Commercial Solar Installation Cost in California: What a Business Pays, 100 kW to 1 MW

A California business, farm or public agency installing a commercial system over 100 kW paid a median $2.0 to $4.1 per watt in 2023, depending on customer type, and commercial systems of 100 kW or less ran $2.5 to $4.3 per watt nationally (20th to 80th percentile), per Lawrence Berkeley National Laboratory's Tracking the Sun 2024 Edition (August 2024). Two dates now drive whether a commercial project captures the federal credit and the state property-tax break at all: a solar facility that began construction after July 4, 2026 must be placed in service by December 31, 2027 to get any federal Section 48E credit, and the California property-tax exclusion for solar goes inoperative on January 1, 2027. Verified September 23, 2026.

This page covers commercial, agricultural and public-sector systems measured in kilowatts and megawatts. Pricing a system for a house? See what a home rooftop solar system costs in California instead; residential prices, tariffs and incentives work differently. The cost of a 10 kW home system is worked through on its own page, and the city guides cover home solar permit fees and utilities by California city, from Tracy to Arcata.

Installed cost by system size

LBNL only publishes a state-level figure where at least 20 observations are available, and it splits non-residential systems into small (100 kW or less) and large (more than 100 kW) bands, so a single blended “commercial” average mixes two different markets and, in California, three different customer types. LBNL's newest update, published August 2026, reports non-residential installed prices as “essentially flat year-over-year” from 2024 to 2025 . Its medians for host-owned systems installed in 2025 are $3.2/W in California for 100 kW or less and $2.6/W above 100 kW ($3.1/W and $2.4/W nationally). The table below breaks the 2023 California figures down further, by customer type.

Industry pricing data corroborates the direction: SEIA and Wood Mackenzie's U.S. Solar Market Insight puts the national commercial segment at $1.71 per watt in Q3 2025, up 9% year-over-year from $1.57 in Q3 2024, driven mainly by a 50% year-over-year jump in racking and electrical balance-of-system costs offsetting cheaper modules — the first sustained increase in over a decade of declines.

One caveat on NREL's figures, which show up often in solar pricing discussions: since 2023, NREL's annual “commercial” cost benchmark models a 3-MWdc ground-mount system, not a rooftop or carport project in the 25 kW–1 MW range most California businesses build . Its 2024 figure, $1.55 per watt (NREL/TP-7A40-92536), should not be read as a rooftop number. NREL's last rooftop-scale (200 kW) commercial benchmark, from Q1 2022, was $1.84 per watt modeled market price (NREL/TP-7A40-83586) — four years stale, but still the most recent size-appropriate NREL figure .

For a manufacturing or warehouse site, an industrial system is reported in the same non-residential bands as any other commercial system of the same DC size; the operating profile (shift patterns, process heat, compressors, refrigeration) sets the demand curve, not a separate industrial price table. See warehouse solar and agricultural solar for the load-schedule questions those projects raise.

Because a single average hides which side of the 100 kW split (and which customer type) a project sits on, work through the size-specific guides rather than a blended figure:

• 100 kW commercial solar cost in California
• 500 kW commercial solar cost in California
• 1 MW commercial solar cost in California

For a line-by-line checklist rather than a benchmark, jump to what to ask every bidder to itemize before comparing price.

What's in the price: cost breakdown

NREL's 2024 component breakdown (on its 3-MW ground-mount model, so treat the total with the caveat above) splits as follows. Modules are priced per watt, so the panel count in a bid depends on what wattage commercial panels are.

For a rooftop-scale project, NREL's last granular breakdown (Q1 2022, 200 kW) itemized permitting, inspection and interconnection at $18,053 per project — about $0.09 per watt — including a $5,713 fixed permitting fee, a national average sales tax of 5.8% on hardware, EPC overhead of 13% on materials and 54% on labor, developer overhead of 30%, contingency of 4%, and profit margin of 7% . No NREL or LBNL source publishes a commercial carport-specific cost premium over rooftop; the only mounting-type coefficient either publishes ($0.40/W for ground-mounting) is explicitly scoped to residential systems, so ask a carport bidder to itemize the structural cost separately rather than assume a rule of thumb.

