Is Commercial Solar Still Worth It Without the ITC? The 2026 Math

For fifteen years, every commercial solar conversation started with the federal Investment Tax Credit (ITC). That era is ending on a schedule: projects without safe harbor protection must be operating by December 31st, 2027, and after that the federal credit is gone. So the question owners are actually asking in 2026 is the right one — does the investment still clear a hurdle rate without Washington’s 30%? The honest answer requires a full financial breakdown, not a slogan. Here is the breakdown.

The short version

• Without the ITC, a representative 1 MW New Jersey rooftop system moves from a roughly 3.5-year payback to a roughly 5.5-year payback — longer, but still comfortably inside the return profile most commercial real estate owners underwrite capital against.
• The credit was one-time. The forces replacing it — structural electricity rate inflation, 15-year state incentive contracts, and permanent 100% bonus depreciation — compound for decades.
• Losing the ITC quietly raises the depreciation benefit: claiming the 30% federal credit requires owners to reduce the amount they can depreciate by half the credit’s value, so they can only write off 85% of what they spent. With no credit, there is no 15% basis haircut, so owners depreciate 100% of system cost.
• Battery storage kept its federal credit. Battery systems beginning construction through 2033 remain eligible under Section 48E, which keeps a 30%+ federal incentive available for paired projects.
• For owners who can still be placed in service by December 31st, 2027, everything above is the floor, not the ceiling — the 30% credit remains on the table for projects that can make the window.

What actually changed on July 4

The One Big Beautiful Bill Act (OBBBA) split the commercial solar market into two populations. Projects that document a construction start by July 4, 2026 hold a placed-in-service runway through 2030 with the full 30% credit intact. Every other project must be energized by December 31st, 2027 — or claim nothing.

That means the industry now has to answer, in public and with numbers, the question it spent a decade deferring: what does commercial solar return on its own?

It turns out the ITC was an accelerant, not the engine. Four things were always carrying the economics. All four survived.

1. Avoided utility cost — in a market that is structurally repricing

The single largest line in any commercial solar pro forma is not an incentive. It is the electricity the building stops buying.

That line is getting more valuable at a pace with no modern precedent. PJM, the grid operator serving New Jersey and twelve other states, has now hit the highest price allowed by regulators in three consecutive capacity auctions. This is a sign that demand for power is outpacing supply. The most recent auction, announced July 14, 2026, cleared at $325/MW-day for the 2028/29 delivery year and supply still came in 6,831 MW short of the grid’s reliability requirement. PJM’s own simulation shows that without the cap, the price would have cleared 71% higher. Data center load growth, plant retirements, and strict reliability rules are not one-year events; they are the new operating environment. Elevated capacity costs are now effectively locked into commercial bills through May 2029, and the pressure does not stop at PJM’s borders — New England and New York commercial rates face parallel dynamics.

Here is why that matters more than the credit didGiven what’s happening with capacity prices, a more realistic assumption for the system modeled below is that utility rates climb from 2.5% to 3.5%. This adds roughly $900,000 of nominal avoided cost over 25 years — one and a half times the value of the $600,000 federal credit the project lost. A one-time 30% discount was valuable. A structural change in the price of the thing solar replaces is more valuable, and it is the change actually underway. (For the mechanics of how commercial rates are built, see how electricity rates are determined.)

2. State incentives were always the quiet majority

In Plankton Energy’s core markets, state programs — not the federal credit — provide the largest single incentive stream over a project’s life.

Take New Jersey. Under the SuSI program’s ADI track, a large net-metered rooftop system earns SREC-II payments at $100 per MWh generated, locked at registration for fifteen years. On a 1 MW system producing 1,200 MWh annually, that is $120,000 per year — $1.8 million in nominal contracted revenue over the 15-year term. The federal credit on the same project was a one-time $600,000. The state program is worth roughly three times the federal one, it did not expire on July 4, and it pays regardless of what happens in Washington.

Massachusetts (SMART 3.0), New York (NY-Sun), and Rhode Island (REG) run their own versions of the same logic: performance-based, long-duration, state-administered revenue that was engineered precisely so that project economics would not live or die on federal policy. In 2026, that engineering is being stress-tested — and holding.

State programs are administratively set and periodically reviewed. Incentive levels lock at registration, which is itself an argument for registering sooner rather than later.

3. Depreciation got bigger, not smaller

The least-discussed provision of the OBBBA may be the most durable: 100% bonus depreciation is now permanent. Commercial solar equipment remains 5-year MACRS property, fully deductible in year one for owners with the tax capacity to absorb it.

And here is the detail most post-ITC commentary misses: the ITC came with a basis haircut. Claiming the credit reduced the depreciable basis to 85% of cost. With no credit, owners depreciate the full 100%. On a $2 million system at a 21% federal rate, that is $420,000 of year-one tax value instead of $357,000 — a $63,000 offset the project picks up automatically. Losing the credit is partially self-mitigating.

Two planning notes. First, depreciation — unlike the old credit — cannot be sold to a third party. Post-ITC, the tax-capacity question shifts from “can you use the credit” to “can you use the deduction,” and owners without meaningful tax appetite should be evaluating third-party ownership rather than leaving the benefit stranded. Second, state conformity varies; New Jersey, for example, decouples from federal bonus depreciation, so state-level benefits should be modeled on the state’s own schedule. (Full mechanics in our depreciation and tax incentives guide.)

4. Battery storage kept its credit — and it pairs with everything above

Congress terminated the solar credit. It did not terminate the storage credit. Battery systems — standalone or paired with solar — remain eligible under Section 48E for projects beginning construction through 2033, phasing down thereafter.

