IVY DIAZ, Digital Editor, World Oil
In the first half of 2025, U.S. oil and gas drilling slowed down, as companies cut back on the number of rigs, especially in major areas like the Permian and Eagle Ford. Oil prices were unpredictable, so operators focused on spending cautiously.
Production levels stayed steady, thanks to technology improvements—such as drilling longer wells and using more advanced completion techniques—but companies chose to buy smaller rivals or assets (“bolt-on” deals), rather than spend heavily on brand-new drilling projects.
Natural gas drilling was weaker, even though demand for U.S. LNG exports and related infrastructure continued to grow. At the same time, high equipment costs, supply chain delays, permitting hurdles, and some job cuts limited how much producers could increase activity, even with high-quality drilling prospects.
U.S. MARKET FACTORS
Fig. 1. U.S. Secretary of the Interior, Doug Burgum, spoke at CERAWeek 2025 by S&P Global in March, in Houston. Burgum chairs the recently created Energy Dominance Council, and is a key figure in advancing President Trump’s ‘unleash American energy’ order. Image: S&P Global
Geopolitical influence. While many operators hoped for fast-tracked projects and more profitable margins under President Trump, decisions by the new presidential administration in first-half 2025 have presented both pros and cons for drillers. Early in the term, executive orders, such as Unleashing American Energy and Unleashing Alaska’s Extraordinary Resource Potential reversed several Biden-era restrictions, reopening federal leasing and expediting permitting. On the other hand, tariffs have presented hurdles, particularly for operators in the Permian basin, where high duties on steel and aluminum have increased costs for critical equipment and materials.
Meanwhile, energy trade tensions — including tariffs on energy imports from Canada and Mexico — introduced uncertainty into supply chains and raised input costs for producers.
On the regulatory front, proposals under Trump, such as ending mandatory greenhouse gas reporting and aggressively reducing environmental review timelines signal further shifts aimed at lowering compliance burdens for operators. Trump also established the National Energy Dominance Council, chaired by Secretary of the Interior Doug Burgum, Fig. 1.
Collectively, these actions have sought to lower barriers and costs for drilling, production, and infrastructure development in 2025, but operational challenges, material price inflation and other external factors have created roadblocks.
Internationally, several geopolitical factors have added uncertainty to the U.S. oil and gas market. Increased sanctions on Russian oil, ongoing Middle East tensions, global trade policies and a wave of production increases from OPEC+ have caused oil prices to swing. While this has influenced capex planning and hedging, U.S. operators have largely stayed disciplined, keeping drilling activity steady-to-lower.
Fig. 2. Permian basin methane intensity declined by more than 50% during the 2022-2024 period. Image: Bloomberg.
ENERGY TRANSITION
In a recent report from S&P Global Commodity Insights, analysts found that Permian methane emissions have been reduced by over 50% between 2022 – 2024, Fig. 2. Despite the U.S. Permian basin accounting for nearly half of U.S. oil production and one-fifth of natural gas output, improved operations, better equipment and the utilization of A.I. and other advanced technologies have contributed to the sustainability shift, S&P found.
The LNG push. U.S. operators are positioning for LNG-driven demand growth moving towards 2030. Argent LNG is advancing its proposed LNG export terminal at Port Fourchon, La., with several major recent milestones. The project, targeting 25 MMtpa of capacity, has secured a long-term lease for a 900-acre site under a 90-year term, expanding from an earlier 144-acre footprint. Also in Louisiana, Monkey Island LNG is making headway, having recently selected ConocoPhillips liquefaction technology for the development, and contracted McDermott to perform key engineering work. Further north, Alaska LNG recently signed a 20-year offtake agreement with Japan’s JERA.
In a push against the renewables sector, President Trump has sought action to prevent several U.S. offshore wind projects, openly expressing his disapproval of the alternative energy he has deemed expensive, unreliable and unsightly. This is just one of several factors at play in the current political climate that has caused many U.S. operators to favor fossil fuels and conventional drilling as a safer strategy.
MERGERS & ACQUISITIONS (M&A)
Mergers and acquisitions in first-half 2025 largely shaped drilling programs, with acreage consolidation pausing short-term drilling as assets were integrated. Thus far, 2025 has seen a high volume of M&A activity in the U.S. Most notably, Chevron completed its $53 billion takeover of Hess Corporation, after winning an arbitration battle against ExxonMobil that spanned more than one year. Chevron swiftly began trimming its workforce, with layoffs announced shortly after the acquisition closed. Chevron has also announced it will merge Hess’ exploration team with its own, recognizing Hess’ strengths in a move that will bolster its own E&P strategy. The Chevron-Hess merger adds major upstream assets, namely the disputed Guyana block, but also significant acreage in the Bakken shale (~463,000 net acres), and other U.S. onshore and offshore producing and development assets.
