Landmark Energy Deals of 2026

Introduction

Energy dealmaking in 2026 ran on two tapes at once. In upstream, a burst of corporate consolidation in January and February gave way to a near-freeze after the Iran war began on February 28, as war-driven price swings left buyers and sellers unable to agree on what oil assets were worth. In power, the opposite happened: utilities, generators and infrastructure funds set records, chasing the electricity demand that data centers are pulling onto the grid. LNG sat between the two, with new US plants starting up and new projects reaching final investment decisions as buyers scrambled to replace Qatari supply.

This article is the deal-by-deal reference for the year, grouped by sub-sector, with the valuation lesson each transaction teaches. It succeeds our review of the landmark energy deals of 2024-2025, now in past coverage; the year's broader trends sit in the energy M&A outlook for 2026, and the war itself in the Strait of Hormuz crisis.

US upstream M&A reached $38 billion in the first quarter of 2026, the highest quarterly total in two years, before activity slowed sharply in March once the war began, according to Enverus figures reported by Rigzone. Almost all of that value came from pre-war deals, signed before the shock, and two of the three largest were bets on natural gas rather than oil.

Devon and Coterra: The Defensive Merger of Equals

On February 2, Devon Energy and Coterra Energy agreed to combine in an all-stock deal in which Coterra shareholders receive 0.70 Devon shares per share, leaving Devon holders with about 54% of the combined company and Coterra holders with about 46%. Based on Devon's January 30 share price, the companies put the combined enterprise value at about $58 billion; Enverus, which values deals by what is paid for the target, counts it as a roughly $25 billion transaction. The deal closed on May 7, 2026, under the Devon name, with $1 billion of targeted annual pre-tax synergies and a new buyback authorization of more than $5 billion.

The strategic logic was defensive scale. Neither company needed to sell, but both faced the same problem as every mid-to-large independent after the 2024-2025 megadeals: a shrinking supply of top-tier drilling inventory and investors who reward durable free cash flow over growth. Combining gave the new Devon a leading position in the core of the Delaware Basin with more than ten years of high-quality inventory, plus Coterra's Marcellus gas and Anadarko assets, which makes it as much a multi-basin combination as a Permian one. The Permian consolidation article covers what it means for the basin's remaining independents.

Merger of Equals

A combination of two companies of broadly similar size in which neither pays a meaningful control premium, usually structured as an all-stock exchange so that both shareholder groups own a large share of the combined company. Boards and management roles are typically shared between the two sides. In energy, mergers of equals let producers gain scale and synergies without one side committing to a price view on the other's reserves, which is why they are common when commodity prices are volatile.

The merger also produced the follow-on business every large combination creates: portfolio pruning. On October 8, Crescent Energy agreed to buy Devon's Eagle Ford position, about 90,000 net acres producing roughly 68,000 barrels of oil equivalent per day, for about $4.2 billion in cash, backed by $2 billion of committed bank financing and a share offering. Devon called the sale an outcome of its portfolio review and plans to use the proceeds for debt reduction and buybacks, the same post-merger pattern that followed the 2024-2025 upstream megadeal wave.

Mitsubishi and Aethon: Buying Gas for LNG

The quarter's second-largest deal came from Japan. In January, Mitsubishi Corporation agreed to buy the Haynesville shale gas business of Aethon Energy, a private operator producing about 2.1 billion cubic feet per day, for about $5.2 billion of equity and roughly $7.5 billion including assumed debt, the largest acquisition in Mitsubishi's history. The sale closed in July, with the assets now operated by a Mitsubishi subsidiary.

The rationale is LNG integration. Mitsubishi holds liquefaction capacity at Cameron LNG in Louisiana, and owning upstream gas lets it control the cost of the molecules it exports to Japan, Europe and elsewhere in Asia. Shell made the same bet in Canada on April 27, agreeing to buy Montney producer ARC Resources for about $13.6 billion, or about $16.4 billion including debt, adding roughly 370,000 barrels of oil equivalent per day next to the gas Shell already supplies to the LNG Canada project. Both deals price gas reserves as feedstock for an export business rather than as a merchant commodity.

