Solar Tax Credit 2026 Guide: What Changed and What Homeowners and Businesses Need to Know

The solar tax credit 2026 picture looks nothing like it did 18 months ago. The One Big Beautiful Bill Act (OBBBA), signed on July 4, 2025, terminated the 30% residential Investment Tax Credit under Section 25D for any system placed in service after December 31, 2025. That credit had been the financial backbone of U.S. rooftop solar for nearly 2 decades. Its expiration is the single largest policy shift the residential market has absorbed since the ITC was created in 2005.

Here is the part most headlines missed: the federal solar tax credit did not disappear. It split. Residential homeowners buying with cash or a loan no longer claim any federal credit on a new system. Commercial, utility-scale, and third-party-owned projects still qualify for the Section 48E ITC at 30%, with adders that can push the effective rate to 40%, 50%, or higher. The result is a market where who owns the system now matters as much as whether you install one.

We structure solar project financing for a living, and we model payback for installers every week. This guide walks through what changed, what survived, and how to run the numbers honestly in 2026 — whether you are a homeowner weighing a purchase or an installer rebuilding your quotes around the new rules.

In this guide:

• What changed on January 1, 2026, and which deadlines still matter this year
• How Section 25D ended, and who can still claim it on a 2025 return
• How the Section 48E commercial credit works in 2026, including the July 4 begin-construction cliff
• Domestic content and FEOC rules, and why the 50% threshold is harder than it sounds
• What the ITC expiration does to residential payback, state by state
• The financing workarounds — leases, PPAs, and third-party ownership — that keep a federal credit in play
• How we think installers should re-quote residential jobs in 2026

Latest Updates: Solar Tax Credits in 2026

The federal solar tax credit framework now runs on 2 parallel tracks. One track ended. The other is on a countdown. This table shows where each credit stands as of July 2026.

3 dates define the 2026 calendar.

• December 31, 2025 — the last day a homeowner-owned system could be placed in service and still qualify for the 30% Section 25D credit. “Placed in service” means fully installed, inspected, and granted permission to operate by the utility — not merely purchased or contracted.
• April 15, 2026 — the filing deadline for 2025 tax returns. Homeowners who completed a system in 2025 claim the credit on Form 5695 with their 2025 return, or on an amended return if they missed it.
• July 4, 2026 — the begin-construction deadline for Section 48E projects to qualify under the more forgiving rules. Projects that start construction after that date face a tighter placed-in-service deadline and a shorter runway to lock in the 30% rate.

The IRS has also issued guidance tightening what counts as “beginning construction.” Physical work of a significant nature — or incurring at least 5% of total project cost under the safe harbor — still establishes the start date. Our read: documentation discipline is now a financial variable, not an administrative one. Installers and developers who cannot prove when construction began risk losing the credit on an audit.

One more update that matters for 2026 planning: the domestic content threshold steps up. Projects beginning construction in 2026 need 50% of component costs from qualifying sources to earn the +10-point bonus. Projects beginning after 2026 need 55%. We cover the mechanics in the domestic content section below.

How the market has responded so far

6 months into the post-credit market, 3 patterns are visible. Residential loan volume dropped sharply in Q1 2026 as the buyers who could move fastest purchased in late 2025 instead. Lease and PPA bookings rose over the same period, because third-party ownership is now the only structure that puts a 30% federal credit into a residential deal. And commercial procurement accelerated ahead of the July 4 begin-construction deadline, pulling some 2027 project pipelines into 2026.

Price is the adjustment nobody wanted to discuss in January. Residential installed prices were already drifting down from their 2023 peak, and the loss of the credit is pressuring them further. Several national installers have cut per-watt pricing by $0.10–$0.30 on cash deals to keep payback inside the customer’s planning horizon. Hardware costs cannot absorb the full $7,000–$9,000 the credit used to cover, but the market is clearly sharing the pain across the value chain.

What Happened to the Residential Solar Tax Credit?

The residential solar tax credit — formally the Section 25D Residential Clean Energy Credit — gave homeowners a dollar-for-dollar reduction in federal tax liability equal to 30% of installed system cost. On a $30,000 system, that was a $9,000 credit. OBBBA terminated it outright for property placed in service after December 31, 2025. There is no phase-down, no partial credit, and no grandfathering for contracts signed but not completed.

That last point burned real people. Homeowners who signed a contract in November 2025 but whose utility granted permission to operate in January 2026 get nothing from the federal government. The credit attached to the placed-in-service date, not the sale date, the installation date, or the payment date. We watched installers scramble through December 2025 to commission systems before year-end, and interconnection backlogs in several utilities meant some customers missed the deadline through no fault of their own.

