rest of 2025.
Most said they have calibrated for an unknown depth and duration of the macro environment, which has taken a downward swing amid President Donald Trump’s tariff negotiations and whiplash implementation, as well as the OPEC+ decision to add barrels to the market earlier than planned.
Going forward, the second-quarter rig count may be flat to down by 25 rigs, according to TPH estimates based on driller guidance during the reporting period. Given that the Baker Hughes rig count has dropped by 11 since late March, TPH analysts said they are “biased to the lower end of the range.”
Nabors CEO Tony Petrello told investors during an earnings conference call that smaller operators are adding rigs while larger operators are reducing them.
The drilling company surveyed its largest Lower 48 industry clients—covering 14 operators that account for roughly 48% of the region’s working rig count at the end of the first quarter—and found that the group expects to reduce its rig count by 4% through the end of this year for a total 2025 rig reduction of 7%.
“Over the last couple of months, we have seen the impact of these customer plans, but we have managed to replace this drop in activity with a number of contracts,” Petrello said. “We expect this trend to continue.”
EOG Resources
EOG Resources is reducing its capex at its guided midpoint by $200 million while still delivering roughly 2% year-over-year growth, chairman and CEO Ezra Yacob told investors during first-quarter reporting.
The $200 million cut further pares its already reduced 2025 iron and pressure-pumping plan, resulting in a total of 80 fewer net completions and three fewer rigs than in 2024 in the oily Delaware Basin, Eagle Ford Shale core and Powder River Basin.
“We have plenty of activity there” already, COO Jeff Leitzell said in a May 2 earnings call. “They’re kind of finely oiled machines, I would say.”
Capital discipline at EOG means more than just focusing on high-return assets, Yacob said. “It’s about being agile and responsive to the broader macro environment. We remain constructive on both oil and gas playing a significant role in the long-term need for reliable low-cost energy,” he said.
“The near-term, however, is reflecting speculation on oil demand impacts associated with tariff announcements, which has softened prices. We expect to see a return to market fundamentals and pricing firming up as more transparency is applied to the tariffs and negotiation turns to implementation.”
At $65 WTI and $3.75 Henry Hub, the company expects to generate $4 billion in free cash flow, said CFO Ann Janssen.
“We can fund our $6 billion capex program this year as well as the regular dividend at WTI oil prices averaging in the low-50s. We remain committed to optimizing our balance sheet and reaffirm our targets of $5 billion to $6 billion in cash and total debt to EBITDA [earnings before interest, taxes, depreciation and amortization] at less than 1 times at bottom cycle prices of $45 WTI.”
ConocoPhillips
During ConocoPhillips’ earnings call, CEO Ryan Lance noted the current environment is “marked by both uncertainty and volatility,” and that the ultimate depth and duration of the price environment is unclear.
But “ConocoPhillips is built for this with clear competitive advantages,” he said.
“We have a deep durable and diverse portfolio. We have decades of inventory below our $40 per barrel WTI cost of supply threshold, both in the U.S. and internationally,” Lance said. “And our advantaged U.S. inventory position in particular should become increasingly evident as the market sorts through the inventory haves and have-nots in the current environment. We believe we are the clear leader of the haves.”
The company’s integration of Marathon Oil is ahead of schedule, Lance said, and the company is reducing some $500 million from its capital plan and showing a $200 million reduction in operating cost, while maintaining production guidance.
“We have flexibility in our capital program we could exercise should conditions warrant. We’ve been here before and we know how to manage through a more challenging environment,” Lance said.
Coterra Energy
Tom Jorden, Coterra Energy CEO, said the company will drop three of its 10 rigs in the Permian Basin, and Coterra is “prepared for this to last a while” as OPEC+ is planning to add another 800,000 bbl/d to the market as fear of a global recession builds.
“We were built for this. Coterra is an ark, not a party boat,” Tom Jorden, chairman, president and CEO, said during the May report, referencing a “pristine balance sheet” and the E&P’s $2.1 billion of 2025 estimated free cash flow at $60 oil and $4 gas.
A further drop in prices below $50/bbl would be the tipping point where Coterra might cut drilling and completions activity further, Jorden said.
Coterra is already “concerned that oil prices could further weaken,” he added.
