Massachusetts queue delays put 2027 solar tax credits at risk

A Massachusetts solar project now sits between a 2029 transmission upgrade and a Dec. 31, 2027 tax deadline. Catalyst Power says the host expected lease income from the array, and the project may reach the front of the grid line too late to keep the investment tax credit, or ITC, that made the deal work.

In a recent studio interview, Catalyst Power described a problem that grew sharper after mid-2025. Solar development timelines were modeled around years of federal incentive stability, then forced to absorb a much shorter federal runway just as utilities, permitting bodies and procurement schedules kept moving at their usual pace.

That timing clash matters because solar projects are built in stages that do not all belong to the developer. Site control, local permits, equipment orders, utility studies and network upgrades each sit on their own clock. When tax law changes faster than those clocks do, delay stops being a routine development risk and becomes a direct hit to project finance.

The new federal deadline is shorter than a normal solar runway

SEIA says projects that begin after July 4, 2026 must be placed in service by Dec. 31, 2027. In plain terms, the project has to be operating by then. That deadline is the mismatch at the center of this case: a solar project can satisfy many development steps and still miss the credit if the grid work needed to energize it finishes too late.

According to The Tax Adviser, the legal change came through H.R. 1, P.L. 119-21, known as the One Big Beautiful Bill Act. The law eliminated the Section 45Y clean energy production credit and the Section 48E clean electricity investment credit for wind and solar facilities placed in service after Dec. 31, 2027, except for facilities for which construction begins within 12 months of the law's July 4, 2025 enactment. SEIA restates the same rule in operating language for solar: begin construction after July 4, 2026, and the project still must be online by the end of 2027.

The dollars at stake can match the urgency in the transcript. SEIA says the base Section 48E credit is 6%, but it rises to 30% if a project pays prevailing wages and uses qualified apprentices. SEIA also says bonus credits can add another 10% for domestic content and 10% for an energy community, with separate low-income bonuses that can go higher in some cases. That is why Catalyst Power speaks about 30%, and in this project's case 40% or 50%, as value that can disappear if the schedule slips.

That loss changes more than a spreadsheet. A project priced with a 30% to 50% federal credit can often support a higher lease payment to a landowner, lower power pricing to an offtaker or more room to absorb upgrade costs. Remove that credit late in development, after money has already gone into engineering, legal work and interconnection, and the project can stop making sense even if the site and demand still look good.

Notice 2025-42 changed what counts as begun construction

Notice 2025-42 took effect on Sept. 2, 2025 for projects not already begun. According to The Tax Adviser, the IRS notice generally eliminated the 5% safe harbor for wind and solar and left the physical-work test as the main way to establish that construction had begun for credit purposes.

That change matters because begun construction is a tax term, not a casual one. Before the notice, developers could generally establish timely progress in one of two ways: start physical work of a significant nature and maintain a continuous program of construction, or pay or incur at least 5% of eligible project cost and then keep making continuous efforts to finish. The Tax Adviser says Notice 2025-42 largely removed that second path for solar.

The physical-work test is narrower than many nonlawyers assume. According to The Tax Adviser, the IRS looks at the nature of the work, not the dollars spent. On-site work such as excavation or foundation work can count, and off-site work such as manufacturing racks, rails, inverters or transformers can count when it is done under a binding written contract. The same notice says preliminary activities do not count, including planning, securing financing, research, permits and licenses. That is a hard line for projects still waiting on utility studies, because many of the most expensive early tasks are still treated as preliminary.

The old 5% path had its own rules, but it gave developers a clearer cost-based target. CohnReznick explains that under the long-running IRS framework, a project could qualify by paying or incurring at least 5% of the final cost of ITC-eligible energy property, excluding land and most buildings. The firm also notes that prepayments lean on a three-and-a-half-month delivery rule and that cost overruns can sink a project that barely cleared the threshold. Even with those limits, the test gave developers a practical way to lock in credit treatment before every permit and upgrade was finished.

The policy did not stay settled for long. In June 2026, CohnReznick wrote that the U.S. District Court for the District of Columbia vacated Notice 2025-42, which temporarily restored the 5% safe harbor option for certain wind and solar projects by the July 4 deadline. That ruling helps some projects at the margin, but it also turns one reversal into another. A developer still has to decide whether to spend for safe harbor, push for qualifying physical work or wait for fresh Treasury action that could change the rule again.

A group study tests shared grid impacts, not one project's calendar

FERC says 68% of interconnection studies completed in 2022 were late. In the same explainer on Order No. 2023, the commission said there were more than 10,000 active interconnection requests at the end of 2022 representing more than 2,000 gigawatts of proposed generation and storage. Those figures do not measure tax-credit loss, but they do show why project schedules keep colliding with queue reality.

A utility group study, often called a cluster study, reviews a batch of proposed projects together instead of one by one. FERC says Order No. 2023 moved transmission providers toward a first-ready, first-served cluster-study approach. The reason is mechanical: several solar projects may seek the same line, substation or transmission path, and one project's viability depends on what the rest of the cohort would also inject onto the grid. The study asks what upgrades are needed if the whole group moves forward, then assigns obligations through the provider's tariff, which is the filed rulebook that governs interconnection terms.