The Bid-Ask Freeze

After the war began, upstream deal volume collapsed: Enverus counted only $9.1 billion of US upstream M&A in the second quarter, down 76% from the first, and attributed the drop to volatility that widened bid-ask spreads. Sellers anchored on spot prices above $100; buyers priced a futures strip that slopes steeply down toward pre-war levels by 2027. The deals that did get done were mostly bolt-ons, such as Matador Resources' $1.3 billion purchase of Paloma Permian, and leasing: more than 40% of the quarter's value came from a record federal lease sale in New Mexico. The lesson is that in a supply shock, upstream deals clear only when the structure (stock consideration, hedges transferred with the asset, price-linked contingent payments) lets both sides avoid committing to one price view.

Power and utilities M&A reached a record $205 billion of announced value across 92 deals in the first half of 2026, more than triple the same period of 2025, according to Deloitte's midyear review. Two megadeals drove most of it, and a string of mid-size gas plant sales showed how the market now prices dispatchable capacity.

NextEra and Dominion: Scale for the Build Cycle

On May 18, NextEra Energy and Dominion Energy agreed to combine in an all-stock transaction that the companies say will create the world's largest regulated electric utility business. Dominion shareholders receive 0.8138 NextEra shares per share, leaving NextEra holders with about 74.5% of the combined company. The deal is valued at about $67 billion of equity; Deloitte, counting assumed debt, puts the transaction at about $124 billion. The combined company would be more than 80% regulated, serve about 10 million customer accounts across Florida, Virginia and the Carolinas and own about 110 gigawatts of generation.

The deal is about funding a decade of capital spending. Dominion's Virginia territory is home to the largest data center cluster in the world, and the combined company cites more than 130 gigawatts of large-load opportunities in its pipeline. Building the generation, transmission and grid upgrades to serve that demand requires a balance sheet and supply chain few utilities have on their own, which is the core case for regulated utility consolidation. Shareholders of both companies have approved the merger, which now faces state and federal regulatory review, including the Virginia State Corporation Commission, with closing expected in the second half of 2027. The companies have offered $2.25 billion of bill credits to Dominion customers over two years after closing, a reminder that in utility M&A the regulator, not the shareholder, is the last approval.

The AES Take-Private: Infrastructure Capital Steps In

On March 2, a consortium led by Global Infrastructure Partners (part of BlackRock) and EQT's infrastructure fund, with CalPERS and the Qatar Investment Authority as co-underwriters, agreed to acquire AES for $15.00 per share in cash. That is an equity value of $10.7 billion and an enterprise value of about $33.4 billion, a 40.3% premium to AES's 30-day average price before the first media reports of a sale. The consortium is funding the entire purchase price with equity, and AES shareholders approved the deal on June 26; closing is expected in late 2026 or early 2027.

The deal is a textbook example of public-to-private arbitrage in power. AES said that without the transaction, funding its growth beyond 2027 would likely have required cutting or eliminating its dividend or issuing significant new equity, both of which public investors punish. Long-dated infrastructure capital, which values contracted renewable and utility cash flows on a lower cost of capital and does not need a dividend, can fund that build more cheaply. The energy private equity landscape explains why infrastructure funds became the most active buyers of power assets in 2026.

Below the megadeals, the most active corner of power M&A was the trade in existing gas-fired plants, where private equity sellers, strategic buyers and a forced seller all met.

Vistra, Talen and the Gas Fleet Trade

The year's clearest valuation lesson came from three sales of existing gas plants, two of them by private equity owners:

Every one of these deals priced existing capacity at a fraction of replacement cost. Building new combined-cycle capacity now costs roughly $2,000-2,500 per kilowatt in industry estimates, and turbines are scarce: Wood Mackenzie expects turbine prices to have risen 195% since 2019 by the end of 2027, with order books sold out and lead times of up to six years. An existing plant that can run today is worth far more to a buyer facing that queue than its historical book value suggests.

