The A&D Market in Early 2026: What's Moving and Why
The acquisition and divestiture market in early 2026 is picking up from the post-consolidation pause. Q4 2025 was quiet — buyers digesting large transactions, sellers reassessing expectations after WTI gave back the $80 handle. Q1 2026 deal flow suggests the market is returning to normal transaction rhythms, driven by portfolio rationalization from the mega-merger operators and continued PE exit pressure.
Deal Flow: What's on the Market
The most active asset packages in Q1 2026 are concentrated in three categories:
Permian non-core divestitures. ExxonMobil, ConocoPhillips, and Diamondback are all quietly marketing peripheral acreage that came along with major acquisitions but doesn't fit core development programs. ExxonMobil's Pioneer acquisition included several Midland Basin packages in Glasscock and Howard counties that don't connect cleanly to the core XTO operating areas. These are high-quality assets — the point is organizational fit, not rock quality — and they're attracting strong bid interest from mid-size independents.
Eagle Ford rationalization. Several operators are consolidating Eagle Ford positions by divesting fringe acreage and acquiring into core windows. The southern and eastern portions of the play — Webb County, McMullen County — have seen transaction activity as operators position for the gassier, higher-NGL intervals that benefit from the improved natural gas price environment.
DJ Basin packages. The DJ Basin (Niobrara/Codell play in Colorado and Wyoming) has seen renewed transaction interest after a multi-year drought. Civitas Resources has been active in the basin, and their scale creates motivation for smaller operators to test buyer interest. Valuation benchmarks in the DJ are tighter than the Permian — expect $8,000-$12,000/net acre for core Weld County positions, $3,000-$5,000 for fringe areas.
Buyer Appetite at Current Prices
At $68-$75 WTI, buyer appetite is selective but genuine. The deals that are clearing are:
- High-quality Permian acreage with long lateral potential and existing infrastructure, priced at $8,000-$18,000/net acre depending on interval and location
- Producing assets with strong decline profiles and infrastructure ownership, priced at $35,000-$50,000/flowing BOE
- Gas assets with LNG contract alignment, priced at contract-value multiples rather than spot commodity economics
What's not moving: fringe Permian acreage outside proven development corridors (buyer memory of overpriced acquisitions in 2018-2019 lingers), development-stage assets requiring significant upfront capital in basins without infrastructure (DJ, Powder River), and Appalachian gas without clear takeaway solutions.
Valuation Benchmarks: $/Acre and $/BOE
Permian Basin (core Midland, Delaware): $12,000-$20,000/net acre for proven Wolfcamp/Bone Spring development windows. $40,000-$55,000/flowing BOE for producing assets with inventory upside. Premium for infrastructure ownership (midstream gathering, produced water disposal).
Eagle Ford: $6,000-$11,000/net acre for Lower Eagle Ford in Karnes, DeWitt, Gonzales. $30,000-$42,000/flowing BOE. Multi-zone upside (Austin Chalk, Upper EF) commands a premium if unitized.
Haynesville: Gas-weighted metrics harder to compare — typically expressed as $/Mcfe or contract value. Core Caddo/Bossier acreage in DeSoto, Red River parishes: $2,500-$4,500/net acre. LNG-contracted production: $5-$8/flowing Mcf/d.
Bakken: $5,000-$9,000/net acre for core Nesson Anticline positions. $28,000-$38,000/flowing BOE. Limited buyer universe reduces liquidity and compresses valuations.
The Devon-Coterra Effect
The Devon-Coterra merger announced in Q4 2025 is the most consequential M&A event for subsequent deal flow — not because of what Devon and Coterra are buying and selling, but because of what it signals about portfolio strategy. The deal creates a combined company with Permian, Eagle Ford, Haynesville, and Anadarko Basin assets — a diversified mix that signals both companies believed single-basin concentration had run its course and multi-basin optionality was worth paying for.
The implication for other operators: expect a wave of portfolio-balancing moves as companies assess whether their current basin mix optimizes for capital allocation optionality. Operators that are heavily concentrated in a single play will face investor pressure to either demonstrate superior returns from concentration or diversify. The Devon-Coterra blueprint suggests diversification is back in fashion after a decade of "pure-play premium" messaging.
The second-order effect: deals that Devon and Coterra would have competed for separately are now competing under a single balance sheet. That removes one active acquirer from the smaller-deal market, which tightens the buyer universe and potentially softens price discovery for mid-size packages. Sellers in that $500M-$2B size range should be aware that the buyer pool is thinner than it was 18 months ago.
Crude Intelligence Report is an independent upstream oil and gas intelligence publication. Content is for informational purposes only and does not constitute investment advice, financial advice, or a recommendation to buy or sell any security. Always conduct your own due diligence before making investment decisions. The author and publisher hold no positions in any companies mentioned in this article. © 2026 Crude Intelligence Report. All rights reserved.
