Adapting to the new rules of the US game
It has been a tumultuous year in the energy transition space. Sponsors and investors continue to navigate the unpredictable post-April 2 "liberation day" tariff regime and other US tariff actions in planning for equipment supply and obtaining project offtake pricing. By Christopher Gladbach, Heather Cooper and Allison Perlman, partners, McDermott, Will & Schulte.
Distress in the debt market is causing some pullback and repricing of risk, especially in the private credit market, following the "liberation day" tariffs imposed by US president Donald Trump. And, most notably, the enactment of the One Big Beautiful Bill Act in July dramatically transformed the market. All this has required developers, sponsors, investors and other stakeholders to redefine their strategies and adapt quickly to the new “rules” of this regulatory and commercial landscape.
At the same time, the energy demand outlook in the US continues to be robust, supported by the need for additional generation to power data centres driving the AI boom. Power pricing, including pricing for securing long-term power supply, continues to travel higher.
What energy source is going to feed this demand? Natural gas generation is having something of a renaissance moment, but gas turbine supply has remained constrained, with many reporting a delivery lead-time of at least three years. Further, interconnection queues remain clogged (although less clogged than 2024) and gas faces more grassroots opposition. So while it is expected that the industry will be busy developing and financing more new gas generation projects, renewables are going to continue to see a very healthy bid.
Given these challenges and the underlying strong demand, several market players are looking to take advantage of asset repricing, and the US M&A platform and portfolio market is coming back in a major way.
OBBBA ushers in a new era
The OBBBA caused a seismic jolt to the energy sector in 2025. During his campaign, Trump had promised major changes to the expanded tax credits in the Inflation Reduction Act of 2022 and made good on that promise after coming into office. Industry-insiders had been bracing for "unfavourable" legislation, but the end result was more dramatic than most experts had contemplated.
The two primary changes made to IRA tax credits by the OBBBA were: the post-2027 repeal of the Section 48E investment tax credit (ITC) and Section 45Y production tax credit (PTC) for wind and solar projects starting construction after July 4 2026; and the introduction of broadly applicable foreign entity of concern (FEOC) rules that apply to most energy credits.
Notably, the “material assistance” FEOC prong – essentially a prohibition on using too much Chinese equipment – is avoided where construction begins before 2026. Other FEOC restrictions – essentially prohibitions on taxpayers having other impermissible ties to Chinese persons – apply starting as early as 2026. Importantly, the FEOC rules do not apply to the legacy Section 48 ITC and Section 45 PTC.
Yet, the OBBBA was not universally bad. Certain technologies did well, including fuel cell and renewable natural gas, both of which received tax credit extensions, and credit-eligible technologies other than wind and solar such as storage continue to be eligible until 2033, albeit subject to the new FEOC rules.
Before the ink dried on Trump's signature on the OBBBA, he released an executive order mandating the IRS to issue guidance within 45 days of “beginning construction” for purposes of the OBBBA post-2027 tax credit repeal for wind and solar. Finally released on August 15 2025, the IRS guidance went in an unexpected direction – keeping the physical work test in its historic form while eliminating the 5% safe harbour for all but the smallest wind and solar projects. The new guidance applies to all projects beginning construction on or after September 2 2025, but importantly only applies to the wind/solar repeal of the ITC and PTC. For other statutory references to begin construction (including for the new FEOC rules), the old begin construction rules remain in place.
This has, not surprisingly, resulted in a highly active year for developers re-assessing their development pipeline vis a vis begin construction strategies. Developers were initially cautious to commit capital to begin construction. However, once the IRS guidance came out in mid-August, developers moved quickly to lock in begin construction strategies before the first important deadline, December 31 2025, so as to avoid material assistance FEOC rules.
It remains to be seen whether developers continue to invest in begin construction strategies into 2026, for example to meet the July 4 2026 begin construction deadline for the wind/solar post-2027 repeal. Some developers may be comfortable transacting around the FEOC material assistance rules and therefore may see continued benefits to starting construction through July 2026. As near the end of 2025, in stark contrast to just a few months ago, we are seeing developers and their counterparties with high confidence in the begin construction landscape, leading to increased certainty of the financability of their development pipeline – or at least, as discussed below, their prospects for clearing a sale in the M&A market.
Unfortunately, the same cannot be said about the FEOC landscape, which, as of this writing awaits much-needed IRS guidance. The FEOC rules in the OBBBA are highly complicated and far-reaching – implicating not just Chinese companies, but also minority-owned subsidiaries, lending arrangements and an ambiguous catch-all “effective control” by such entities. The full scope of the FEOC rules is well beyond the scope of this article, but suffice it to say, no stakeholder in a tax-credit project is immune from their potential reach.
The last four months of 2025 have seen a dramatic, albeit slow, effort by the energy industry to confront these rules. Unfortunately, the FEOC starts to apply to projects as early as 2026, so most market participants can’t simply punt on these rules. Gradually, we are seeing the impact of the FEOC seep into almost every transactional relationship touching credit-eligible properties – whether tax equity investments, traditional lending, EPCs, supply agreements, M&A, and of course Section 6418 tax credit transfers. Contract drafters are moving forward under obligation to confront these new rules, but wary in the absence of IRS guidance. As of this writing, such guidance was still forthcoming, but the industry is optimistic that we will see initial guidance in early 2026, thus allowing the market to transact freely in 2026 and beyond.