Constellation's Remedies: Selling Plants to Close Calpine

The largest power deal of the previous cycle created some of 2026's transactions. To win approval for its acquisition of Calpine, which closed on January 7, 2026, Constellation agreed with FERC and the US Department of Justice to divest generation in markets where the combined fleet would have been too concentrated. In March it agreed to sell five mostly gas-fired PJM plants in Delaware and Pennsylvania (Bethlehem, York 1, York 2, Hay Road and Edge Moor), about 4.4 gigawatts, to LS Power for about $5 billion, expected to close by the end of 2026. It also sold its minority stake in Texas's Gregory plant and, on October 14, completed the sale of the 606-megawatt Brazos Valley plant near Houston to LS Power.

Divestiture Remedy

A condition imposed by antitrust or energy regulators that requires a merging company to sell specific assets, such as power plants in a concentrated market, so that the combination does not reduce competition. The buyer of the divested assets usually needs regulatory approval too. Remedies create their own M&A: forced sellers, assets with a known deadline and buyers who can underwrite regulatory risk quickly.

Remedies matter for bankers because they turn a strategic acquisition into a series of sell-side mandates with fixed timelines. They also show how regulators view market concentration in power: the DOJ cared about specific regional markets, not national scale, which is why NextEra and Dominion, with largely non-overlapping service territories, face a mainly state-level review instead.

The loss of about 17% of Qatar's LNG export capacity to Iranian strikes, and the near-closure of the strait that carried almost a fifth of global LNG, turned 2026 into the year US LNG went from expected glut to scarce supply. The LNG market article covers the market; the transactions that mattered were these:

Midstream produced no megadeal in 2026, and that is the point. With the large corporate combinations of the last cycle done, pipeline companies spent the year on bolt-on acquisitions that add gas volumes behind their existing networks, above all in the Permian, where associated gas keeps growing whatever happens to oil prices.

Energy Transfer and Vaquero: Paying for the Contract Book

The clearest example came on October 6, when Energy Transfer agreed to buy Vaquero Midstream for about $2.625 billion, paid in $1.95 billion of cash and about 33.3 million new common units, with closing expected in the fourth quarter. Vaquero owns about 300 miles of gathering and intrabasin pipe in the Delaware Basin and a processing complex with 675 million cubic feet per day of capacity, expandable to about 1.2 billion. What Energy Transfer is paying for, though, is the contract book: long-term, fee-based agreements backed by about 100,000 dedicated acres, with an average remaining life of about ten years. That is why the deal is expected to be immediately accretive to distributable cash flow per unit, and why midstream buyers value targets on contracted EBITDA and contract life rather than on commodity prices. Our article on midstream contract structures explains why fee-based volumes command the highest multiples.

Transocean and Valaris: Scale in a Fixed Fleet

In oilfield services, the defining deal was offshore. On February 9, Transocean agreed to acquire Valaris in an all-stock deal valued at about $5.8 billion, creating a fleet of 73 rigs, including 33 ultra-deepwater drillships, with an implied combined enterprise value of about $17 billion and an estimated $10 billion contract backlog. Transocean shareholders would own about 53% of the combined company. The logic follows the drilling cycle: after a decade without new-build rigs, the fleet is fixed in size, so scale in high-specification units gives the combined company more pricing power on dayrates as offshore spending recovers, plus more than $200 million of targeted cost synergies to help pay down debt. The offshore drilling article covers how rig economics drive these valuations.

Taken together, the year's transactions share a small set of lessons that will outlast the specific deals:

For anyone preparing to discuss a recent energy deal, those lessons are the analytical layer that turns a headline into an answer: the 2026 tape rewarded scale, contracted cash flows and patient capital, and punished anyone who confused a spike in spot prices with a change in long-term value.