Two buildings with the same annual kWh can still land on very different prices. Roof condition and remaining life, main switchgear and panel capacity, interconnection study results, whether the tariff's demand charges are modeled (not just annual kWh), mounting type, and ownership structure all move the number independently of system size. See PPA versus purchase and commercial financing options for how ownership changes both the price you sign and who keeps the tax benefit.

What you actually pay: federal tax treatment

A California business buying commercial solar in 2026 claims the credit under 26 U.S.C. §48E, the clean electricity investment credit. The statute sets a 6% base rate and a 30% rate for a facility with a maximum net output under 1 MW AC or one meeting the prevailing-wage and apprenticeship requirements. Bonus amounts exist for energy communities, domestic content and certain low-income sites, each with its own test; the domestic manufactured-products share the statute requires is 50% for projects beginning construction in 2026 and 55% after December 31, 2026. As the callouts above state, the credit does not apply to solar property placed in service after December 31, 2027 when the facility began construction after July 4, 2026. Confirm any rate or bonus with a tax professional before counting on it. The bonus tests, the foreign-entity rules, selling the credit and recapture are covered in what the §48E credit rules say in 2026.

On depreciation, 26 U.S.C. §168(e)(3)(B)(viii) classifies §48E qualified property and energy storage technology as 5-year property, and §168(k)(1)(A) provides a 100% first-year allowance for qualified property, which applies to property acquired after January 19, 2025. Under §50(c)(3), the depreciable basis is reduced by 50% of the credit, not the full credit. Here is the federal arithmetic on a representative project:

The credit and the deduction are different mechanisms. The credit reduces tax owed dollar for dollar. The deduction reduces taxable income, so what it is worth depends on your entity's tax rate and whether it has enough income to use it. Ask your tax professional to run both on your own return.

California does not conform to §168(k), and in general does not conform to the 2025 federal legislation that restored the 100% allowance, according to the FTB's 2025 Form 100 booklet, so the state deduction differs from the federal one. The same booklet lists an 8.84% tax rate for corporations other than banks and financial corporations and an $800 minimum franchise tax. Have a tax professional compute the California depreciation schedule and basis.

The credit can be transferred to an unrelated taxpayer under §6418, though not to a specified foreign entity, and tax-exempt and governmental entities can elect to receive it as a payment under §6417. For construction beginning after December 31, 2025, §48E also denies the credit where a facility includes material assistance from a prohibited foreign entity, so panel, inverter and racking sourcing should be documented before relying on the full amount. Under §50(a), the credit is recaptured if the property is disposed of or stops qualifying within five years: 100% within the first full year after it is placed in service, then 80%, 60%, 40% and 20% in each following year.

What commercial solar saves on the utility bill

California's commercial tariffs price energy and demand separately, and demand charges — billed on the single highest metered kW in a period, not on total kWh — do not move nearly as much as a system's annual production does. A system that flattens most of a building's energy use can still leave the one interval that sets the demand charge largely untouched, which is why storage controls belong on the same proposal as the panels, not treated as a separate line item.

Export compensation for anyone interconnecting on or after April 15, 2023 runs through the CPUC's Net Billing Tariff (D.22-12-056, adopted December 15, 2022): hourly, Avoided Cost Calculator-based values, locked in as a “vintage” for nine years from interconnection . PG&E's own billing system did not start billing business customers under its Solar Billing Plan until March 2026, roughly three years after the policy's effective date . SMUD, outside CPUC jurisdiction, pays a flat 9.6 cents per kWh for exported commercial, industrial and agricultural solar, effective June 1, 2026, regardless of time of day or season. SCE's current, non-real-time-pricing commercial TOU-GS tariff sheets and LADWP's current commercial $/kWh rate levels could not be verified from a primary source at publication — rather than estimate, we are saying so plainly and pointing you to each utility's own current rate page before you model a bill offset on either one.