Who can still claim the 30% credit

Homeowners whose systems were placed in service on or before December 31, 2025 can still claim the credit — on the 2025 return they filed in spring 2026, or on an amended return within the standard 3-year window. The claim goes on IRS Form 5695, filed with the 2025 return. If the credit exceeded 2025 tax liability, the unused portion carries forward to future tax years. It does not expire while it carries.

3 details to get right on that claim:

• The credit covers panels, inverters, racking, wiring, battery storage with at least 3 kWh of capacity, and the labor and permitting costs tied to the installation.
• Roof repairs and structural work do not qualify, even when the installer required them before mounting panels.
• Utility rebates that adjust the purchase price reduce the cost basis; state tax credits generally do not.

Why Congress let it expire

OBBBA’s framers argued the residential credit had done its job. Residential solar costs fell roughly 60% over the credit’s lifetime, and the law redirected federal support toward domestic manufacturing and larger projects. Whether you accept that logic or not, the policy reality is fixed: the federal government is out of the homeowner-subsidy business for rooftop solar, and it is staying in the commercial and manufacturing-subsidy business through Section 48E and the Section 45X production credits.

Does battery storage still get a federal credit?

Not for homeowner-owned systems. Standalone batteries and batteries paired with solar lived inside Section 25D, so they expired with it. The federal path that remains for storage is the same as for solar: commercial ownership. A business installing a battery claims Section 48E, and a TPO provider can own a residential battery and claim the credit while the homeowner pays a monthly fee.

This is why battery attachment rates in TPO deals are climbing in 2026. The financier’s 30% credit applies to the battery, the inverter, and the panels as one owned system. For homeowners in states with time-of-use rates or weak export compensation, a TPO-owned battery is often the only way the storage math works at all.

What this means if you are shopping for solar now

If you are a homeowner evaluating solar in 2026, treat the federal credit as zero in every cash-purchase scenario. Any quote that still shows a 30% federal reduction on a homeowner-owned system placed in service in 2026 is wrong, and the installer showing it either has not updated their proposal templates or is selling against the tax code. Both are red flags.

The math has not become impossible. It has become more local. Electricity rates, state incentives, and net metering policy — details that used to sit in the credit’s shadow — now determine whether a project pencils. We break down the ROI shift in the ROI section below.

Section 48E: Commercial Solar Tax Credit in 2026

While the residential credit died, the commercial credit survived under a new name and a new structure. The Section 48E Clean Electricity Investment Tax Credit replaced the old Section 48 ITC as a technology-neutral credit for zero-emission generation and storage. Solar qualifies. So do batteries, wind, geothermal, and several other technologies.

The base rate is 6% of eligible project cost. Projects that meet prevailing wage and apprenticeship requirements multiply that base by 5 — reaching the 30% headline rate. In practice, virtually every commercial project of any size meets the labor requirements, because failing to do so forfeits 80% of the credit’s value.

A commercial project that stacks all available adders can reach 50% or more. That ceiling was true under the old Section 48 as well. What changed is the clock.

The July 4, 2026 begin-construction deadline

OBBBA gave solar and wind projects 1 year from enactment to begin construction under the favorable rules. That window closes on July 4, 2026. Projects that establish a construction start by that date keep the standard continuity period — generally 4 years — to place the project in service.

Projects that begin construction after July 4, 2026 face a compressed placed-in-service deadline. The practical effect: a commercial project that has not started by early July 2026 is a materially riskier financial proposition than one that started in June. We have already seen developers accelerate procurement and pull forward site work to beat the date, and module supply for Q2 2026 tightened accordingly.

Establishing a construction start

The IRS recognizes 2 tests for beginning construction:

1. Physical work test — on-site or off-site physical work of a significant nature, such as manufacturing custom mounting equipment under a binding contract.
2. 5% safe harbor — incurring at least 5% of total project cost, usually through module or inverter purchases under a binding contract.

Either path requires contemporaneous documentation: executed contracts, invoices, payment records, and delivery receipts. The IRS publishes its credit guidance on the IRS credits and deductions portal, and it tightened the rules in 2025 to restrict projects from relying on purchased inventory that sits in a warehouse without a clear path to a specific project. If you are an installer banking modules to preserve 48E eligibility for fall 2026 jobs, get tax counsel to review the structure now — the safe harbor is narrower than the industry assumed.

