This report does not constitute a rating action.

E&P Companies Will Rein In Spending To Focus On Cash Flow

E&P companies remain focused on generating free cash flow and delivering shareholder rewards. 

After two years of significant capital spending increases in 2022 and 2023 (following the lean COVID-19 years of 2020 and 2021), U.S. E&P companies pulled back on capital expenditure (capex) in 2024, spending in aggregate about 1% less than in 2023, in line with our forecast from last year. Lower spending levels last year were due to ongoing capital efficiency improvements, natural gas price weakness and deferral of natural gas well completions, an operational pause as companies digested large merger and acquisition (M&A) transactions, and companies’ ensuring they would have sufficient excess cash flow to distribute to shareholders. With the WTI crude oil price averaging more than $75/bbl, E&Ps could keep spending well within cash flows while modestly growing production and funding substantial shareholder rewards. Producers funded their M&A transactions largely with equity, enabling most to maintain their strong balance sheets.

Chart 1

This year, WTI oil prices have fallen to about $60/bbl, and we expect operating cash flows to weaken for most oil-weighted producers, leading to modest reductions in capex. However, many operators are now in a stronger position compared with prior downturns, having significantly improved their balance sheets through years of capital discipline and debt reduction. U.S. producers are cutting back on capital not because their projects are uneconomic at the wellhead at $60/bbl, but because they want to keep spending levels well below internally generated cash flow and continue to reward shareholders via dividends and share repurchases. Deferring production until prices potentially improve can also boost projects’ net present value and overall returns.

In general, E&P companies can be more flexible with capex today than a decade ago due to the increased proportion of production from shorter-cycle unconventional plays, which have matured from the “land grab” and exploration/testing phase to manufacturing mode. The U.S. Energy Information Administration (EIA) estimates about 65% of U.S. crude oil and nearly 75% of U.S. natural gas comes from unconventional plays, including shales and tight formations. These plays are characterized by low single-well drilling and completion costs, the limited need for exploration drilling, and the ability to bring production online quickly (typically within a few months). As a result, unconventional producers can ramp spending up or down relatively quickly depending on oil and natural gas prices, ultimately impacting production.

While at first producers are more likely to defer completions or turn-in-lines (TILs) to rein in spending, they can also lay down rigs as they roll off contracts or ultimately drop rigs prior to contact end and pay early termination fees. U.S. producers have already started to lay down rigs this year, with the U.S. rig count down about 5% relative to 2024, and we expect that decline to accelerate during the course of the year. Still, many producers remain hesitant about dropping rigs, as doing so could erode efficiency gains. At the same time, according to data from Primary Vision, the U.S. frac spread count is down 25% year over year as of mid-May.

We expect U.S. E&P spending to decrease 5%-10% this year. 

Although initial 2025 budgets indicated a modest aggregate spending decline of 0%-5%, the recent drop in oil prices, capital discipline, and ongoing capital efficiency improvements have led to several announcements of additional reductions. For the companies that have announced capex reductions in their first quarter earnings calls, the additional drop has been about 3%, although in Diamondback Energy Inc.’s case, the incremental reduction was 10% relative to prior guidance. Not surprisingly, most of the capex reductions have been on oil-focused plays, as natural gas prices have increased relative to 2024 and are widely expected to rise further.

Overall, we now estimate the year-over-year aggregate U.S. capital spending drop could be 5%-10%, assuming WTI oil prices remain about $60/bbl. Our numbers are pro forma for major mergers and acquisitions completed in 2024, such as Exxon Mobil Corp./Pioneer Natural Resources Co., Diamondback Energy/Endeavor Energy, ConocoPhillips/Marathon Oil Corp., and Chesapeake Energy/Southwestern Energy (now Expand Energy Corp.), among others.

Chart 2

Chart 3

U.S. Oil Spending Will Decrease, But Gas Spending Will Rise

We expect oil-focused U.S. E&P companies to reduce spending by about 10% this year. 

At the beginning of the year, budgets for the oil-focused E&P companies indicated about a 7% year-over-year drop in spending. Since then, oil price volatility has increased due to trade uncertainty, the potential for an economic slowdown, and the Organization of the Petroleum Exporting Countries Plus (OPEC+) decision to release higher-than-expected volumes back into the market. Based on the most recent rounds of conference calls, several oil producers have reduced their budgets, but not by much considering the nearly 20% decline in oil prices since early January. For the companies that have announced capex reductions on their first quarter earnings calls, the average drop in full-year capex guidance has been about 3%, with nearly all of the reductions from oil-focused producers.