Additionally in 2025, the U.S. has seen several multibillion-dollar shale consolidations, which we’ll cover in depth further in this article, as we get into specific regions.
Oil production. According to the U.S. Energy Information Administration (EIA), U.S. crude oil production slipped a bit in Q1 2025, to around 13.28 MMbpd, down from an average 13.44 MMbpd in Q4 2024.
The EIA expects U.S. crude oil production to climb to a high towards the end of 2025, averaging around 13.41 million bpd. In particular, production is expected to continue rising toward late 2025, with the maximum monthly or quarterly rates likely around December. After that peak, in 2026, the EIA predicts a small decline, with U.S. production expected to ease back to about 13.28 million bpd on average.
Oil prices. The U.S. EIA forecasts U.S. Brent crude prices to average between $59-60/bbl in 2026, compared to its forecast of around $66/bbl in 2025. The EIA expects U.S. WTI prices to drop to an average $47.77/bbl in 2026.
Natural gas supply/demand. Enverus Intelligence Research (EIR) identified 14.6 GW of retired coal capacity in the U.S. with strong potential for natural gas repowering, especially at sites near existing gas infrastructure. This trend could drive new demand for U.S. natural gas production and drilling activity, while longer-term opportunities in geothermal and nuclear point to an evolving role for upstream in supporting firm, low-carbon power.
The EIA expects overall U.S. natural gas production to stay mostly flat, averaging 117.1 Bcfd in 2025 and slipping slightly to 116.8 Bcfd in 2026. Output from oil-focused regions like the Permian, Bakken and Eagle Ford is slowing, since less gas is being produced as a by-product of oil drilling.
Henry Hub natural gas prices are expected to rise, with prices increasing to about $3.70/MMBtu in 4Q 2025, and rising further to around $4.30/MMBtu in 2026 (EIA).
U.S. RIG COUNT
In 2025, U.S. active drilling rig counts have generally been lower than a year earlier, reflecting continued caution among drillers. As of mid-September 2025, there are 539 rigs active. This is down from about 582 rigs in the same week of September 2024—roughly a 7–8% year-over-year drop.
The decline has been more pronounced in oil-targeted rigs: oil rigs have dropped significantly year-over-year, while natural gas rigs have held steadier or even increased in some periods. For example, around late August 2025, there were about 411 oil rigs and 122 gas rigs, compared to higher oil rig counts in 2024.
There have also been several multi-week stretches of decline, especially during mid-year (summer 2025), with the count often slipping to its lowest levels since 2021 in key oil basins like the Permian.
U.S. WELLS FORECAST/TRENDS
The above-mentioned factors, along with World Oil’s surveys of operators and state agencies, have all shaped this U.S. forecasting process. Accordingly, World Oil predicts that U.S. drilling will be down by 3.9% in the second half of 2025¸Table 1. Also, we expect footage drilled to decline 6.5% in second-half 2025.
U.S. GULF OF AMERICA/MEXICO
According to the EIA, the U.S. Gulf of America/Mexico is contributing about 13% of total U.S. crude oil production in 2025, and is expected to maintain that level through 2026. For natural gas, its share is much smaller — roughly 1% of U.S. marketed natural gas came from the U.S. Gulf. Several new field startups in 2025 have helped bolster production and offset decline from older assets, while more fields are anticipated to be online soon.
Fig. 3. Shell’s Dover subsea tieback connects to the existing Appomattox production system (pictured). Image: Shell
Production began from the Shell-operated Whale deepwater platform at the start of the year. In February 2025, ConocoPhillips announced it would sell its interest in the Ursa and Europa fields to Shell for a hefty $735 million. Shell and Chevron both started production from deepwater subsea tiebacks in April – Dover and Ballymore, respectively, with both oil majors working toward maximizing output from existing deepwater assets, Fig. 3. Chevron noted that Ballymore, with expected daily output of 75,000 bopd, will add to the company’s goal of reaching 300,000 net boed from the Gulf by 2026.