“I hope we’re wrong on that. But our experience tells us that, when you see these events and you see the possibility, be prepared for the worst-case scenario.”
If WTI were $50, “the returns are not bad. I mean, they’re certainly better than if we rewind to not too many years ago with anything we were experiencing” with $20 oil and unwanted tankers full of LNG during COVID-19.
“But we’re making these steps because we’re concerned about future weakening in oil prices,” he said.
Diamondback Energy
The current macroeconomic view is “challenging at best,” said Diamondback Energy CEO Travis Stice during first-quarter reporting. Pointing to macro uncertainty and the OPEC+ plan to increase volume, he said the industry is still looking at headwinds.
“What we tried to put together was a response to those kind of macro conditions,” he said.
As such, Diamondback is cutting $400 million, three drilling rigs and one frac spread. The intent is “to maximize the capex reduction while minimizing volume impact.
“And at the same token, provide us a runway for maximum flexibilities to respond in either direction in the future quarters as this evolving supply demand imbalance works its way through the system.”
Hitting the brakes on spending will probably reduce net production by 20,000 bbl/d. That will put second-quarter guidance close to 495,000 bbl/d and the third quarter to 485,000 bbl/d, Stice said.
Stice sent shockwaves through the industry with his letter to shareholders released the evening prior to the company’s May 6 earnings call. He anticipated that onshore oil rigs will decline by 10% by the end of the second quarter and continue to decline well into the third.
“This will have a meaningful impact on our industry and our country.”
Chord Energy
Meanwhile, Chord Energy is going long in the Bakken.
Chord Chief Commercial Officer Darrin Henke said the producer is encouraged by its first three 4-mile middle Bakken wells, the first of which began production in the first quarter.
The first 4-mile Bakken well was spud in late 2024 and completed in February. Chord reached a total depth exceeding 30,400 ft, vertical and lateral combined, while cleaning out frac plugs.
“The clean-out was executed in only one run and was much faster than we originally expected, leading to a total well cost approximately $1 million below the original budget,” Henke said during a May 7 first-quarter earnings call.
CEO Danny Brown said the firm will maintain “substantial operational and financial flexibility to moderate activity and maintain an efficient returns focused program with strong free cash generation.
Chord has one of the lowest base decline rates of its peers, Brown said, and no material drilling obligations on its acreage, which is largely held by production. The firm is reducing its activity from five rigs and two frac crews to four rigs and one frac crew. Both original and current guidance reflects the return of the second frac crew during the fourth quarter.
“This allows us to monitor the macro environment at a lower activity pace and gives us the option to either bring back this second frac crew or just keep one frac spread through the end of ’25 and into 2026,” he said.
The company is also cutting its full-year capital spending plan by $30 million, Brown said. The reduction reflects program efficiencies “and does not currently contemplate any reductions to activity until the third quarter to make the final call.”
Occidental Petroleum
At Occidental Petroleum, CEO Vicki Hollub said the company’s cash flow priorities aim to position Oxy for long-term success.
“Debt reduction remains a key focus, and we are committed to strengthening our financial position to support a more meaningful return of capital to common shareholders across the commodity cycles,” Hollub told investors during a conference call.
Year-to-date, Oxy has retired $2.3 billion in debt; during the last 10 months, the company has repaid a total of $6.8 billion.
“All 2025 maturities have been retired, providing us with a more comfortable runway over the next 14 months,” she said.
Hollub also noted the improvements generated by enhanced well designs and execution. In the Permian, Oxy has seen a 15% improvement in drilling duration from last year, which has reduced costs more than 10%, Hollub said.
The efficiency allowed Oxy to drop two rigs from its Delaware drilling program this year, while planning to bring more wells online with slightly increased production. The reduction, in conjunction with timing optimizations across Oxy’s portfolio, have allowed the company to reduce capex for the year by $200 million.
“We are closely monitoring the evolving macro backdrop and remain ready to take additional action if needed. We believe the diversity of our portfolio and flexibility of our development programs position us well to respond quickly to changing conditions,” Hollub said. “If commodity prices weaken meaningfully, we are prepared to scale back activity and manage cost prudently, preserving value through the cycle just as we did in 2020.”