Does commercial solar raise a property's value?

Both the Appraisal Institute's Commercial Green and Energy Efficient Addendum (2015) and the Appraisal Foundation's Valuation Advisory #9 (2018) direct appraisers to the income approach as primary for solar on income-producing property, using the cost approach as a check. Where solar is leased or under a PPA, VA-9 instructs appraisers to examine the contract terms for how they affect “the amount and durability of net income”, and both bodies flag the sales-comparison approach as limited by thin transaction data for specialized systems like solar .

Peer-reviewed evidence isolating a solar-specific value premium for California commercial property does not exist. The closest research measures whole-building LEED/Energy Star certification, not solar in isolation: Eichholtz, Kok & Quigley found a roughly 3% contract rent premium and a 16% sale-price premium for certified office buildings in 2010, and a roughly 3% contract rent premium with a 13%-plus sale-price premium in a larger 2013 follow-up — labeled certification-based, not solar-specific. The closest solar-only figures are industry, not academic, and not Californian: CBRE found a 4.2% value uplift on logistics property from on-site rooftop solar in Continental Europe , and JLL documented two U.S. industrial-property case examples, 4.4% (New Jersey) and 3.7% (Baltimore-D.C.), from third-party rooftop-solar leases valued by discounted cash flow of the lease income. The well-established residential literature — LBNL's “Selling Into the Sun” (about $4/W, or roughly $15,000, for an average home) and a California-specific NBER study of San Diego and Sacramento County home sales (3.5–3.6%) — is residential and should not be applied to commercial property. National commercial cap rates were “broadly stable” around 6.6% in CBRE's H1 2026 survey, with no California-specific table publicly available.

Property tax, sales tax, and permit fees

Under R&T §73, the construction or addition of an active solar energy system is excluded from “newly constructed” for reassessment purposes; storage devices and power-conditioning equipment through the point of electricity conveyance are included as part of the excluded system.The exclusion applies to commercial and industrial property, including utility-scale solar — a 2012 Board of Equalization annotation found no language restricting it (Assessors' Handbook annotation 610.0089) . Per BOE Letter to Assessors 2026/034 (September 1, 2026, the most current guidance available), the exclusion goes inoperative January 1, 2027; a system in process or completed before then keeps the exclusion until a subsequent change of ownership , and there is currently no successor statute for a system placed in service on or after that date. A separate filing rule, effective the same date, gives an initial purchaser of a newly built structure with incorporated solar three years to file the exclusion claim .

On sales and use tax, CDTFA Regulation 1521 covers construction contracts. It treats solar panels that are accessory to a building or structure, such as rack-mounted panels on a roof, as “fixtures,” and building-integrated PV that functions as roofing, windows or walls as “materials”, a distinction that changes how sales tax applies to the contract. It also says a charge for labor to affix solar panels purchased in a completed condition to a mounting system is not taxable. CDTFA also administers a partial exemption for certain manufacturing, research and electric-generation equipment under R&T §6377.1; whether it reaches your business is a question for a tax professional.

Permit fees are capped statewide by Government Code §66015 at $1,000 for a commercial system up to 50 kW, plus $7 per kW for the 51–250 kW portion, plus $5 per kW above 250 kW (effective through January 1, 2034) . Actual city schedules are often lower: San Diego charges $758 plan-check plus $290 inspection for the first 100 kW, and $264 plan-check plus $145 inspection for each additional 100 kW, plus a separate electrical permit fee (Information Bulletin 301) . Confirm your own jurisdiction's current fee schedule directly.