In June, TotalEnergies acquired a 25% working interest in 40 Chevron-operated exploration leases in the U.S. Gulf, covering about 1,000 km.² The deal builds on the companies’ existing offshore partnerships at Ballymore, Anchor, Jack, and Tahiti. TotalEnergies noted the move will leverage advanced 3D imaging to support future drilling decisions. INEOS also entered the region by purchasing CNOOC’s Gulf assets, valued at an estimated $1.8 billion (Wood Mackenzie). Beacon Offshore began production from Shenandoah field in the deepwater Gulf of Mexico in late July, with Phase 1 expected to ramp up to about 100,000 bpd later in the year, Fig. 4. ExxonMobil awarded a decommissioning contract to EnerMech for its Hoover-Diana development, Fig. 5.
Fig. 4. Beacon Offshore Energy’s Shenandoah floating production system, seen at tow-out. Image courtesy of Danos.
According to Wood Mackenzie analysts, producers in the Gulf will bring on 300,000 barrels of new daily output in 2025, and a further 250,000 barrels in 2026, due to projects many years in the making.
On the regulatory front, President Trump signed the One Big Beautiful Bill Act (OBBBA) into law, giving the offshore oil and gas sector in the Gulf renewed certainty and stability in its leasing program. The Bureau of Ocean Energy Management (BOEM) in June published a Proposed Notice of Sale (PNOS) for Lease Sale 262, the first of three offshore auctions in the under the 2024–29 Outer Continental Shelf Leasing Program. The sale would offer about 15,000 unleased blocks—roughly 80 million acres—located 3 to 231 miles offshore in water depths from 9 ft to more than 11,100 ft.
Despite steady activity in the region, World Oil expects both drilling and footage to decrease by 2.5% in the Gulf of America/Gulf of Mexico.
TEXAS
In Texas, World Oil anticipates four of the 12 Railroad districts to be up during second-half 2025. Seven Railroad districts are expected to be down, and one Railroad district will see no change.
In our January 2025 forecast round, World Oil anticipated drilling to rebound with a 1% increase, with footage to see the same small increase. We also predicted Texas to account for 42% of all U.S. drilling in 2025. We expect Texas drilling to decrease by 6.5%, and footage by 6.7% in the second half of 2025.
Fig. 5. ExxonMobil’s Hoover-Diana platform in the U.S. Gulf of America / Gulf of Mexico. Image: ExxonMobil
Permian basin. Chevron followed through on an earlier promise to free up “billions” in cash flow by slowing production in the Permian. According to a July statement by Bruce Miemeyer, head of Chevron’s shale operations, the company is cutting drilling rigs and frac crews in the Permian, as it approaches its long-term target of producing 1 MMboed in the region.
Occidental Petroleum (Oxy) recently divested $950 million in Permian assets to support continued debt reduction. The Permian basin has seen its fair share of M&A activity in 2025, further shaking up drilling operations. Perhaps the largest Permian deal so far in 2025, Diamondback Energy acquired Double Eagle for nearly $4.1 billion, adding ~40,000 net acres in the core Midland basin to strengthen its inventory. Mach Natural Resources expanded into the Permian and San Juan basins with $1.3 billion in acquisitions that will double the company’s production, Fig. 6. Most recently, Crescent Energy acquired rival Vital Energy in a $3.1 billion all-stock deal. The deal helped propel Crescent to become a top-10 U.S. independent producer, and enhances its Permian footprint. In another notable transaction, Permian Resources bought core northern Delaware basin acreage from APA in a $608 million deal in Q2 2025.
Tariffs have influenced drilling decisions. According to a recent Federal Reserve Bank of Dallas survey, U.S. shale executives expect to drill significantly fewer wells this year than planned at the start of 2025, as lower oil prices and uncertainty around President Donald Trump’s tariffs have hurt profits.
SOUTHEAST
Fig. 6. Mach Natural Resources entered the Permian and San Juan basins with $1.3 billion in asset acquisitions. Image: Mach Natural Resources.
The Southeastern region hosts a diverse range of oil and gas plays, which continue to deliver varied outcomes. In the Haynesville shale region of East Texas / Northwest Louisiana, roughly 33-36 rigs have been active in 2025, down slightly from the end of 2024. Operators haven’t been aggressively adding rigs because of modest gas prices and emphasis on capital discipline (S&P Global). And, according to the EIA, natural gas production in the Haynesville declined last year, as producers decreased drilling activity because of historically low natural gas prices.
