Permian Basin Production Outlook 2026

The Permian Basin of West Texas and southeastern New Mexico is the largest oil producing region in the United States. In 2024, the last full year the EIA has published, it averaged 6.3 million barrels of crude oil a day and supplied 48 percent of all U.S. production. Any outlook for U.S. oil is mostly an outlook for this one basin, which is why this page exists. It uses the EIA's published 2024 baseline, the Dallas Fed Energy Survey breakevens from March 2026, and the pipeline record. Where a number appears below, its source and date appear with it.

The baseline: what the EIA says the Permian did in 2024

Outlooks fail when they start from a wrong base, so start with the measured year. The EIA's Petroleum Supply Monthly put U.S. crude oil production at an average of 13.2 million barrels a day in 2024, up 270,000 barrels a day from 2023. Almost all of that growth came from the Permian, which rose 370,000 barrels a day to average 6.3 million. The next largest regions, the Eagle Ford and the Bakken, each supplied about 9 percent of national output and were roughly flat. The Permian did this with fewer rigs: it averaged 308 active drilling rigs in 2024, 26 fewer than in 2023, while still running more than half of all the rigs in the country. Output rose because each rig and each well produced more, through longer laterals, faster drilling and completion technology including electric fracturing fleets and automated drilling, in the EIA's account.

Two features of that baseline shape everything in 2026. First, growth is now a productivity story rather than a rig story. A basin that adds 370,000 barrels a day while dropping 26 rigs is not constrained by how many rigs it can staff; it is constrained by the quality of the rock left to drill, the pace at which the best locations are used up, and the price signal. Second, the basin is mature enough that the market for its output is national: at 48 percent of U.S. supply, a Permian slowdown cannot be offset by the other shale regions, which are an order of magnitude smaller and were flat in 2024. That is the sense in which the Permian outlook and the U.S. outlook are the same document.

How to track the Permian in 2026, now that the DPR has ended

For a decade, the standard monthly source on the Permian was the EIA's Drilling Productivity Report, which published regional production estimates, rig counts, new-well productivity and drilled but uncompleted well counts. That report no longer exists. Its final edition was released on May 13, 2024, and any website still quoting fresh DPR figures is quoting a dead series. This site's guide to reading the DPR now serves as a record of what the report contained and how its terms were defined.

The EIA moved the coverage rather than dropping it. From June 2024, the Short-Term Energy Outlook carries production estimates and forecasts for the five main Lower 48 regions, including the Permian, alongside the national totals; the guide to reading the STEOshows where the regional tables sit. State sources fill the gaps the STEO leaves: the Texas Railroad Commission publishes Texas production by county and lease, and New Mexico publishes its side of the basin, which matters because the Delaware Basin's fastest growth has been on the New Mexico side. The rig count itself still comes from Baker Hughes each Friday, covered in the rig count guide. A reader who wants one habit: take the production level from the STEO regional table, the drilling pace from Baker Hughes, and the price needed to sustain that pace from the Dallas Fed survey below. Those three sources are all primary.

One basin, three different rocks

The Permian is not one field. It is a pair of deep sub-basins, the Delaware on the west and the Midland on the east, separated by the shallower Central Basin Platform, and the economics differ by which piece a well sits in. The Delaware Basin, straddling the Texas-New Mexico line, holds the thickest stack of shale targets, chiefly the Wolfcamp and Bone Spring formations, and it is where the largest wells and most of the recent growth have been, much of it on the New Mexico side. The Midland Basin's workhorse targets are the Spraberry and Wolfcamp, drilled from around Midland and Odessa; its wells are typically a step below Delaware wells in initial output, which fits its higher new-well breakeven in the Dallas Fed table below. The Central Basin Platform is the old Permian: conventional reservoirs such as the San Andres, produced with vertical wells for decades, now a source of steady, slow-declining output and of carbon dioxide and water handling infrastructure rather than growth. The stacked targets are the basin's structural advantage. Several oil-bearing layers sit on top of each other, so one surface pad, one road and one set of pipelines can serve wells drilled into different formations, spreading fixed costs across more barrels than a single-layer basin can.

Oil has been produced commercially in the Permian since the 1920s, and the basin has passed through a full conventional life cycle of boom, maturity and decline before shale drilling revived it in the 2010s. That history matters for reading the present outlook: the roads, pipelines, service companies and workforce of West Texas are a century deep, which is part of why the basin can sustain a completion pace that a newer shale region cannot match, and why its constraint is the quality of the remaining rock rather than the availability of services.