That process answers one reader question and creates another. It explains how a project that looks ready on the developer's side can still wait months or years for the utility or transmission provider to decide whether a feeder, substation or larger transmission element needs reinforcement. It also shows why one project's tax calendar does not control the study. The study is measuring shared grid effects, not preserving a single developer's federal credit deadline.

The harder question is what rule forces the utility to finish the needed upgrade on time. These sources point to no federal rule that sets a completion date for a specific Massachusetts transmission upgrade by a solar project's tax deadline. Order No. 2023 governs the study process, and it allows FERC to police delay in that process, but the sources here do not show a law that compels this unnamed upgrade to be built before 2027.

That is why the 2029 schedule matters so much. A developer can secure land, negotiate commercial terms, advance engineering and even establish begun construction, then still face a project that cannot be energized until the grid work is done. Once the interconnection upgrade slips beyond the tax date, a delay that once looked like a queue problem turns into a capital-structure problem.

FERC can discipline the process without saving a project's tax date

FERC ordered PJM to revise its compliance plan in July 2025. Utility Dive reported that the commission found parts of PJM's interconnection approach did not fully meet Order No. 2023, even though PJM had argued its existing process already complied. That intervention matters because it shows FERC is willing to push a major grid operator to tighten its queue rules.

Order No. 2023 is the governing federal rule in the background of this story. FERC says the rule took effect in November 2023, required transmission providers to file compliance plans in 2024, set deadlines for interconnection studies and imposed penalties for late studies. The March 2024 rehearing order, known as Order 2023-A, clarified parts of the rule but did not change the overall goal of reducing backlogs and improving certainty.

That framework can move studies faster, but it cannot promise what solar developers often need most: a finished physical upgrade by a date certain. Study deadlines do not build a transformer, complete substation work or resolve every cost-allocation fight. A provider can comply with the federal study rule and still have a network project whose design, procurement, approvals and construction run longer than a developer's tax window.

The national pattern is clear even if the precise tax exposure is not. FERC's backlog figures, Utility Dive's PJM reporting and Catalyst Power's Massachusetts example all point in the same direction: interconnection delay is not an isolated complaint. No public tally in these sources counts how many projects will specifically lose 30% to 50% of ITC value because upgrades push them past the 2027 date, so developers have to review the risk project by project rather than rely on a marketwide average.

Massachusetts has a cost-sharing answer, but not a timing answer

Canary Media says Massachusetts is working through about $334 million of shared grid projects. In June 2025, the outlet reported that the state's utilities and regulators were advancing Capital Investment Projects, or CIPs, to spread some upgrade costs across future customer bills instead of charging each distributed solar project the full amount up front.

The mechanism is more specific than a generic subsidy. Canary Media says developers still repay a share of those costs over time as their projects connect, and each approved project has to show broader customer benefits such as improved reliability, access to lower-cost community solar or both. That is a meaningful rule because it tells developers what Massachusetts is trying to fix: not whether grid upgrades are needed, but how to pay for them when the system benefits reach beyond one project.

The comparison with the old model is stark. Canary Media reported that interconnection costs in Massachusetts once sat in the tens of thousands of dollars, then rose into the hundreds of thousands or millions as available capacity tightened and larger modifications were required. That is the kind of jump that can kill a project before tax questions even arrive. It also helps explain why a state would build a cost-sharing program around projects that otherwise die in the queue.

CIPs still do not solve the timing problem in Catalyst Power's example. They address who pays and who benefits from some grid upgrades, especially for distributed solar, but they do not change the federal ITC calendar or guarantee that a transmission upgrade scheduled for 2029 will finish by 2027. Massachusetts may be improving the economics of interconnection while leaving the schedule risk largely intact.

Developers still have a few tax-preservation moves

The clearest tax-preservation tool in these sources is to establish begun construction early. Under The Tax Adviser's summary of Notice 2025-42, qualifying physical work can include off-site manufacturing of equipment such as inverters, transformers, racks and rails when it is done under a binding written contract and the equipment is not simply pulled from ordinary inventory. That route is harder than writing a deposit check, but it is one of the few concrete steps a developer can still control while the queue keeps moving.

The June 2026 court ruling described by CohnReznick reopened a second path for at least some projects. If the 5% safe harbor remains available, a developer may be able to pay or incur enough eligible equipment cost before the deadline to preserve credit treatment even while interconnection work drags on. But the same source says the timeline is short and Treasury could appeal or issue new guidance. Safe harbor is therefore a tool, not a cure.

Other commercial responses exist, but these sources do not turn them into a standard playbook. A power purchase agreement, or PPA, is the long-term contract that sets how electricity will be sold, and bridge financing can carry a project through a delay. Neither changes whether the tax credit legally applies. No public rule in these sources sets a standard PPA reset or financing bridge that makes a post-deadline solar project whole once the credit is lost.

A 2029 upgrade schedule makes a 2027 tax deadline look like a cancellation notice. The signals worth watching are concrete ones: whether Treasury or the IRS changes begun-construction guidance again after the June 2026 court ruling, whether the utility study moves under the Order No. 2023 process, and whether the project can still line up physical work, interconnection milestones and final energization before the federal clock runs out.