People have been calling the top of the Permian for years. And yet, they keep having to walk it back.
Our latest Permian inventory analysis from the Enverus Intelligence® Research (EIR) team shows why the basin continues to defy those calls. The Permian Basin Play Fundamentals report gives operators a detailed view of where inventory sits, who controls it, where it is expanding, and where hidden risks are quietly eroding future value.
Every year for the last several years, roughly 6,000 Permian wells turn in line. Despite that pace, the economically viable location count has stayed roughly flat, because well costs keep falling and delineation keeps converting geologically viable locations into the economic tier. In other words, Permian Basin cost reductions and interval expansion are offsetting depletion.
Economically viable Permian inventory grew approximately 10% year over year. Lower well costs and high-quality resource expansion into formations that were not on most operators’ radar five years ago are replacing what gets drilled each year. That dynamic is what makes the Permian Basin fundamentally different from every other oil play in North America.
Scale no other basin can match
The Permian now holds roughly 55,000 sub-$50-per-barrel economically viable locations, nearly double the combined total of the Eagle Ford, Williston, DJ, Anadarko, and Montney.
Two forces drove that growth. First, well costs came in around 5% lower on a dollar-per-foot basis compared to last year’s analysis, shifting a meaningful number of $40 to $45 breakeven locations into the sub-$40 tier. Second, resource delineation stepped out materially, particularly in the northern Delaware, converting geologically viable inventory into economically viable inventory at scale.
That conversion mechanism is the engine behind the Permian’s self-replenishing character, and it is not something the Eagle Ford or DJ can replicate.
When a geologically viable resource is included, total undeveloped inventory approaches 100,000 locations. That adds 42% to location count and 29% to oil resource. More than 60% of that additional resource sits in emerging deep zones, with the Barnett-Woodford and Wolfcamp D as the primary contributors in both the Delaware and Midland.
The majors hold 70%, but the remaining 30% is in play
The top five public operators control approximately 70% of high-quality net inventory across the basin. Consolidation over the past five years has made the inventory distribution top heavy, meaning future M&A activity is increasingly driven by public-to-public corporate consolidation.
Private operators now hold just 16% of sub$50 breakeven inventory, with roughly 7% tied to family-owned companies. Our analysis identifies specific acquisition targets in both the Delaware and Midland that screen well on remaining inventory quality and count, some with more than 100 high quality locations at competitive break-evens. At current development pace, that represents real runway for a buyer.
Inventory life: the Permian’s structural advantage
Combined, the Delaware and Midland hold roughly 11 years of sub$50 per barrel runway at current development cadence.
One driver that matters more than many appreciate is the Known Potash Leasing Area in New Mexico. Historically, the KPLA blocked development across large portions of northern Delaware acreage, with permitting regularly denied due to conflicts with potash mining.
That friction is now largely resolved. Operators have struck agreements with mining companies, and extended reach laterals have changed the equation. Development that would have stranded a one-mile lateral can now be cleared with laterals exceeding four miles. The result is a large, relatively undeveloped area of the northern Delaware that has re-entered the economic inventory set and materially contributes to this year’s inventory gains.
The Barnett-Woodford: the largest expansion opportunity in the Lower 48
The Midland Basin Barnett-Woodford stands out as the biggest expansion story in this year’s analysis. We track more than 6,000 combined economically and geologically viable locations in this interval, making it the largest oil-directed expansion opportunity in the contiguous United States.
Well performance exceeded the broader Midland average by more than 30% in 2025. At roughly $800 per foot well costs, break-evens converge with primary Wolfcamp targets in the low $40s.
The geological framework explains why this interval works. In the Midland core, Lower Mississippian thickness is typically absent, meaning the Barnett and Woodford effectively merge into a single reservoir and are developed as one flow unit. Further north, where the Lower Mississippian is present, the zones can be separated and landed individually, although the Woodford tends to be thinner and adds limited incremental upside on its own.