Breakevens: the Dallas Fed numbers, and what they mean

The cleanest public measure of Permian economics is the Dallas Fed Energy Survey, which each first quarter asks executives at oil and gas firms in Texas, northern Louisiana and southern New Mexico what WTI price their firms need, on average, to profitably drill a new well, and separately what price covers the operating costs of wells already producing. The first-quarter 2026 survey was collected March 11 to 19, 2026, and drew 135 responding firms, 92 of them exploration and production companies. Its answers are the spine of this site's shale breakeven guide, and they are the figures an outlook should use.

Read the table as a two-speed basin. At a WTI price in the middle $60s, the average firm is roughly at the line where new drilling pays, with the Delaware Basin's core cheaper to drill than the Midland's on the 2026 responses. At any price above the low $40s, wells already drilled keep producing, because shutting them in would lose money faster than pumping at a thin margin. That gap between the new-well figure and the existing-well figure is why Permian output responds slowly to price falls: drilling stops first, production fades later, as the wells drilled in better times decline and are not replaced. It is also why the breakeven figures in the $30s and $40s that older pages, including an earlier edition of this one, presented as drilling breakevens were misleading. Numbers in that range describe keeping existing wells alive. A new well must also repay several million dollars of drilling and completion cost, and the survey says the average firm needs $66 a barrel to justify that.

The firm-size split carries the consolidation story. Large producers told the Dallas Fed they could drill profitably at $59; small producers needed $68. A nine-dollar gap in the price needed to grow is a standing pressure toward mergers, because the low-cost firm can keep drilling through a price dip that stops the high-cost firm entirely. The big Permian combinations of recent years, including ExxonMobil's purchase of Pioneer Natural Resources, which closed in May 2024, fit that arithmetic.

Decline math: the treadmill underneath the outlook

A shale well produces fastest on the day it starts and declines steeply from there, unlike a conventional well. Reservoir engineers describe the path with the Arps hyperbolic decline equation:

q(t) = q_i / (1 + b * D_i * t)^(1/b)

• q(t) is the production rate at time t.
• q_i is the initial production rate.
• D_i is the initial nominal decline rate.
• b is the hyperbolic exponent, which sets how fast the decline itself slows.

The practical consequence matters more than the algebra. Because every existing well is declining, the basin must complete hundreds of new wells a month just to hold production flat, a dynamic the industry calls the shale treadmill. Growth is the small difference between two large numbers: new production from fresh completions, and the legacy decline of everything drilled before. That is why Permian output can keep rising while the rig count falls, as it did in 2024, if completions per rig and per-well output rise fast enough, and why it can roll over quickly if completion crews are cut. The drilled but uncompleted well inventory, the subject of the DUC guide, is the buffer between drilling and completion: drawing it down supports production for a time without new drilling, but it is a stock, not a flow, and it runs out.

Parent and child wells

One drag on per-well productivity is spacing. The first well in a section, the parent, produces from undisturbed rock. Later wells nearby, the children, produce from rock the parent has already partly drained, so they tend to start lower and decline into a lower ultimate recovery, and their fracture treatments can break into the parent well, a frac hit that can damage the parent's output. As the basin matures, a rising share of completions are children in sections already drilled, which is one reason the easy productivity gains of the 2010s have slowed even as drilling technique keeps improving. Operators answer with wider spacing, staggered formations and simultaneous fracturing of several wells at once, each of which trades total recovery per section against recovery per well.

The gas constraint: Waha, Matterhorn and what comes next

The binding limit on Permian oil growth in the last decade was rarely oil pipelines. It was natural gas. Permian wells produce associated gas in large volumes, and that gas must go somewhere: into a pipeline, or, within regulatory limits, into a flare (the natural gas flaring by state guide tracks how much Texas and New Mexico burned or vented each year since 2015). When the pipelines out of the basin fill, the price at the Waha hub, the West Texas pricing point, collapses. In the summer and early fall of 2024 Waha prices traded below zero frequently, meaning producers paid to have gas taken away.