Who claims the credit

The credit belongs to the system’s owner. For a business installing solar on its own roof, the business claims it. For a leased residential system or a PPA, the financing company claims it. That distinction drives the entire third-party ownership section below, and it is the reason the federal solar tax credit is not truly gone for homeowners — it just changed hands.

For a deeper definition of how the credit works mechanically, see /glossary/investment-tax-credit in our glossary.

Domestic Content Bonus and FEOC Rules

The domestic content bonus adds 10 percentage points to the Section 48E credit — taking a project from 30% to 40% — when enough of the project’s components come from qualifying sources. In 2026, the threshold is 50%: at least 50% of total manufactured-product and component cost must satisfy the domestic content test. For projects beginning construction after 2026, the threshold rises to 55%.

OBBBA layered a second test on top of the old one. It is no longer enough for a component to be made in the United States. It must also be free of FEOC (Foreign Entity of Concern) control — meaning no prohibited ownership, licensing, or supply ties to entities connected to China, Russia, Iran, or North Korea. The FEOC screen reaches into subcomponents, and it is where most 2026 compliance projects are getting stuck.

Why the 50% bar is hard to clear

The U.S. solar supply chain is deep in modules, racking, and steel, and shallow in cells, wafers, and inverters. A project built with American-assembled modules can still fail the FEOC test if the cells inside those modules trace to a restricted supplier. Inverters are the hardest category — a large share of global inverter production runs through Chinese-controlled supply chains, even when final assembly happens elsewhere.

The cost math is straightforward:

On a $2 million project, the bonus is worth $200,000. That is often larger than the project’s entire development margin. The tradeoff: FEOC-compliant, U.S.-content equipment typically costs 10–20% more than the cheapest import alternative. On the same $2 million project, a 15% equipment premium on roughly $900,000 of hardware is $135,000 — leaving about $65,000 of net gain. The bonus usually wins, but not by a landslide, and not before you verify the supply chain paperwork.

Documentation is the real gate

The IRS expects a domestic content certification, and developers increasingly demand manufacturer attestations down to the cell and wafer level. Our experience structuring these deals: start the supply chain audit at the term sheet, not at commissioning. A project that discovers FEOC exposure after equipment is delivered has 3 bad options — swap hardware at a loss, forfeit the bonus, or certify and absorb audit risk.

A contrarian view: the bonus can be a distraction

Here is the position we take that most coverage does not. For small commercial projects — say under $250,000 — the domestic content chase often destroys more value than it creates. The compliance overhead, the equipment premiums, and the deal friction of re-specifying hardware can consume the bonus’s entire margin on small jobs. A $150,000 rooftop earns $15,000 from the bonus. If the compliant equipment package costs $12,000 more and the engineering re-review burns another $3,000, you have worked hard for nothing.

The bonus is designed for projects with procurement teams and tax counsel. If that is not your customer, quote the base 30% credit, hit the begin-construction deadline, and win the job on schedule and price. Discipline about which credits to pursue is itself a competitive advantage in 2026.

How the ITC Expiration Changes Solar ROI

This is the section homeowners actually need. Losing a 30% credit does not make a project 30% worse — it makes it exactly 30 points of cost basis worse, and the payback math flows from there.

Take a typical 8 kW residential system at $3.00 per watt: $24,000 installed. Under the old rules, the federal credit cut the net cost to $16,800. In 2026, the net cost is $24,000. That $7,200 difference is what disappeared on January 1.

Payback before and after

Assume the system offsets a $0.17/kWh utility rate and produces 11,000 kWh per year — about $1,870 of annual savings, escalating with utility rates.

The pattern across the market matches what we reported at the top: typical U.S. residential payback has lengthened from 6–10 years to 8–14 years without the federal credit. The spread across states is now enormous. Electricity price, not sunshine, is the dominant variable.

The states where solar still pencils fast

High retail rates do what the tax credit used to do. In California, Massachusetts, New York, Connecticut, Rhode Island, and Hawaii, residential rates above $0.25/kWh keep payback under roughly 9 years for a well-designed system with decent sun. Add state incentives or full-retail net metering — see /glossary/net-metering — and several markets still deliver sub-8-year payback, better than the national average was with the federal credit.

In low-rate states — Louisiana, Idaho, Washington, much of the Southeast — a cash purchase now pushes past 15 years unless a state or utility incentive fills the gap. In those markets, third-party ownership or simply waiting for rates to rise are rational choices.