We expect more companies will announce full-year capex reductions as they report earnings over the next few weeks, and potentially later in the year, bringing the full-year drop in capex to about 10% for the oil-focused U.S. group. If oil prices fall to the mid-$50/bbl area or lower, we would expect an even more significant pullback in capital spending. Oil producers were only moderately hedged heading into 2025, and thus they are feeling the full impact of lower prices on cash flows.

We expect aggregate oil production for this group to be essentially flat in 2025 despite the 10% drop in spending, highlighting producers’ ongoing capital efficiency gains. However, we would expect a more pronounced impact on production next year if lower spending levels persist.

Chart 4

Chart 5

We expect U.S. natural gas producers to increase capital spending and activity ahead of the likely uptick in demand. 

Unlike oil-focused producers, natural gas producers are planning to ramp up spending and completion activity to capitalize on the recent uptick in natural gas prices and expectations for further price improvement in late 2025/early 2026. Prices are being buoyed by the uptick in natural gas feedstock demand for liquefied natural gas (LNG) export facilities, which S&P Global Commodity Insights (SPCI) estimates will increase by more than 6 billion cubic feet per day (bcf/d) from October 2024 to March 2026, and essentially double to 25.7 bcf/d in 2029, adding more than 25% to current U.S. natural gas demand. Prices are also being supported by increasing power generation demand from AI and data center development. The growing impact of AI on in-basin power generation and natural gas demand in Appalachia was a key focus in first-quarter earnings calls for several natural gas producers.

We estimate natural gas-focused U.S. companies will increase capital spending this year by about 6%, which should translate into about a 5% uptick in production. The growth in 2025 will also be supported by releases of shut-in production in response to the low natural gas prices in 2024, drilled-but-uncompleted wells and delayed TILs.

Chart 6

Chart 7

U.S.-based integrated oil companies’ capex will be more resilient. 

We expect aggregate capital spending by U.S. integrated oil companies (Exxon Mobil Corp. and Chevron Corp.) to show a modest uptick of about 2% this year, primarily due to ExxonMobil’s intention to grow volumes in the Permian Basin following its acquisition of Pioneer Natural Resources in 2024, partially offset by both companies’ improved capital efficiencies. In addition, both ExxonMobil and Chevron are developing a number of large scale, long-cycle offshore projects around the globe that are unlikely to be deferred at current commodity prices. Overall, we expect integrated producers’ capital programs to be more resilient to changes in oil and natural gas prices relative to their independent peers due to their strong balance sheets and greater willingness to outspend cash flows temporarily in order to maintain shareholder distributions.

Canadian Producers Continue To Invest

We expect Canadian companies will increase spending again this year, driven primarily by long-cycle oil projects. 

The spending dynamic in Canada remains underscored by long-cycle oil sands thermal and mining projects which, due to their high upfront and fixed costs and the need to run upgraders and refiners at a certain capacity to maximize efficiency, has resulted in steady capital spending increases since 2020. In addition, since mid-2024 Canadian oil producers have benefited from the Trans Mountain Expansion pipeline expansion that added 590,000 barrels per day of takeaway capacity to Canada’s West Coast. As a result of the additional capacity, the Western Canadian Select (WCS) heavy oil differential narrowed to $12-$13/bbl from $18-$20/bbl in 2022-23, and is currently about $10/bbl. While the current exceptionally narrow differential is supported by regular seasonality from turnaround activity and U.S. refiners ramping up for peak asphalt/paving season, we believe U.S. demand for Canadian heavy barrels has also increased recently given the lack of alternative sources of heavy crude (Canadian heavy barrels in the Gulf Coast typically compete with barrels from Mexico and Venezuela). We expect future WCS differential volatility will be more limited than in the past, which should support the economics of oil projects.