Chevron has agreed to sell 70% interest in its Haynesville assets to Tokyo Gas for $525 million. The transaction is expected to generate over $1.2 billion in value to Chevron at current Henry Hub prices. Expand Energy, formed when Haynesville major producers Chesapeake and Southwestern Energy merged, expects to average around 7.1 Bcf/d in total production in FY 2025 and exit the year near 7.2 Bcfd, with part of that from Haynesville. Another large producer, Aethon Energy, is maintaining production levels and saying it needs higher gas prices (around $5/MMBtu) before it ramps up further drilling. (East Daley Analytics).
Despite solid activity, our forecast expects both drilling and footage in Louisiana to drop by 57% in second-half 2025.
Meanwhile in historically modest-producing states in the Southeast—Arkansas, Tennessee and Mississippi, World Oil anticipates drilling activity to see a big jump. Arkansas drilling and footage will increase 133%, Tennessee by 150%; Mississippi will see a 71% jump in drilling and a steep 255% increase in footage. Bear in mind, however, that these percentages are relative to small total numbers of wells and footage for these states.
NORTHEAST
The Utica shale region saw one of the year’s largest acquisition deals, with EOG Resources announcing it will acquire Encino Acquisition Partners (EAP) for $5.6 billion. The deal positions EOG as a leading E&P within the Utica shale play, adding 675,000 net acres and representing more than 2 billion boe of undeveloped resources. In the Marcellus shale, drilling and production have been fairly quiet in 2025, as gas prices remain a major influence: weaker prices dampen incentive to drill in Marcellus vs. some other basins.
DOE officials under Trump have pledged to keep the Marcellus and Utica shales at the forefront of U.S. energy. Meanwhile, industry associations stress they are investing in new technologies to produce more energy while cutting costs and reducing environmental impacts.
New York continues to maintain its long-standing ban on hydraulic fracturing (fracing). Bills have been introduced to expand this prohibition. One bill in 2025 (NY Senate Bill S2472) would permanently ban horizontal drilling, high-volume hydraulic fracturing, and using gelled propane for fracing, further tightening restrictions. Therefore, in second-half 2025, World Oil forecasts a 14.8% drop in both wells and footage for New York.
Fig. 7. The Fritz 2-30 well in Clay County, Indiana. Image: Black Gold Exploration (BGX).
Compared to first-half 2025, Ohio is expected to see a 10.7% increase in both drilling and footage, while West Virginia drilling activity is expected to drop about 29%. World Oil forecasts a 12% increase in Pennsylvania, and Virginia will see a rise in activity, doubling both its number of wells and footage drilled.
MIDWEST
In the Illinois basin (southern Illinois / western Indiana / western Kentucky), there’s been renewed interest in overlooked well zones. Black Gold Exploration (BGX) drilled the Fritz 2-30 well in Clay County, Indiana (Fig. 7), which has helped draw attention back to legacy productive zones after many years of low activity. From start of drilling the Fritz 2-30 well to first oil production took just over three months.
Overall U.S. rig counts show a modest drop, compared to 2024, though for gas rigs there’s been some strength. Midwest states tend to follow that pattern (with gas sands / conventional plays being more resilient) (EIA).
In Illinois, World Oil expects a 3.8% drop for both total wells and footage. Indiana is forecast to see a substantial rise in activity, coming from very low numbers in first-half 2025 to increase well count by 320%, and footage by 492.3%. In Michigan, we expect to see a 25% jump in wells and a 16.8% jump in footage. Kentucky will remain level, and in Ohio, both well count and footage will increase by 10.7%.
MID-CONTINENT
In the Bakken (Williston basin, N.D. & Mont.) rig activity has been reduced: the number of active rigs in the Bakken region has dropped and is reported to be in the mid-30s (≈ 35 rigs) in mid-2025. High breakeven costs (in the ~$60-70/bbl range) are limiting how many new wells make economic sense under current price conditions (EIA). Aside from the completed Chevron-Hess deal adding ~463,000 net acres in the Bakken, M&A activity has been subdued in this region in 2025.
Bolstering infrastructure. Because production growth (or at least steady production) continues, there’s been renewed focus on overcoming transportation bottlenecks. This includes midstream pipeline expansions in North Dakota, so oil and gas can move more efficiently from wellheads to markets. There is also investment pressure to improve rail, processing, and export logistics.
Overall, the Mid-continent region will see a 3.1% rise in well count and a 7.8% drop in footage drilled during second-half 2025.