What installers must re-model

Every proposal template built before 2026 embeds the 30% credit somewhere: in the net-cost line, the payback chart, or the financing comparison. Those assumptions are now wrong, and wrong payback numbers are a liability, not a sales tactic. We recommend installers rebuild residential quotes around 4 honest inputs:

1. Gross installed cost, with no federal reduction for homeowner-owned systems.
2. Actual utility rate and rate escalator from the customer’s tariff, not a national average.
3. State and utility incentives applied only when documentation supports them.
4. A lease/PPA comparison that shows the third-party owner’s 30% Section 48E credit flowing through as a lower rate or lower monthly payment.

Our generation and financial tool models exactly these inputs — production, tariff, escalator, and incentive stack — so the payback curve a customer signs for is the payback curve the project actually delivers. See /generation-financial-tool for the feature page, and our /blog/solar-installation-cost-breakdown for where every installed dollar goes.

The insight most payback articles miss

Here is something we see in real project data that rarely gets written down. The ITC’s expiration changed the optimal system size. Under the 30% credit, oversizing was nearly free — the credit subsidized every marginal panel, and export compensation did not matter much. Without the credit, each marginal kilowatt-hour exported at a reduced rate earns a poor return, and the financially optimal design hugs the home’s actual consumption.

In 2026, the best residential designs are smaller, consumption-matched, and often paired with a battery sized for self-consumption rather than for backup. Installers still quoting last year’s oversized systems are quoting a worse investment than they realize. This is a design problem, not just a sales problem — and it is solvable in the design phase with proper consumption modeling.

State and Local Incentives That Still Exist

The federal retreat made state policy the front line. The patchwork below is not exhaustive — program budgets open and close — but it shows the main categories still putting real money into residential and commercial solar in 2026.

3 structural points matter more than any single program.

First, SREC markets — New Jersey, Maryland, DC, Pennsylvania, and Ohio — pay for production, not installation. A system earning $80 per MWh on 12 MWh of annual production adds roughly $960 per year of income on top of bill savings. That revenue stream survived the federal changes untouched, and it materially shortens payback in those states.

Second, state tax exemptions still quietly improve project economics. More than 30 states exempt solar equipment from sales tax, property tax, or both. On a $24,000 system in a 7% sales-tax state, the exemption is worth about $1,700. Installers should itemize it in the proposal — customers who see the number treat it as found money.

Third, municipal and utility programs are budget-limited and first-come. NY-Sun blocks step down as they fill. Utility rebates in Texas and Colorado open and close within a quarter. The operational rule for 2026: check program status the week you quote, not the week you close. The DSIRE database from NC State University is the standard reference for current state, local, and utility incentives. Our /blog/solar-financing-options-explained guide covers how these incentives interact with loans, leases, and PPAs.

For installers, the workflow implication is that incentive research is now per-project design work. A proposal that names the specific NY-Sun block or SMART tariff rate reads as professional. A proposal that says “state incentives may apply” reads as lazy. solar software that pulls production modeling and financial assumptions into one workspace makes the per-project version cheap to produce.

Financing Workarounds: Leases, PPAs, and Third-Party Ownership

Here is the structural irony of 2026: the federal solar tax credit is dead for homeowners who buy, and alive for homeowners who do not. Because Section 48E belongs to the system’s owner, a financing company that owns a rooftop system claims the 30% credit — plus applicable adders — on the very same house that would get $0 in a cash sale.

This is third-party ownership (TPO): leases and power purchase agreements where a financier owns the equipment and the homeowner pays for the equipment’s use or its output. TPO share of the residential market collapsed when the 30% residential credit made ownership attractive. Expect it to climb back toward — and possibly past — its 2016 peak above 50% now that ownership carries no federal benefit.

How the credit flows to the homeowner

The homeowner never sees Form 5695. The credit shows up as economics inside the contract:

• A lower lease payment than an equivalent loan payment, because the financier’s cost basis is 30% lower.
• A lower PPA rate per kWh — often $0.02–$0.05/kWh below what the no-credit ownership math supports.
• Escalator headroom, where the financier shares some credit value to offer a flatter rate path.

A concrete comparison for that same $24,000, 8 kW system: a 2026 cash buyer pays $24,000 and recovers roughly $1,870 per year. A PPA customer pays nothing upfront and buys the system’s power at, say, $0.13/kWh against a $0.17 utility rate — saving about $440 in year 1 with zero capital and zero tax appetite required. The cash buyer wins on lifetime savings. The PPA customer wins on day-one cash flow and risk transfer.

