What a 1 MW Commercial Solar System Costs in California in 2026

The Installed Cost: $1.5-1.9 Million for 1 MW

The most defensible figure available puts commercial (C&I) solar at $1.67 per watt DC nationally, per SEIA and Wood Mackenzie's Q1 2026 U.S. Solar Market Insight data, up 4% year over year. That increase is notable because residential pricing fell roughly 7% over the same period — the divergence is attributed to Section 232 metal tariffs, which hit commercial-scale structural and electrical balance-of-system costs harder than smaller residential installs.

For a straightforward 1 MW rooftop or ground-mount system in California, that puts total installed cost in a working range of $1.50-$1.90 per watt, or roughly $1.5-1.9 million before any tax credit. Lower figures circulating on aggregator and SEO sites (some claiming $1.10-1.30/W for large C&I) are not well-supported by primary sources and shouldn't be treated as a baseline for budgeting a real project.

This figure describes a clean, no-surprises install. It does not include roof reinforcement or replacement if your structure needs it before an array goes on, interconnection network upgrade costs (see below), or land acquisition if you don't already own a suitable site. Get a site-specific EPC quote before committing capital — a national average is a starting point for a conversation, not a number to sign a contract against.

Roof, Ground, or Carport: The Mounting Decision

Rooftop is the cheapest path structurally and sits inside the $1.50-1.90/W range above, assuming the roof itself is sound. A 1 MW rooftop system needs roughly 100,000-130,000 square feet of usable roof area. The variable that doesn't show up in the headline $/W figure is roof condition — a roof that needs reinforcement or replacement before the array goes on adds cost outside the installed-cost range, and that cost is specific to the building, not something to estimate generically.

Ground-mount sits at the low end of some published ranges ($0.80-1.20/W), but that figure comes from utility-scale EPC benchmarks describing multi-megawatt projects with simpler racking and no roof penetrations. A standalone 1 MW ground-mount typically carries more permitting and civil cost per watt than a 50+ MW utility project, so that low-end number should be treated as directional, not a citable estimate for a 1 MW site. Figure roughly 5-6 acres of land for 1 MW ground-mounted.

Carport is clearly the most expensive option — engineered steel canopy structures, foundations, and wind and snow loading requirements push costs toward $3.00-4.00 per watt for commercial-scale installs, roughly double rooftop. That premium only makes sense where the covered parking itself has independent value to the site (retail, office, campus).

The 48E Tax Credit and the Line at Exactly 1 MW

Section 48E replaced the older investment tax credit structure and set a base rate of 6% of qualified project cost. Getting to the full 30% rate requires meeting prevailing wage and apprenticeship (PWA) requirements — and here is where 1 MW stops being just a size description and becomes the exact regulatory threshold. A facility with maximum net output under 1 MW AC is automatically exempt from PWA and gets 30% regardless of labor practices. A facility at or above 1 MW AC must satisfy PWA to get the higher rate, or the credit falls back to 6%.

The measurement is AC nameplate, not DC capacity — a project marketed as '1 MW' based on DC panel rating can land on either side of the line depending on inverter sizing and how the project is configured. This is worth resolving with your EPC and tax advisor before assuming which rate applies, and worth confirming against the statutory language directly (IRS guidance at irs.gov/PWAFAQS and the Form 3468 instructions) rather than taking any summary, including this one, at face value.

Beyond the base rate, stackable bonus adders exist for domestic content, energy community location, and low-income siting, each reportedly worth up to 10-20 additional points — potentially pushing total credit value toward 40-50% in the best case. These adders are consistently described across industry sources but haven't been independently verified against IRS text here, so confirm eligibility for any specific adder before including it in a project pro forma.

The Deadline That Already Passed

This is the fact that should reshape how this page is read: under the One Big Beautiful Bill Act, signed July 4, 2025, solar facilities under 48E face an early termination structure with two clocks. The first required beginning construction by July 4, 2026 to preserve credit eligibility on the original timeline. As of today, September 5, 2026, that date has already passed.

The second clock now governs: any project beginning construction after July 4, 2026 must be placed in service by December 31, 2027, or there is no investment tax credit at all — not the reduced 6% rate, none. For a 1 MW project, that's a real construction and commissioning timeline to hit, not a distant planning consideration.

'Beginning construction' is established one of two ways: the Physical Work Test (actual physical work of a significant nature on the project) or a 5% cost safe-harbor method. That safe-harbor path has genuinely been a moving target this year. IRS Notice 2025-42, issued August 15, 2025, initially limited the 5% safe harbor to 'low-output' solar facilities of 1.5 MW AC or less — which would have mattered directly for a project sized right at 1 MW, since it kept the easier safe-harbor route open here while pushing larger projects to the Physical Work Test only. Then, on June 6, 2026, a federal district court vacated Notice 2025-42 in full, ruling the IRS had not adequately justified singling out wind and solar for the change. That restores the 5% safe harbor for solar projects of any size, at least for now — the government is expected to seek a stay and likely appeal, so treat this as unsettled rather than final as of September 5, 2026. None of this changes the underlying July 4, 2026 / December 31, 2027 statutory deadlines above, which come from the OBBBA itself and are unaffected by the notice's litigation status. Confirm the live status of both the notice and your construction-start method with tax counsel before filing anything on the strength of either test.

