The passing of the One Big Beautiful Bill Act (OBBBA) in July 2025 brought forward deadlines for PV projects to receive U.S. tax credits introduced by previous legislation, and set new requirements to demonstrate start of construction and other eligibility criteria. Project developers must move quickly to adapt to this new regulatory landscape.
Image: Pexels / Los Muertos Crew
From pv magazine 2/25
The U.S. utility-scale solar sector is faced with a dual reality in 2026: record-breaking demand, tempered by tightening federal tax credit eligibility.
Solar represented roughly 75% of the 28 GW of new capacity added to the grid in late 2025, according to Federal Energy Regulatory Commission (FERC) data. Yet, this dominance is being tested by the OBBBA.
The landscape has changed for developers with projects in the pipeline. It is no longer enough to have site control and an interconnection position. The difference between a viable project and a stranded asset can now depend on satisfying the specific, labor-intensive requirements of the “Physical Work Test.”
The OBBBA tightened the window for eligibility on the technology-neutral tax credits created by the Inflation Reduction Act. To lock in the full Section 45Y production tax credit (PTC) or 48E investment tax credit (ITC), utility-scale solar and wind projects must begin construction by July 4, 2026.
Projects that start after July 2026 must be placed in service by Dec. 31, 2027, to qualify. In a market where interconnection queues are still five years long and transformer lead times can also be measured in years, an end-of-2027 deadline does not bode well for utility-scale projects seeking eligibility.
Safe harboring
One of the most significant hurdles came in August 2025, when the US Department of the Treasury issued Notice 2025-42. For more than a decade, developers used the 5% Cost Safe Harbor to meet the definition of “construction start” and grandfather projects, essentially starting construction by paying for 5% of the total project cost.
For any solar project larger than 1.5 MW, that door is now closed. The Treasury has replaced the 5% test with the Physical Work Test, which defines the start of construction as when “physical work of a significant nature begins” on site.
This is what’s known as a “facts-and-circumstances” test, meaning there is no longer a bright-line dollar amount that guarantees safe harbor of credits. Instead, the focus is on the nature of the work, and it must be integral to the facility’s function as an electricity generator.
“At a time when we need energy abundance, these rules create new federal red tape,” said Heather O’Neill, president and CEO of Advanced Energy United. “They eliminate long-standing precedent for how companies demonstrate they’ve begun project development.”
Onsite vs. Offsite
With the 5% test gone, the tax equity market is trying to find a new pathway. Keith Martin, partner at Norton Rose Fulbright, noted that while the Physical Work Test is more subjective, it isn’t entirely new territory. “The market as a whole is comfortable with work on the main power transformer because the IRS said that works,” Martin explained.
Offsite work, such as the manufacturing of custom transformers or specialized racking, counts, but only if it is performed under a binding written contract. However, Martin warned “the market is less comfortable with anything else.”
For onsite work, clearing land or building access roads is no longer enough to qualify. Developers are now pushing to drive 10% to 20% of steel piles or finish foundation excavation by the July deadline to ensure they have an audit-proof claim to having begun construction.
Documentation
The burden of proof has shifted from the IRS to the developer to demonstrate physical work. Lenders and tax equity investors are now demanding what several legal firms describe as “unredacted institutional evidence.”
In previous years, an affidavit or a redacted invoice might have sufficed for a 5% safe harbor claim. Under Notice 2025-42, that won’t work. Lenders are now requiring:
The 1.5 MW exception
While utility-scale projects are feeling the squeeze, distributed generation caught a break. The Treasury preserved the 5% cost safe harbor for projects with a nameplate capacity of 1.5 MW or less.
For these smaller sites, the “check-writing” method still works. However, the Treasury included an “anti-stacking” rule to prevent developers from breaking large projects into smaller pieces.
Multiple facilities owned by the same taxpayer that share a point of interconnection or are placed in service in the same year will be aggregated. If the total exceeds 1.5 MW, the 5% safe harbor vanishes, and the project must meet the Physical Work Test.
Construction continuity
Starting construction by July 4, 2026, is only half the battle. Once construction begins, developers must meet a continuity requirement.
Historically, if a project was finished within four years, the IRS assumed construction was continuous. While that four-year window remains, the OBBBA raised the stakes for projects that take longer. If a project started in early 2026 isn’t finished by the end of 2030, the developer must now prove “continuous actual construction” instead of “continuous efforts.”
The change is challenging for projects in the PJM Interconnection or Electricity Reliability Council of Texas (ERCOT) regions, where network upgrades can take years. Excusable disruptions like permitting or interconnection delays serve as legal defenses to prove a project has not been abandoned, but the new guidance removes the “continuous efforts” qualifier. This means a developer cannot show it was trying to get a permit, and it must show that physical work on the project occurred in a continuous manner.
Interconnection bottlenecks
The interconnection delays in grid regions like PJM threaten tax credit eligibility for renewable energy projects. A 2024 report from Columbia University suggested that most projects entering the queue today are unlikely to come online before 2030.
For a developer who begins physical work in June 2026, the safe harbor clock runs out on Dec. 31, 2030. If PJM delays push the commercial operation date (COD) into 2031, that developer must pass facts-and-circumstances testing.
“This leaves uncertainty about how much work is required,” said Norton Rose Fulbright’s Martin. “The financiers will have to decide where they feel comfortable drawing lines.”
Developer checklist
To pass an IRS audit in 2026, a project file needs to show high-quality documentation for bankability. Based on IRS Notice 2025-42, legal firms have outlined:
Project execution
In a post-OBBBA environment, the industry’s focus is shifting toward projects that can be built quickly. The five-year interconnection queue has made distributed generation and community solar the fastest solution for meeting near-term demand. Localized solar-plus-storage can be deployed in 12 to 24 months, bypassing the transmission upgrades required for large-scale projects.
“Electricity demand is accelerating faster than grid infrastructure can keep up,” said Aaron Gomolak, CEO of power electronics equipment supplier Ampt. These conditions are forcing developers to prioritize “ready-to-build” assets over massive, speculative project pipelines.
The complexity of the requirements for projects to ensure tax credit eligibility is driving a wave of market consolidation. Smaller developers, who often lack the legal and procurement departments to track physical work logs, FEOC requirements on certain components, and other areas, are increasingly selling their ready-to-build assets to larger platforms.
The value of a ready-to-build project is dependent not only on its interconnection position but also the quality of its beginning of construction documentation, noted Norton Rose Fulbright. Buyers are conducting deep-dive audits to ensure that the physical work claimed by the previous owner meets the new, stricter Treasury standards.
In the secondary market, this has turned due diligence into a forensic hunt for proof that work carried out qualifies as significant, and that contracts are legally binding. Investors and buyers are now demanding unredacted supply agreements and geotagged evidence.
Strength ahead
While the regulatory cliff of the OBBBA is forcing a difficult change in how projects are documented and financed, the long-term outlook for solar doesn’t live or die by tax credit safe harbors. The industry is moving toward a phase where the fundamental economics of solar outpace the importance of federal incentives.
The most powerful driver of solar growth isn’t federal policy, it’s the levelized cost of energy (LCOE). Over the past decade, the cost of solar energy has plummeted and in many regions building new solar is cheaper even than continuing to operate existing coal or gas plants. Financial advisory Lazard finds that solar and wind projects have a lower LCOE than nearly all fossil fuel projects – even without subsidies. Solar can also be built faster than its fossil fuel counterparts, making it a rapidly scalable resource that will be crucial to meeting rising electricity demand.
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