In the Delaware, the story is different. Oil-directed Woodford development is constrained to a narrow fairway where preserved thickness, structure, faulting, and liquids-rich maturity align. Basin-ward, the Woodford quickly becomes overmature and gas prone. Platform-ward, it is immature and lacks sufficient pressure to deliver economic results. Full-section pilots within that narrow corridor have demonstrated sub$40 breakeven potential.
Lease terms add urgency. Approximately 420 Barnett-Woodford locations sit on leases with depth clauses and primary term expirations through early 2028. For operators exposed to those rights, the development clock is already running.
Depletion risk is real, and not evenly distributed
In the Delaware, the Lower Wolfcamp accounts for nearly 20% of remaining locations, but more than half of that inventory carries lagged development risk from overlying Upper Wolfcamp depletion.
Carbonate barriers play a critical role. In the northern Delaware, cemented carbonate layers limit communication between zones and help protect Lower Wolfcamp performance. In the southern and western Delaware, those barriers are largely absent, increasing depletion exposure.
In the Midland, Spraberry zones are particularly sensitive to Wolfcamp depletion across the Central subplay. Lower Spraberry recoveries can effectively halve once cumulative parent recovery crosses roughly two million barrels per acre, pushing break-evens from the low $40s into the mid $50s or worse.
The takeaway is simple. Inventory quality is inseparable from development sequencing. Full interval development that targets multiple zones simultaneously produces materially better outcomes in areas with high depletion sensitivity.
The Yeso offers the best break-evens in North America, for unexpected reasons
The Yeso formation on the Northwest Shelf leads all North American oil plays on average breakeven economics, at roughly $39 per barrel over the past two years. That is lower than both the Delaware and Midland.
Why the Yeso works economically
The Yeso is not a shale resource play. It is semi-conventional and sits at shallow depths of roughly 2,500 to 5,500 feet on the New Mexico Shelf. While the area has a long history of vertical production from carbonate platform rocks, lower historical recoveries left substantial oil in place.
Operators are now targeting that oil with horizontal infill wells in conventional and semi-conventional facies. Shallow depth, high liquids yield, lower completion intensity, and strong productivity combine to deliver very low break-evens. Subsurface variability and reservoir heterogeneity remain real risks, meaning performance is not uniform across the play.
The Central subplay drives most of the outperformance, with break-evens as low as $32 per barrel on recent wells. REPX and Spur Energy control the majority of remaining inventory, each holding close to 200 sub-$50 locations and more than a decade of development runway at current pace.
Associated gas: the infrastructure question operators need to answer now
Permian oil development is inseparable from gas. Our analysis projects 6.9 Bcf per day of associated gas growth by 2030, even with no increase in gas-directed drilling.
Western Delaware and southern Midland acreage are the most gas price sensitive. At zero-dollar gas, several Lower Wolfcamp intervals generate negative net present value. At $2 gas, they flip positive. Realized gas price is no longer a macro assumption. It is a core economic input that belongs directly in development models.
Alpine High is also showing renewed interest as a standalone gas story. Recent programs delivered the largest Permian gas EURs in several years, and at $3 to $4 gas, returns are competitive with the Haynesville.
What to do next
The Permian has not plateaued. It continues to unlock new intervals, new acreage, and new cost efficiencies.
Operators who understand which zones are converting from geologically viable to economically viable, which acreage carries hidden depletion exposure, and which private positions represent real acquisition value will make better capital decisions than those working from a static inventory picture.
EIR covers this analysis in depth, operator by operator and interval by interval. If you want to understand how your acreage stacks up on inventory quality, depletion exposure, and acquisition value, talk with our team.
About Enverus Intelligence® | Research
Enverus Intelligence® | Research, Inc. (EIR) is a subsidiary of Enverus that publishes energy-sector research focused on the oil, natural gas, power and renewable industries. EIR publishes reports including asset and company valuations, resource assessments, technical evaluations, and macro-economic forecasts and helps make intelligent connections for energy industry participants, service companies, and capital providers worldwide. See additional disclosures here.
