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DAVID BLACKMON, Contributing Editor��

Fig. 1. The Permian basin of West Texas and southeastern New Mexico remains the largest oil-producing region in the U.S. by far, contributing around half of the nation’s total oil output. Image: ConocoPhillips

It’s impossible to know for sure as of this writing what the future will hold. The only thing that is certain is that rising uncertainty and volatility will dominate the region’s near-term outlook.��

OIL: CURRENT TRENDS��

The Permian basin continues to be the largest oil-producing region in the United States, contributing around half of the nation’s total oil output, Fig. 1. In 2024, it hit a record of approximately 6.3 million barrels per day (MMbpd). However, growth is slowing. Industry forecasts during the first quarter of 2025 suggest that oil production will increase by 250,000 to 300,000 bpd in 2025, down from a 380,000-bpd rise in 2024. This aligns with projections¹ from the U.S. Energy Information Administration (EIA), indicating a tapering off from the rapid expansion seen in previous years. The slowdown is attributed to geological limits, as the best drilling locations (Tier 1 acreage) are increasingly exhausted, and operators shift to less productive fringes.��

Well productivity is also a concern. While technological advances like longer lateral wells (now averaging over 10,000 ft) and hydraulic fracturing have kept output high, per-well productivity has declined in some areas. For instance, in the Delaware sub-basin, recent wells have shown a negative trend² in oil recovery over the past two years, though the Midland sub-basin has seen some improvement. This variability reflects differences in geology, completion designs and well spacing, with "parent-child" well interference reducing yields in densely drilled areas.��

NATURAL GAS DYNAMICS��

Natural gas production in the Permian is still growing, mainly as a byproduct of oil drilling, reaching around 20.7 billion cubic feet per day (Bcfd) in early 2025. However, this growth comes with challenges. The gas-to-oil ratio (GOR) has risen from 3,100 cubic ft per barrel (cf/b) in 2014 to 4,000 cf/b in 2024, meaning gas is becoming a larger share of output—sometimes at the expense of oil profitability. Infrastructure constraints are also biting. Pipeline takeaway capacity for natural gas is nearing its limit, and with maintenance season underway, prices at the Waha hub in West Texas have dropped, sometimes even turning negative.³ This forces operators to flare or shut in wells, which in turn curbs oil production, since the two are often co-produced.��

New pipelines, like the Matterhorn Express (2.5-Bcfd capacity, expected in third-quarter 2024) and expansions to the Permian Highway Pipeline (adding 0.55 Bcfd), are set to ease some of these bottlenecks by late 2025. Longer-term projects, including the Apex (2.0 Bcfd), Blackcomb (2.5 Bcfd) and Saguaro Connector (2.8 Bcfd) pipelines, expected by 2027, promise to add 7.3 Bcfd of capacity, targeting Gulf Coast LNG terminals and Mexican markets.��

These new gas infrastructure projects could narrow the Waha-Henry Hub differential, which hit $3 in early April 2025, as well as stabilize prices. However, until this capacity comes online—likely not before 2026—analysts warn of a “grimmer” outlook, with spare takeaway capacity shrinking and prices remaining vulnerable to production surges and maintenance disruptions.��

Fig. 2. Permian operators continue to wrestle with rising costs and geological hurdles, including lower initial production rates and growing water-to-oil ratios. Image: APA Corporation.

At the same time, innovative responses to these natural gas challenges are emerging. The Permian’s biggest independent producer, Diamondback Energy, said in February⁴ it is looking for equity partners for a proposed new gas-fired power plant to help consume excess gas locally, thus reducing reliance on pipeline development. Diamondback would plan to use some of the power generated by the plant for its own operations, while selling the excess to new datacenters planned for the area.��

OPERATIONAL AND ECONOMIC CHALLENGES����

Permian operators continue to grapple with rising costs and geological hurdles, Fig. 2. Drilling in fringe areas produces more water—up to four barrels per barrel of oil, compared to a 1:1 ratio in other basins—and this water-to-oil ratio can climb as high as 12:1 in some spots. Handling this water adds expense, as does treating and transporting the surplus gas. Rig counts are down, with Baker Hughes indicating a drop⁵ to 294 active rigs by early April 2025, reflecting tighter margins and a shift toward capital discipline among operators. Some sources on X suggest this could lead to 45–50 fewer rigs and 4,500–9,000 job losses, though these figures are speculative and not yet confirmed by official data.��

Operators are focusing on efficiency, rather than aggressive growth, a shift from the "drill, baby, drill" ethos of the 2010s shale boom. Big Permian producer Chevron plans to boost output by up to 10% in 2025 while cutting capital spending, prioritizing cash flow and shareholder returns over sheer volume.��

ExxonMobil said in March it aims to continue ramping up production following its acquisition of Pioneer Natural Resources in 2024, a $60 billion deal that significantly expanded its footprint in the region. The company has already achieved a production level of over 1.2 million barrels of oil equivalent per day (MMboed) in the Permian by mid-2024, and it plans to further increase this to approximately 2 MMboed by 2027. For 2025 specifically, ExxonMobil expects to maintain a trajectory toward this goal, leveraging its now-combined 1.4 million acres of contiguous acreage—the largest in the basin—to optimize drilling and operational efficiencies.��

FEDERAL LEASE SALES IN THE DELAWARE BASIN��

Fig. 3. Serving as a precursor to Interior Secretary Doug Burgum’s commitment to open up more federal lands in southeastern New Mexico’s portion of the Delaware basin, the Bureau of Land Management during the first quarter of 2025 awarded new leases on 34 parcels totaling more than 25,000 acres in the states of New Mexico, Wyoming, Montana, Nevada and North Dakota (pictured here). Image: ConocoPhillips.

Following four years of refusal to satisfy the provisions in the Federal Lands Leasing Act by holding regular oil and gas lease sales, both President Trump and Interior Secretary Doug Burgum promised to rapidly ramp up sales of new acreage upon assuming office in January. This is a crucial commitment for the portion of the Delaware Basin in southeastern New Mexico, where the Bureau of Land Management holds sway over big swaths of federal lands.��

Burgum lived up to his commitment during the first quarter of 2025, awarding new leases⁶ on 34 parcels totaling more than 25,000 acres in the states of New Mexico, Wyoming, Montana, Nevada and North Dakota, Fig. 3.��

“This quarter’s lease sales demonstrate Interior’s unwavering commitment to fostering American Energy Dominance, and we are grateful to those who produce energy on federal lands,” said Department of the Interior Secretary Doug Burgum. “By building on the commonsense, pro-growth policies of the Trump administration, we’re ensuring public lands are being used to their fullest potential to support national security, economic strength and livelihood of the American people.”��

BLM currently has a subsequent lease sale for New Mexico acreage set to take place on May 22. Further details on this and other planned sales can be found on the DOI.gov⁷ website.��

EXTERNAL FACTORS CAUSE PRICE DESTRUCTION��

The industry in the Permian and across the country has always been adept at addressing operational and infrastructure problems by some combination of engineering, technology advances and business efficiencies. But all too frequently, external events intervene which are out of the control of company management teams.��

Impacts from such external events are multiplied when two or more major shifts occur simultaneously, as happened in early April.��

OPEC+ MOVES TO UNWIND VOLUNTARY PRODUCTION CUTS��

On April 3, the eight OPEC+ member countries, who have held to voluntary production cuts since November 2023, announced a “gradual and flexible” unwinding of the 2.2-MMbpd cuts over an 18-month period, starting from April 1. The targeted monthly upward increment in production will be 138,000 bpd.��

The release further states that those eight countries—Saudi Arabia, Russia, Iraq, UAE, Kuwait, Kazakhstan, Algeria and Oman—“will implement a production adjustment of 411 thousand barrels per day, equivalent to three monthly increments, in May 2025.” That represents a large initial rise in additional oil on the market, which produced an immediate downward pressure on crude prices.��

PRESIDENT TRUMP’S MAJOR TARIFF ANNOUNCEMENT��

Fig. 4. U.S. President Donald Trump’s announcement of a major wave of new import tariffs8 on imports from most countries, during an April 2 White House Rose Garden ceremony, has created impacts on the global oil market. Image: Bloomberg.

The impacts of the OPEC+ move were magnified by the fact that it followed, by less than 18 hours, the April 2 White House Rose Garden ceremony, in which President Trump announced a major wave of new import tariffs⁸ on imports from most countries, a move that created immediate impacts on global stock and commodities markets, Fig. 4.��

Crude oil prices reacted to the Trump tariff announcement in a major, immediate way, with both the U.S. domestic WTI price and the international Brent index dropping by roughly 6%⁹ prior to the opening of trading on April 3. Both the WTI and Brent prices fell by roughly 5% during the April 4 action. At the same time, international stock markets saw a general sell-off in response to the Trump tariffs, with U.S markets falling by more than 10% in the following two trading days.��

Obviously, continued production growth like that being projected for the Permian basin by the EIA and others cannot be sustained, should crude prices drop down to a lower trading range for an extended period of time. However, President Trump and other administration officials, like White House advisor Peter Navarro, have maintained their desire to see oil prices fall to $50/bbl to break the back of persistent inflation left over by the Biden regime.��

That is problematic, given that the first-quarter 2025 Energy Survey,¹⁰ published March 26 by the Dallas Federal Reserve, estimates that drillers in the Permian basin require a $62 oil price, just to break even on drilling new shale wells on Tier 1 acreage. That breakeven price rises rapidly as the quality of the drilling prospect declines.��

Again, as of this writing, the situations related to the direction of crude prices, supply chains and the overall economy are impossible to predict. However, it appears likely that all those projections published during first-quarter 2025 will see significant revisions during the second quarter.��

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