For commercial buildings, that keeps a federal incentive attached to the technology that attacks the fastest-growing parts of an electric utility bill: demand charges and capacity obligations. A solar array reduces the kilowatt-hours a building buys; a battery reduces the peaks that set what each remaining kilowatt-hour costs. In markets like Massachusetts, storage also earns direct program revenue through ConnectedSolutions and Clean Peak. Post-2027, solar-plus-storage is how a federal credit stays in the capital stack.

The math, side by side

The table below models a representative 1 MW-DC New Jersey commercial rooftop under both regimes. Assumptions are listed underneath and are deliberately conservative.

Assumptions: 1,200 MWh year-1 production (1,200 kWh/kW-DC), 0.5%/yr degradation; blended avoided retail rate $0.16/kWh escalating 3.5%/yr; SREC-II at $100/MWh for 15 years, locked at registration; O&M escalating 2%/yr; 21% federal tax rate with full year-1 absorption of bonus depreciation; state tax effects excluded (NJ decouples from federal bonus depreciation). Illustrative only — Plankton Energy builds site-specific models for every project.

The project’s operating economics did not change at all — same production, same avoided cost, same state revenue. What changed is the entry price, from roughly $1.0 million net to roughly $1.6 million net. The result is a payback in the mid-five-year range and unlevered returns in the mid-to-high teens on an asset with a 25-to-35-year life, backed substantially by a 15-year state contract and a utility market repricing upward.

The ITC made commercial solar exceptional. Its absence makes commercial solar normal — a strong-returning infrastructure investment that has to compete on its merits. It does.

How the ownership question changes

The credit’s exit reshuffles how to buy solar more than whether to.

Direct ownership now favors owners with real tax capacity, because depreciation is the remaining federal lever and it cannot be transferred. It also gets administratively simpler: no credit means no five-year ITC recapture schedule, which removes a constraint the credit era placed on mid-hold dispositions.

Third-party ownership — PPAs and site leases — becomes the path for tax-light owners, but with a wrinkle worth understanding: industry analysis projects financing costs for non-qualifying third-party projects rising 40-50%  once credits disappear.. The exception is developers holding safe-harbored project pipelines, whose protected 30% credit runs through 2030 and can still be passed through in PPA pricing. In 2026, the most valuable question a building owner can ask a developer is no longer “what’s your price” — it is “what safe-harbored capacity do you hold, and can you document it.” (Framework in Lease vs. PPA vs. Direct Purchase, and financing structures on our Financing page.)

Where it doesn’t pencil

Credibility requires naming the exceptions. Post-ITC commercial solar underperforms in three situations: low-rate utility territories (blended avoided cost near $0.10/kWh stretches paybacks meaningfully — a Northeast problem this is not), roofs with under ten years of remaining life where replacement isn’t coordinated into the project scope, and direct purchases by owners without tax capacity, who leave the largest remaining federal benefit unused instead of structuring around it. None of these is a reason to skip the analysis. All three are reasons to run it before committing capital.

The floor, not the ceiling

Everything above is the conservative case — the economics with zero federal credit. Through December 31st, 2027, a better case is still live: projects that can realistically be permitted, built, interconnected, and authorized to operate by that date, claim the full 30% and land in the left-hand column. The critical path is longer than most owners assume, which is why the sequencing decision belongs in 2026, not 2027.

The right way to hold both truths: underwrite the right-hand column, race for the left.

Frequently asked questions

Is commercial solar still worth it without the federal tax credit?

In strong utility markets, yes. On a representative New Jersey 1 MW rooftop, removing the ITC extends simple payback from roughly 3.6 to roughly 5.5 years, with unlevered returns in the mid-to-high teens — driven by avoided utility cost, 15-year state incentive contracts, and permanent 100% bonus depreciation.

What replaces the ITC in commercial solar economics?

Three things: structurally rising electricity rates (PJM capacity prices have cleared at their cap in three consecutive auctions), state performance-based incentives such as New Jersey’s SREC-II payments locked for 15 years, and permanent 100% bonus depreciation — which now applies to 100% of system cost rather than 85%, since there is no ITC basis reduction.

Does bonus depreciation still apply to commercial solar in 2026?

Yes. The OBBBA made 100% bonus depreciation permanent. Commercial solar remains 5-year MACRS property, and without an ITC there is no basis haircut — the full system cost is depreciable. State conformity varies.

Do batteries still qualify for a federal tax credit?

Yes. Energy storage — standalone or solar-paired — remains eligible under Section 48E for projects beginning construction through 2033, with a phase-down afterward. Storage was not part of the solar termination.

Can I still get the 30% ITC on a new commercial solar project?

Only if the system is placed in service — built, interconnected, and authorized to operate — by December 31st, 2027, or if it holds documented safe harbor from a construction start on or before July 4, 2026. Projects that can make the 2027 window should be sequencing now.

About Plankton Energy. Plankton Energy develops, engineers, installs, and operates commercial solar and storage systems for real estate owners across the Northeast and California, and builds deadline-aware, incentive-accurate financial models for every project — including honest post-ITC pro formas. To see what your building returns on 2026 math, contact Plankton Energy for a site-level assessment.

Disclaimer: This article is for general informational purposes and does not constitute tax, legal, or investment advice. Incentive levels, tax treatment, and program rules change; figures shown are illustrative models, not offers or guarantees. Consult a qualified tax professional before making investment decisions.