The Clean-Energy Tax-Credit Transfer Market Grew to $42 Billion While Small Deals Lost Their Buyers

The market for transferable clean-energy tax credits grew from $28 billion in 2024 to $42 billion in 2025, and, a year into the One Big Beautiful Bill, Latitude Media reports the market is expected to keep growing in 2026. The headline number reads like a healthy market maturing on schedule.

Beneath that total, liquidity has divided by deal size. Advisory firm Renewable Credit Management reports “less liquidity” and higher transaction costs for credit amounts below $10 million. That is the band where nearly every commercial storage deal sits.

The $10 million line matters for storage. A commercial behind-the-meter storage project earns a 30% investment tax credit on a system that often costs a few hundred thousand to a few million dollars, so the resulting credit almost always lands well below $10 million. The band losing liquidity is the band where nearly every commercial storage deal lives.

The exits. The clearest evidence sits in who left the business. LevelTen wound down its tax-credit marketplace while continuing to operate as a power-purchase-agreement marketplace. Atheva wound down entirely. Evergrow shut down as well.

These were among the platforms built to make small credits tradable at scale, the ones promising something closer to a commodity exchange where a modest credit could find a buyer with low friction. They did not survive the first year.

The survivors moved up. The marketplaces still standing did not stay in the same business. Crux and Reunion Infrastructure, two of the largest remaining platforms, both moved toward the institutional end of the market, positioning themselves as ways for developers to raise layered project capital rather than places to sell a single credit.

Alfred Johnson, chief executive of Crux, describes where the market settled: it “would look more like project financing” rather than commoditized trading, because evaluating the risk on any given credit remains the buyer’s responsibility. A project-financing market is one where each transaction carries its own diligence, its own counsel, and its own insurance. That structure rewards size. It punishes the small deal that cannot spread those fixed costs across enough dollars to justify them.

What made the diligence heavy. The weight came from FEOC, the foreign-entity-of-concern rules that OBBB attached to credit eligibility. A buyer who purchases a credit and later discovers the underlying project failed a compliance test does not simply lose a trade. Hans Royal of Schneider Electric explains that post-sale non-compliance leaves the buyer facing “taxes owed and potentially penalties.” The liability follows the credit.

The rules remain unsettled. Andy Moon, chief executive of Reunion, notes that “Treasury has not yet clarified large chunks of what it means to be compliant with the FEOC, and so, as a result, insurers are not willing to insure those risks.” Uninsurable risk does not clear at any price a small seller would accept. Timothy Doran of Renewable Credit Management frames the effect plainly: “there are additional layers of complexity, so that plays into the transactional cost piece of this.”

Complexity is a fixed cost. The same FEOC documentation review, the same insurance wrap, and the same legal opinion cost roughly the same whether they sit on a $50 million utility-scale credit or a $600,000 commercial storage credit. On the large deal, that cost is a rounding error. On the small one, it can consume the discount the seller was counting on to make the transfer worthwhile.

The one tailwind is real but partial. Storage and clean-fuel credits gained prominence over the past year as buyers diversified away from wind and solar. The reason is timing: OBBB accelerated the sunset for wind and solar, stripping eligibility from projects that enter service after 2030. LevelTen research cited by Latitude Media found the pressure showing up in offtake prices, with potential PPA increases of 40% to 50% across markets and as high as 120% in some regions. Sarah Wolf of LevelTen put one case in concrete terms: “PPA prices could jump from $55 per megawatt-hour to $121.”

Storage sits outside that sunset. Its tech-neutral credit runs through the 2030s, and buyers looking for a durable credit are increasingly willing to consider it. That is a genuine advantage for the asset class.

The advantage operates at the portfolio level, not the transaction level. A buyer diversifying into storage credits wants a large, clean, well-documented position. That interest does not automatically reach down to the individual sub-$10 million credit generated by a single commercial installation, which still has to clear the same diligence as everything else in a market that now trades like project finance.

The gap this leaves. The distinction that survived OBBB was between credits that expire and credits that endure. The distinction the market added on its own is between credits large enough to be worth financing and credits too small to be worth the paperwork. A commercial storage project can be fully ITC-eligible, fully FEOC-compliant, and still find that monetizing its credit costs more, in time and fees, than the developer modeled when the payback math was drawn up.

The likely adaptations follow the logic of a project-finance market. Aggregation, in which a platform bundles many small credits into one institutional-sized position, is the obvious one. So is up-front standardization: sellers who can hand a buyer a complete FEOC compliance file at closing remove the single most expensive piece of diligence from the transaction. Neither exists at scale yet.

The credit that anchors commercial storage economics remains on the books, longer-lived than almost any other in clean energy. The market for turning it into cash, at the size most commercial projects actually generate, is the part that thinned in year one.

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