The honest tradeoffs

TPO is not free money, and we would not be doing our job if we presented it that way. The financier keeps the credit, the SRECs in most structures, and a margin. Over 20–25 years, a homeowner with the tax appetite and cash to buy outright almost always banks more total savings than a lease customer.

3 practical cautions:

1. Home sale friction. Leases and PPAs must transfer to the buyer or be bought out at closing. Most transfers go smoothly; some delay sales. Read the transfer clause before signing.
2. Escalators compound. A 2.9% annual PPA escalator can erase the initial rate advantage by year 12–15 if utility rates rise slower. Negotiate the escalator, not just the starting rate.
3. Buyout math. Early buyout schedules in TPO contracts are often priced at fair market value that assumes the credit. Get the buyout table in writing up front.

For homeowners with low tax liability — retirees, for example — TPO was often the better structure even when the residential credit existed, because they could not use the credit efficiently. In 2026 that logic extends to everyone: the credit is only real if someone can claim it, and the TPO financier always can.

Community solar: the workaround for non-owners

Renters and homeowners with shaded or unsuitable roofs have a third path in 2026. Community solar subscriptions let a customer buy or lease a share of an off-site project, and the project developer claims the Section 48E credit — often with the low-income or energy-community adders stacked on top. Subscribers typically save 5–15% on the subscribed portion of their bill with no installation at all.

The credit dynamics actually favor community solar more than rooftop under OBBBA. Shared projects are commercial-scale by definition, so they keep the full 30% base rate, and many qualifying sites sit in energy communities. Availability is the constraint: only about 22 states have enabling programs, and waitlists in the strongest markets — New York, Illinois, Minnesota — run months long.

Prepaid leases and the hybrid middle

One structure gaining share in 2026 is the prepaid lease: the homeowner pays a single upfront amount — typically discounted 20–30% versus a cash purchase because the financier nets the 48E credit into the price — and owns the power for the lease term with a $1 or fair-market buyout at the end. It behaves like ownership with a built-in discount. Customers who want ownership economics but lack tax appetite should ask for this quote explicitly; few sales reps lead with it.

How Installers Should Quote Solar in 2026

We sit on both sides of this market — financing projects and building the software installers quote them in. The quoting playbook that worked from 2022 through 2025 is now wrong in 3 specific places, and fixing them is the difference between a credible 2026 pipeline and a trust problem.

1. Strip the federal credit out of homeowner-owned quotes — visibly. The fastest credibility move in 2026 is a proposal with a line that reads “Federal tax credit (Section 25D): expired 12/31/2025 — $0.” Customers have read the headlines. A quote that addresses the expiration head-on disarms the first objection and reframes you as the honest broker. A quote that quietly leaves the 30% line in place will get screenshotted and shopped.

2. Sell rate protection, not subsidies. The 2022 pitch was “get 30% off from the government.” The 2026 pitch is arithmetic: your utility rate has risen about 3–4% per year for a decade, and a solar kWh costs what it costs on day 1. Without a credit, the value story is the widening gap between the utility curve and the solar curve. Model both curves honestly — with the customer’s actual tariff — and the close rate survives the subsidy’s death.

3. Quote TPO and ownership side by side, every time. Roughly half your residential customers are now better served by a lease or PPA than by a purchase. Presenting only a cash/loan option in 2026 is presenting only half the market. The side-by-side comparison also sells ownership harder when ownership genuinely wins, because the customer can see the lifetime-savings gap with their own eyes.

Operationally, this means your design-to-proposal loop has to carry financial modeling that used to live in a spreadsheet. Our solar design software produces the shading-accurate production estimate; solar shadow analysis software validates the array against real obstructions; and our solar proposal software turns those numbers into the cash-versus-PPA comparison in the same sitting. When the design number and the finance number come from the same model, the quote holds together under scrutiny.

One more operational note: watch your close rate by financing type. Across the installer base we work with, cash close rates fell after the expiration while TPO close rates rose. Rebalance your lender and TPO partnerships now — the installers who entered 2026 with only a loan partner are turning away the customers the new policy is creating.

Common Tax Credit Mistakes Homeowners Make

The 2025–2026 transition created a new generation of errors. These are the 6 we see most often — in customer paperwork, in installer quotes, and in online advice that did not survive the law change.

Mistake 1: Assuming the credit follows the contract date. The Section 25D credit attached to the placed-in-service date. Homeowners who signed and even paid in full during 2025 but received permission to operate in January 2026 have no federal credit to claim. The painful corollary: some of these customers are owed honest answers from installers who promised commissioning “by year-end” in writing.