Depreciation: 100% Bonus, But a Longer Class Life

OBBBA made 100% bonus depreciation permanent for qualified property acquired after January 19, 2025, with no scheduled phase-down. That's a meaningful benefit on its own: the full depreciable basis can be expensed in year one, separate from the ITC.

OBBBA also eliminated solar's 5-year MACRS designation. Under IRC §168(e)(3)(B)(vi), that accelerated classification terminates for solar, wind, and energy storage facilities that began construction after December 31, 2024 — those projects fall back to the longer standard depreciation schedules that predate the prior five-year rule, commonly cited as 20 years. With 100% bonus depreciation in place, that reclassification is largely moot right now since the entire basis is expensed immediately regardless of stated class life — it matters more as a contingency if bonus depreciation is reduced in a future tax year, or for a project owner without enough taxable income to use the full deduction in year one.

Standard IRS practice reduces the depreciable basis by half the ITC amount claimed when combining the credit with depreciation — this is an existing basis-reduction rule, not new to OBBBA, and should be confirmed against current IRS publications before being used in a specific tax model rather than assumed unchanged.

Interconnection: Rule 21 Won't Fast-Track You

Rule 21 governs distribution-level interconnection at PG&E, SCE, and SDG&E (it doesn't apply to publicly owned utilities like LADWP, SMUD, or Roseville, which set their own terms entirely). Fast Track — the quickest review path — applies to systems of 500 kW or less at secondary voltage. A 1 MW system exceeds that threshold and should expect Supplemental Review, the Independent Study Process, or a full Detailed Study, any of which extends the review timeline well beyond what a 500 kW project would see.

The bigger risk isn't time, it's cost. California applies a cost-causer-pays model: if the utility determines distribution network upgrades are needed to accommodate your interconnection, you generally pay for them, even when those upgrades benefit other customers who interconnect after you. The CPUC has directed utilities to let projects use existing Integration Capacity Analysis hosting capacity where possible to avoid triggering upgrade costs, but this isn't guaranteed for every site. Budget for the possibility of a five- or six-figure network upgrade cost that doesn't show up in your installed $/W quote, and note that CPUC opened a new interconnection rulemaking (R.25-08-004, via an Order Instituting Rulemaking adopted August 14, 2025) that remains active — Rule 21 mechanics could still change before your project reaches the interconnection queue.

Financing a 1 MW Project

Three structures cover most 1 MW commercial deals. Direct ownership lets you use the 48E credit and bonus depreciation yourself, assuming you have the tax appetite to absorb them. A PPA structure routes the tax benefits through a third-party owner or tax-equity investor, who passes savings back to you as a lower per-kWh rate — the same structural logic that makes PPAs relevant post-25D expiration on the residential side, now operating through 48E instead.

At $1.5-1.9 million, a 1 MW project sits below where traditional partnership-flip tax equity typically operates — those deals commonly start around $20 million, per project-finance industry sources, which puts a standalone 1 MW system out of range for that structure on its own. Sale-leaseback reaches further down the market, with some banks reportedly willing to fund deals as low as $2 million — but that floor sits above, not below, this project's $1.5-1.9M cost range. A 1 MW project at the lower end of that range may still be too small for a standalone sale-leaseback and could need to be bundled with other assets, sized up slightly, or financed through a smaller regional lender rather than a bank running the $2M-and-up program. Get direct quotes before assuming any of these structures is available at this exact size.

On PPA pricing specifically: reported ranges across different sources for California commercial deals span roughly $0.09 to $0.27 per kWh depending on source and assumed offtaker credit quality. These ranges don't agree with each other closely enough to state a single citable figure here — get live quotes tied to your specific offtake structure and utility territory rather than anchoring to any published range.

Batteries and SGIP: Check Before You Assume

As of September 5, 2026, all four California Self-Generation Incentive Program administrators — CSE, SCE, SoCalGas, and PG&E — are in Step 5 of the Large-Scale Storage budget tier, and Step 5 is closed in every territory. This is despite unclaimed funds still sitting in each program: CSE $1.79 million, SCE $2.30 million, SoCalGas $1.96 million, and PG&E $10.74 million, per selfgenca.com's program metrics page, which updates nightly.

When Step 5 is open, the incentive pays $0.25 per watt-hour standard, or $0.18/Wh when stacked with the federal ITC. Right now, don't plan a 1 MW project's economics around SGIP being available — check selfgenca.com/home/program_metrics directly before assuming any dollar figure applies, since 'closed' with funds remaining suggests a possible reopening or lottery process rather than the program being permanently exhausted.