On the natural gas side, Canadian gas prices, including Alberta Energy Co. (AECO) Hub, remain weak, and thus we expect producers to remain focused on liquids-rich gas plays given the stronger pricing fundamentals for Canadian-produced condensate. In Canada, condensate is used as a blending agent for bitumen production, and we estimate Canada only produces roughly two thirds of its domestic condensate demand. Given the high liquids component in Canada’s most prolific gas-producing regions like the Montney, Canadian producers can break even at exceptionally low (in some cases even negative) gas prices because the offsetting condensate component of the production prices roughly in line with WTI. Furthermore, Canada’s first LNG export facility, LNG Canada Phase 1, is anticipated to begin exporting this summer (1.8 bcf/d of capacity). We anticipate most of this incremental demand will be met with supply additions as anticipated LNG export demand and strong condensate pricing fundamentals are supporting higher activity in Canada’s liquids-rich gas plays. Accordingly, we expect the Montney will remain the key area of natural gas production growth in Canada.

Overall, we expect Canadian oil and gas companies to increase aggregate spending by about 3% after a 9% uptick in 2024. We forecast this will lead to a nearly 5% increase in Canadian oil and natural gas production as producers are achieving efficiency gains similar to their peers south of the border.

Reinvestment Rates Remain Well Below 100%

Capital efficiencies have allowed companies to do more with less, leaving ample allocation for shareholders. 

We do not expect lower capex this year to result in lower total production in 2025 but could see a more pronounced impact in 2026 if lower spending levels persist. This is due in part to the ongoing capital efficiency improvements producers have achieved over the past few years. Despite a nearly 28% drop in the North American rig count between 2019 and May 2025, production has increased as companies have continued to improve capital efficiencies. The improvements have been in large part due to changes in drilling and completion techniques, including the drilling of longer laterals, more targeted drilling and fracking, and integrating real-time data and technologies including artificial intelligence. Oilfield equipment and services (OFS) companies have also been doing their part by finding ways to lower costs for their customers, including using lower cost fuels, developing faster tools, and increasing automation of standard processes. The recently enacted 25% tariff on imported steel will have a low-single-digit percent impact on well costs, though this will likely be offset by gains in operational efficiency. We believe most 2025 budgets remain largely unaffected by tariffs due to locally sourced and prepurchased materials.

Greater capital efficiency, combined with a commitment to reward shareholders and maintain strong balance sheets, has kept reinvestment rates for the North American E&P industry well below 100% since 2020. We estimate capex as a percentage of cash flow from operations fell to the mid-30% area in 2021 and 2022 from about 100% in 2020, but has since climbed back to the 55%-60% area. Companies have kept their focus on cash flow generation and returns and are no longer chasing production growth at any cost.

Chart 8

Lower capital spending will help E&P companies support cash flows amid weaker oil prices but could hurt OFS providers in the near term. 

While lower capex will initially offset the impact of lower oil prices for E&P companies, a more significant and sustained drop in activity will likely lead to production declines. This is particularly true for unconventional plays, where we estimate average decline rates are about 30% per year (with first-year decline rates often double that). Based on our current commodity price deck published on April 10, 2025, we assume oil and natural gas prices will improve next year, which should lead to higher drilling and completion activity. As a result, we do not expect many rating actions for E&P entities due to lower oil prices and reduced capital spending levels in 2025.

For OFS companies, however, lower E&P capex means lower revenues and typically weaker margins as OFS providers offer price discounts to retain business. We expect cash flows for OFS companies to come under pressure this year, particularly for smaller players focused on U.S. land operations. We do not currently anticipate a significant reduction in offshore or international activity given the longer-cycle nature of these projects. In order to offset the reduction in activity and resulting cash flow from operations, we would expect OFS companies to reduce costs where possible and rein in share repurchases. This should enable most OFS providers to protect cash flows and ratings in the near term, but ultimately, they will need activity in the oilpatch to resume.

Related Research

• S&P Global Ratings Lowers Its Oil Price Assumptions On Potential Oversupply; Natural Gas Price Assumptions Unchanged, April 10, 2025
• North American Upstream Capex Growth To Decelerate In 2024 Amid Greater Capital Efficiency Gains, May 1, 2024

Primary Contact:	Carin Dehne-Kiley, CFA, New York 1-212-438-1092; carin.dehne-kiley@spglobal.com
Secondary Contacts:	Laura Collins, Toronto 1-4165072575; laura.collins1@spglobal.com
	Victoria Godunova, New York 1-212-438-0280; victoria.godunova@spglobal.com
Contributor:	Valeria Briones, New York ; valeria.briones@spglobal.com