Tax credit tightening
Since the passing of the IRA, many new transaction structures for utilising tax credit transfers – including hybrid tax equity transfer-flip transactions, preferred equity transactions and variations on these structures – have relied heavily on the robust tax credit insurance market to underwrite the structural tax risk of these transactions. The insurance market also significantly supported sponsors who were not creditworthy, by providing another deep pocket for tax credit buyers.
Despite the potential tightening of available renewable energy tax credits, the underlying ability to transfer energy tax credits under the OBBBA has remained intact. Given this, the market continues to see a significant number of tax credit transfer deals, but seller and buyer risk profiles are shifting due to a narrowing of coverage and expansion of exclusions in tax credit insurance policies. Today, it is not uncommon for coverage to be limited to legal risks and for exclusions to include changes in law, seller breaches, project-level operational risks, FEOC violations, supply-chain issues, prevailing wage and apprentice failures, and tax credit elections and procedural errors, among others.
There are more challenges. The insurance market is also experiencing more onerous and longer underwriting as underwriters are now requiring comprehensive diligence memos with supporting documentation, engineering reviews and expanded sponsor representations and covenants. Policies are costing more with lower maximum coverage amounts and higher retentions. Insureds are carrying a larger burden of risk and higher costs, which may cause some stakeholders in 2026 to seek alternatives to tax credit insurance.
As a result of all this, purchasers are increasingly requiring sellers to provide indemnities backstopped by creditworthy entities, and seller indemnity obligations are becoming broader and longer in scope. Further, contracts are exhibiting narrower seller knowledge qualifiers, more conservative pricing and longer diligence timelines. Parties can no longer fully rely on insurance to cover factual uncertainties, forcing such uninsurable risks to be borne by the parties through contractual mechanics. Given this tightening, it remains an open question to what extent insurance will continue to materially benefit non-creditworthy sellers or continued structural innovation.
Tariffs
On April 2 2025 from the White House lawn – a day known by its critics and fans alike as "liberation day" – Trump announced reciprocal tariffs. Since then, the constantly changing tariff regime – including reciprocal tariffs but also antidumping and countervailing duties, Sec. 201 and 301 tariffs, and others – has become a source of significant consternation for project sponsors and the subject of significant negotiation and risk allocation in renewable energy transactions. The uptick in and unpredictability of tariffs related to materials and equipment has created supply chain and cost uncertainty. This year experienced a noticeable slowdown in project and transaction timelines while stakeholders have struggled to address the burden of supply-chain turbulence, cost uncertainties and, potentially, narrowing margins.
The US has seen a modest boost of domestic manufacturing and in the production of domestic modules and other renewable energy equipment in a response to this ever-changing tariff regime. Yet, US production has not come close to meeting the scale necessary to support the development of renewable projects throughout the country and in most cases importing supply at higher costs has been the only feasible alternative. As a result, risk sharing regimes continue to be heavily negotiated to address these tariff disruptions and higher project costs.
A pattern has emerged on allocating tariff risks. The market has gravitated towards structures in which project developers and sellers are carrying most of the tariff burden, but some updated contractual risk-sharing regimes are mandating that offtakers, project utility buyers and, less so, equipment suppliers share in upside tariff surprises.
In addition to affecting development and M&A transactions, tariff risks have bled into project financing as lenders and investors are requiring increased diligence regarding tariff and commodity risks. Further, increased costs and reduced margins have affected the sizing and scope of tax equity investments, tax credit benefits, and project sizing and debt sizing parameters in development and financing transactions. How the market will continue to develop considering these ongoing risks is to be determined, but market participants are hoping for stability and an overall reduction in project input costs.
Opportunities
Over the past 12–18 months there has been a significant increase in private credit market and infrastructure fund participation in the power asset space. Some of those lending positions aim to take space more traditionally filled by project finance lenders – generally with a bit better spread where there is a constraint of one kind or another. Many are participating in holdco or mezzanine loans which essentially act as equity replacement in structurally subordinated positions to underlying project financings. These loans are based on anticipated cashflows and coverage ratios of underlying operating assets, but they can be used, subject to use of proceeds restrictions, to fund ongoing development expenses as well.
The distress in the energy market has been well covered in the news, including one very prominent developer with holdco loans sharing some of these features. So, while these loans continue to expand, we are seeing lenders take a more focused look at the quality of the underlying project level cashflows and conducting additional diligence on these, increasing coverage levels modestly as well as sharpening the pencil on what counts as part of the lending base.
In the M&A space, the reality is that despite additional clarity on the start of construction rules some sponsors have run out of money and out of runway. The interconnection queues are too long, and the pipeline and operating assets don’t support the amount of debt that is needed to continue the business productively. So the rush to start construction has led many developers with safe-harbour projects for tax purposes but no clear way to continue their progress as rapidly as needed. All of this has led to an increased buyer’s market for those investors that are looking to roll up their sleeves and do the work.
The market is seeing an exceptional amount of activity especially in the distributed and small-scale generation space, with some transaction structures utilizing complex earn-out regimes and picking apart the most useful and viable assets from the portfolio mix. Given this trend, we anticipate further increased consolidation in the industry in 2026.
For those with capital, there will continue to be opportunities for those who have positioned themselves to capitalise on discounted assets, higher offtake prices and the trend of increasing demand.
