Big Oil’s Production Keeps Soaring Despite Deep Spending Cuts

Big Oil slashes capex but hits record production and rising revenues, risking future reserves.

What the company is saying

The analysis highlights that Exxon Mobil, Chevron, BP, Shell, and TotalEnergies have prioritized shareholder returns, collectively spending over $100 billion annually on dividends and buybacks—nearly 80% of earnings—over the past five years. The narrative frames this capital discipline as a deliberate shift following the 2020 oil price crash, with expansion plans deprioritized. EY's Matt Melnar and Patrick Jelinek are quoted to emphasize that production and reserve replacement are now diverging, and that U.S. natural gas is becoming central to industry demand trends. The announcement stresses efficiency gains and technological advances—such as AI-driven drilling and geosteering—as key enablers of record oil production and a 7% revenue increase in 2025, despite a 49% drop in capex and a 70% fall in acquisition spending. The tone is neutral and data-driven, with forward-looking remarks about natural gas positioned as industry observations rather than bold projections. The report does not bury negative trends, openly stating that oil reserve additions fell 11% and failed to fully replace production for the first time in five years.

What the data suggests

The disclosed numbers show a sector-wide pivot: over $100 billion per year has been returned to shareholders by the five largest oil majors, equating to nearly 80% of their earnings. Among the 30 largest U.S. E&P companies, capital expenditure dropped 49% year-over-year in 2025, with exploration spend down 11% to $4.8 billion—just 3% of total capex. Acquisition spending collapsed 70%. Despite this retrenchment, oil production reached an all-time high in 2025 and revenue rose 7%. The group represents about 43% of total U.S. oil and gas output. The U.S. DUC inventory fell to 4,972 wells in May 2025, the lowest since 2013, after 14 consecutive months of decline, reflecting a strategy of completing existing wells at $5–6 million each versus $8–10 million for new wells. Oil reserve additions from discoveries and extensions fell 11% year-over-year, failing to replace production volumes for the first time in five years. In contrast, natural gas reserves rose 14%, discoveries 21%, and production 18%, with reserve revisions positive for the first time in five years. The data supports management’s claim that efficiency and technology have offset lower spending, but also signals a growing risk to long-term oil reserve replacement.

Analysis

The announcement is a sector analysis with a neutral tone, primarily reporting realised, backward-looking data: capex, buybacks, production, reserves, and revenue are all quantified for 2025 or the recent past. The only forward-looking statements are general observations about the strategic role of natural gas and producers 'positioning for a future'—these are not presented as imminent or guaranteed outcomes, and they are clearly separated from the realised operational and financial metrics. There is no evidence of narrative inflation: the language is factual, and all major claims are supported by disclosed numbers. While the report highlights efficiency gains and technological advancements, these are described in the context of already-achieved production and cost outcomes. No large new capital outlay is paired with long-dated, uncertain returns; rather, the focus is on capital discipline and immediate operational results. The absence of profitability metrics (net income, EBITDA, etc.) alongside revenue and production means the maximum true_signal is weak_positive, per the Disclosure Completeness Rule.

Risk flags

• ●Reserve replacement risk is rising: oil reserve additions declined 11% year-over-year and failed to fully replace production for the first time in five years, suggesting future output could fall if not addressed.
• ●DUC inventory depletion limits flexibility: the U.S. DUC count dropped to 4,972 wells, the lowest since 2013, after 14 months of decline, reducing the ability to quickly ramp up production during price spikes or supply shocks.
• ●Sustained capex cuts may undermine future growth: with capital expenditures down 49% and exploration spend at just 3% of total capex, the sector risks eroding its long-term asset base despite current efficiency gains.
• ●Heavy shareholder payouts constrain reinvestment: returning over $100 billion annually—80% of earnings—to shareholders leaves less capital for new projects or acquisitions, potentially sacrificing future growth for near-term returns.
• ●Natural gas growth is positive but not a full offset: while gas reserves and production are up sharply, the sector remains exposed to oil market volatility and policy shifts, especially if reserve replacement trends do not reverse.

Bottom line

U.S. oil and gas majors are maximizing shareholder returns, spending over $100 billion a year on dividends and buybacks while slashing capex and acquisition budgets. This capital discipline has not hurt short-term performance: oil production hit a record in 2025 and revenues grew 7%, driven by efficiency gains and advanced drilling technology. However, the sector is now failing to fully replace oil reserves, with additions down 11% and DUC inventories at decade lows, raising medium-term supply risks. Natural gas is a bright spot, with reserves, discoveries, and production all posting double-digit growth, but this does not fully offset the risk of declining oil reserves. Investors should weigh the near-term cash returns against the mounting evidence that underinvestment could erode future output and flexibility. The most important takeaway: current financial strength is real, but the sustainability of these returns depends on reversing negative reserve trends.

Announcement summary

(NYSE:XOM), (NYSE:CVX), (NYSE:BP), (NYSE:SHEL), and (NYSE:TTE) have collectively spent more than $100 billion annually in dividends and buybacks over the past five years, representing nearly 80% of their earnings. EY reported that capital expenditure by the United States’ 30 largest publicly traded exploration and production (E&P) companies fell 49% year-over-year in 2025, with exploration spending dropping 11% to $4.8 billion, which is only 3% of total capital expenditures across the group. The 30 companies account for approximately 43% of total U.S. oil and gas production. Money spent on acquisitions by these companies fell 70% as the previous consolidation wave slowed. Despite reduced spending, oil production by the group reached an all-time high in 2025, and revenue increased 7%. EY’s Matt Melnar stated that oil production and reserve replacement are moving in different directions, with reserve replacement metrics no longer telling the full story. The companies have increased production volumes despite falling capex due to drilling efficiency gains, technological advancements, and a strategic shift toward shorter-cycle, high-return assets. Shale oil companies are drilling longer, horizontal wells, sometimes extending three miles or more, and completing multiple wells simultaneously to reduce execution times and service contract costs. Operators are deploying AI, machine learning, and predictive analytics to maximize production efficiency, cut operating costs, and extend well lifespans. Deep learning models process large 3D and 4D seismic datasets and historical drilling logs to map high-permeability zones. Predictive analytics determine the optimal volume of proppant, fluid, and pressure for maximum estimated ultimate recovery. AI-driven geosteering systems adjust drill bit trajectory in real time to maximize yields, and AI systems optimize gas injection rates for natural gas drilling. The U.S. shale boom has enabled wells to be drilled, fracked, and producing oil within months, shifting away from long-term offshore or mega field projects. Some assets, such as Exxon Mobil’s deepwater projects in Guyana, require heavy upfront investments but less additional capital to maintain. Companies have relied on Drilled but Uncompleted (DUC) wells to sustain production, with the U.S. DUC inventory dropping to approximately 4,972 wells in May, the lowest since 2013, marking 14 consecutive months of decline. Completing an existing DUC costs around $5 million to $6 million, compared to $8 million to $10 million for drilling and completing a new well. EY reported that oil reserve additions from discoveries and extensions declined 11% year over year, failing to fully replace production volumes for the first time in five years. U.S. shale producers now have less flexibility to ramp up output during supply crunches or price spikes. Natural gas reserves increased by 14% year over year, discoveries increased by 21%, and production grew by 18%, with reserve revisions turning positive for the first time in five years. EY’s Patrick Jelinek noted that U.S. natural gas is increasingly central to major industry demand trends, with strong growth in reserves, discoveries, and revisions indicating producers are positioning for a future where natural gas plays a strategic role.

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