According to the Federal Reserve Bank of Kansas, Oklahoma has seen a noticeable recovery in rig activity. From as few as ~33 rigs in mid-2024, the state’s active rigs rose to about 55 units by May 2025, largely driven by improving natural gas prices. In second-half 2025, World Oil forecasts a 13.9% drop in Oklahoma well count, and 10.1% less footage drilled.
Kansas is expected to see a significant uptick in second-half 2025, with 38.2% more wells, and a 13.9% increase in footage. Nebraska activity will remain flat.
Considering aforementioned factors at play in the Bakken, North Dakota will see a small drop of 8.4% for both well count and footage in second-half 2025.
ROCKY MOUNTAINS
Announced in Q2 2025, Chevron and Halliburton have jointly developed a new process that enables closed-loop, feedback-driven completions in Colorado. “This real-time adaptive feedback loop is expected to further drive efficiencies and improve overall asset performance,” said Chevron’s Kim McHugh, vice president of the Rockies Business Unit.
In a major development for the Rocky Mountain region, the Department of the Interior in May released a new USGS assessment identifying significant undiscovered, recoverable oil and gas resources in parts of Wyoming, Colorado and Utah. The assessment estimated the presence of 473 MMbbls of oil and 27 Tcf of natural gas—resources that could help bolster domestic energy supply and fuel local economies.
Also in Utah, Zephyr Energy continues to achieve successful well production test results from its flagship Paradox basin project. Zephyr’s flagship asset is an operated 46,000-acre lease holding, which has been assessed to hold 2P reserves of 2.6 MMboe, 2C resources of 34 MMboe and 2U resources of 270 MMboe. Despite these and other factors, World Oil’s forecast predicts both Utah well count and footage drilled to drop by 8.9%.
New Mexico continues to be a top producer in this region, contributing approximately 15% of total U.S. crude oil production in 2024, making it the second-highest producing state behind Texas (EIA). The state is also a top 10 natural gas producer, with about 8% of natural gas reserves (EIA). World Oil expects New Mexico drilling to remain relatively steady but high, with just a 2% drop forecasted for both wells and footage.
Wyoming’s activity is expected to decline by 30.8% for both wells and footage in second-half 2025. Montana activity will remain flat with no change, while in Colorado, World Oil anticipates a hefty increase of 38% for both well count and footage drilled.
WEST COAST
California Resources Corporation has recently agreed to acquire Berry Corporation for $717 million in a deal that consolidates two of California’s largest upstream operators, creating a combined entity with more than 160,000 boed of production and 652 MMboe of proved reserves.
Fig. 8. ConocoPhillips’ Willow project, with first oil targeted by 2029, was granted key regulatory approvals in 2025. Image: ConocoPhillips.
Although California is historically a difficult place for upstream development, 2025 has seen some positive shifts. California lawmakers passed legislation (SB 237) to allow up to 2,000 new oil wells per year starting in 2026 in Kern County. This is intended to boost in-state production as refining capacity drops and gasoline costs remain high. World Oil anticipates a rise in onshore activity for the state, with 9.1% more wells and 9.1% footage drilled in second-half 2025. Offshore activity is expected to remain level, with no change in well count, and just a 1.9% increase in footage.
In 2025, Alaska’s upstream oil and gas sector has seen a mix of production gains, project milestones, and policy shifts that shape the state’s role in U.S. energy security. Crude oil output is projected to average around 422,000 bpd, supported by new volumes from Santos and Repsol’s Pikka project and ConocoPhillips’ Nuna development, which came online at the end of 2024. These projects are expected to help counter natural decline and stabilize production.
ConocoPhillips’ Willow project remains a highlight for the northernmost state (Fig. 8). Despite continued legal challenges, a U.S. appeals court upheld approvals for Willow in 2025, with first oil still targeted for 2029. The project underscores both the scale of opportunity on Alaska’s North Slope and the contentious regulatory environment surrounding major oil developments.
Finally, regulatory changes under the U.S. Department of the Interior are opening additional acreage in the National Petroleum Reserve-Alaska (NPR-A) and rolling back restrictions on leasing. Combined with active exploration agreements and deepwater projects, these changes signal a more favorable policy environment for upstream investment.
Despite continued industry and regulatory advances, World Oil expects Alaska’s onshore well count and footage drilled to drop 8.2% in second-half 2025, while offshore activity is expected to increase substantially due to ongoing projects.
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