Mistake 2: Filing the credit in the wrong year. A system placed in service in 2025 belongs on the 2025 return — the one filed in spring 2026 — even if the filer forgets until later. The fix is an amended return, not a claim on the 2026 return. The IRS matches credit claims against the placed-in-service year.

Mistake 3: Believing the credit “comes back” in a future year. There is no scheduled revival of Section 25D. Congress could write a new credit at any time, but financial decisions made in 2026 should assume zero federal residential credit for the foreseeable future. Planning around hypothetical legislation is how projects get delayed into worse economics.

Mistake 4: Missing the carryforward. Homeowners whose 2025 credit exceeded their 2025 tax liability can carry the unused portion forward indefinitely until it is absorbed. We still see 2023 and 2024 filers who left carryforward value on the table because nobody told them it rolls. If you claimed the credit in an earlier year and could not use it all, check your prior returns.

Mistake 5: Overstating the cost basis. The credit applied to eligible solar property — panels, inverters, racking, wiring, batteries, and direct installation labor. It did not apply to a new roof, tree removal, or electrical panel upgrades that were not required for the solar installation. Inflating the basis invites an adjustment plus interest; on an audit the IRS asks for the installer invoice and reads the line items.

Mistake 6: Ignoring how rebates interact with basis. A utility rebate that reduces your purchase price reduces the cost basis for any remaining credit or depreciation calculation. State tax credits generally do not reduce federal basis, but state rebates structured as price adjustments do. The distinction is technical, and it is exactly the kind of detail a tax professional earns their fee on in 2026.

A final note that is not a mistake but a blind spot: homeowners who go solar through a lease or PPA sometimes believe they personally received a tax credit because the sales material mentions “30% federal credit.” The financing company received it and priced it into the rate. There is nothing wrong with that structure — but the homeowner should understand what they signed, and reputable TPO providers explain it plainly.

Conclusion

The federal solar tax credit did not end in 2026 — it narrowed. Homeowner-owned systems lost the 30% Section 25D credit on December 31, 2025, and typical residential payback stretched from 6–10 years to 8–14 years. Commercial and third-party-owned systems kept the Section 48E credit at 30%, with adders that reward domestic content, energy-community siting, and low-income projects. Ownership structure, electricity rates, and state incentives now decide whether solar pencils — not a single federal line item.

If you take 3 actions from this guide:

• Homeowners: run the numbers with a $0 federal credit, then compare a cash or loan quote against a lease or PPA where the financier’s 30% credit lowers your rate. In high-rate states, ownership still wins on lifetime savings; elsewhere, TPO often wins on real cash flow.
• Businesses and developers: if your project can begin construction by July 4, 2026, document the start date now. The 30% Section 48E window is open, and the domestic content bonus is worth auditing your supply chain for.
• Installers: rebuild every residential template around the post-credit math — honest payback curves, side-by-side financing comparisons, and consumption-matched designs. The market did not die; it got more demanding, and accurate quoting is now the differentiator.

The subsidy era trained buyers to ask “how much does the government pay?” The 2026 era rewards whoever answers the better question: “what does this kilowatt-hour actually cost over 25 years?” Answer it precisely, and solar remains one of the strongest financial decisions a homeowner or business can make.

Frequently Asked Questions

Is the 30% federal solar tax credit still available in 2026?

No. The 30% residential Investment Tax Credit under Section 25D expired on December 31, 2025 under the One Big Beautiful Bill Act. Homeowners whose systems were placed in service in 2025 or earlier can still claim it on their 2025 tax returns.

What solar tax credits are still available in 2026?

Commercial and utility-scale projects can still claim the Section 48E Investment Tax Credit at 30%, plus adders for domestic content, energy communities, and low-income status. Some state and local incentives also remain.

How does the ITC expiration change solar payback?

Without the 30% federal credit, typical U.S. residential payback lengthens from 6–10 years to 8–14 years. States with high electricity rates and strong net metering still see faster payback.

Can businesses still claim solar tax credits in 2026?

Yes. Commercial solar projects can claim the Section 48E ITC at 30% if construction begins by July 4, 2026. Projects starting after that date face a tighter placed-in-service deadline.

Do leased solar systems still get tax credits?

Yes. Leases and PPAs are owned by the financing company, which can claim commercial tax credits on residential systems they own. The homeowner does not directly claim the credit.

What is the domestic content bonus for solar in 2026?

The Section 48E domestic content bonus adds 10 percentage points to the ITC if at least 50% of component costs come from FEOC-compliant sources. The threshold rises to 55% after 2026.