The relief project was the Matterhorn Express Pipeline, about 580 miles from Waha to Katy, near Houston, built by a joint venture of WhiteWater Midstream, EnLink Midstream, Devon Energy and MPLX, with capacity of 2.5 billion cubic feet a day. Gas began flowing on October 1, 2024, and Waha prices firmed immediately, rising 34 cents to $0.45 per million Btu on the first day of flows in market reporting at the time. Matterhorn was the first new gas pipeline out of the basin in three years, and it converted the gas constraint from binding to merely watched. The next tranche is already planned: WhiteWater's Eiger Express, announced in August 2025 and expanded in November 2025 to 3.7 billion cubic feet a day, is expected in service in mid-2028 on the Matterhorn route to Katy. Between those dates, associated gas keeps growing with oil output, so the Waha basis remains the basin's early warning gauge: a return to persistent negative Waha prices would say the gas constraint is binding again before it showed up in oil production figures. The Henry Hub guide explains how a regional hub price like Waha relates to the national benchmark.

The gas load also grows on its own. As a shale reservoir is produced, pressure falls and each barrel of oil arrives with more gas than it did when the well was new, a rising gas-to-oil ratio that is a normal feature of a maturing tight oil play. A basin holding its oil output flat can therefore still be adding associated gas supply every year, which means takeaway capacity that is comfortable today becomes tight again on a schedule set by reservoir physics as much as by drilling. That is the context for the pipeline queue: Matterhorn relieved the 2024 squeeze, midstream firms are already building and expanding the next lines, and the spread between Waha and Henry Hub prices is the running scoreboard for whether they are keeping up. Our dated table of Permian gas pipelines and Waha spread quotes shows how that scoreboard has read since 2024.

The third product: produced water

Every Permian oil well also produces water, typically several barrels of salty produced water for each barrel of oil, and the water has to be gathered, treated or injected back underground. Water handling is a real share of operating cost, and it is the part of Permian operations most exposed to regulation. In parts of West Texas, the Texas Railroad Commission has restricted disposal injection in designated seismic response areas after earthquakes were linked to deep injection, pushing operators toward recycling produced water for fracturing and toward shallower or more distant disposal. None of this sets the basin's production level month to month, the way price and gas takeaway do, but it raises the cost floor under the marginal operator and belongs on the diligence list: two firms with the same rock can have different economics because one owns water pipelines and recycling capacity and the other pays to truck and dispose of every barrel.

The analyst's checklist for any Permian claim

• Ask which breakeven is being quoted. New-well and existing-well figures differ by more than $20 a barrel in the Dallas Fed survey. A claim that the Permian breaks even in the $40s is describing wells already drilled, not new drilling.
• Date the production figure.The EIA's measured full-year figure is 6.3 million barrels a day for 2024. Anything larger for a later period should name its source: STEO estimate, state data, or a commercial model.
• Separate rigs from output. The basin added 370,000 barrels a day in 2024 with 26 fewer rigs. Rig direction alone does not settle production direction; completions and per-well productivity sit between them.
• Watch the gas side. Waha prices, flaring reports and pipeline in-service dates tell you whether the takeaway constraint is binding before the oil data does.
• Check the child-well share. Rising completions in already drilled sections point to lower per-well recovery ahead, whatever the headline completion count says.
• Mind the firm-size gap. A $59 new-well breakeven for large firms against $68 for small ones predicts consolidation and a production mix shifting toward the majors in any long price dip.

What would change this outlook

Three developments would rewrite the picture above. A WTI price sustained below the Dallas Fed's $66 new-well average would slow completions first and production growth within a few quarters, while output itself would keep rising for a time on wells already drilled, because existing wells cover their operating costs down to the low $40s. A return of persistent negative prices at Waha before Eiger Express arrives in 2028 would cap growth from the gas side regardless of the oil price. And a faster than expected fade in per-well productivity, as child wells take a larger share of completions, would raise the completion pace needed just to hold 6.3 million barrels a day. None of these is a forecast. They are the three dials, price, gas takeaway and well productivity, that the sourced data on this page lets a reader monitor month by month.

Data and sources: U.S. Energy Information Administration, U.S. crude oil production rose by 2% in 2024, Today in Energy, April 16, 2025, read October 26, 2026 (2024 production, Permian share, rig average and WTI average, from the Petroleum Supply Monthly). Federal Reserve Bank of Dallas, Energy Survey breakeven data (breakeven.xlsx updated March 25, 2026; first-quarter 2026 survey collected March 11 to 19, 2026), checked October 23, 2026. EIA, Drilling Productivity Report, final edition released May 13, 2024, confirmed October 26, 2026. Matterhorn Express in-service date, route and capacity from project partner and market reporting of October 2024 (RBN Energy, East Daley Analytics and Reuters reporting, read October 26, 2026); Eiger Express capacity and timing from Oil and Gas Journal, November 24, 2025.