Incentives and mandates

SGIP's general-market non-residential storage budget, Large-Scale Storage, is at Step 5 ($0.25/Wh) and shown Closed for PG&E, SCE, SoCalGas and the Center for Sustainable Energy as of September 23, 2026; the Non-Residential Storage Equity ($0.85/Wh) and Equity Resiliency ($1.00/Wh) budgets are also shown closed. See our SGIP battery storage page (which carries a published correction) before assuming a reservation is available. USDA REAP grants (up to 50% of eligible cost for IRA-funded categories) are currently paused while the agency rescinds its prior notice and rewrites the underlying rule under Executive Order 14315; guaranteed loans, up to 75% of eligible project cost, remain open.

C-PACE assessments are collected on the county property tax bill under Streets & Highways Code §5898.10/.20. Four DFPI-licensed program administrators currently operate statewide (Renew Financial/CaliforniaFirst, PACE Funding Group, FortiFi, and Ygrene), and commercial-focused providers PACE Equity (up to 30-year term, up to 30% of property value, non-recourse, fixed rate) and CleanFund (up to 100% of project cost) also operate here via county and JPA program agreements. Full mechanics, eligible improvements, and how to apply are on our CPACE financing page.

For new construction, California's 2025 Energy Code (Title 24 Part 6, in effect for permits filed on or after January 1, 2026) mandates solar PV, and in most cases battery storage, under §140.10 for a broad list of nonresidential building types, sized at Solar Access Roof Area times 18 W/ft² for steep-sloped roofs or 14 W/ft² for low-sloped roofs. See our Title 24 requirements page for the full building-type list, sizing equations, and battery exceptions .

On utility rebates: SMUD explicitly states it does not offer solar installation rebates, and PG&E, SCE, SDG&E and LADWP's current business pages show no PV cash rebate either — each offers interconnection, net billing, or (for storage) SGIP instead. SGIP itself is a CPUC-authorized, ratepayer-funded program, not a utility's own discretionary rebate.

Timeline and interconnection

PG&E's and SCE's Rule 21 interconnection fees are flat regardless of system size: an $800 application fee and a $2,500 supplemental-review fee at both utilities (confirmed for SCE) . PG&E's own posted timeline runs application review 10–20 business days, engineering review 15–95 business days across up to three phases, and, if grid upgrades are needed, implementation adds 3–12 months on top; once no upgrades are required, final inspection is within 30 business days and interconnection approval follows about 3 business days later.PG&E's Distribution Interconnection Handbook gives an overall typical range of 3–6 months for Simplified/Fast Track review, 3–7 months for Supplemental Review, and 4–10 months for a full Detailed Interconnection Study, with a 15-business-day initial Fast Track review.

Separately, Assembly Bill 2143 requires prevailing wage on renewable facilities over 15 kW enrolled in NEM or the Net Billing Tariff at PG&E, SCE, or SDG&E, with certified payroll filed with the CPUC twice yearly through the SURGE portal . Confirm whether your project's interconnection tariff triggers this before pricing labor.

Quote checklist: what every bidder should itemize

A benchmark only helps if the bids you hold against it describe the same project. Start from one written scope and ask every bidder to state the DC system size, equipment, roof, ground-mount or canopy scope, electrical upgrades, storage, interconnection work, permits, engineering and service responsibilities. If the scopes differ, the totals do not describe the same system: a lower number can leave out site work, roof work, storage or an obligation that arrives later in the contract.

Compare the same cash price and physical scope first. Then put financing, lease, PPA, tax and incentive assumptions on separate rows: a payment illustration does not replace the cash price, and a claimed tax result is not a reduction that applies to every owner. The CPUC's California Solar Consumer Protection Guide is written for residential customers, but its core advice, to make sure everything you were promised is written in the contract, applies to a commercial bid too.

1. Request full proposals and every contract exhibit before deciding.
2. Match technical scope and cash price across bidders.
3. List production, tariff, incentive and remaining-bill assumptions beside their sources and dates.
4. Review ownership, service, finance and property-transfer terms separately.
5. Keep the final contract, change orders and supporting projections together.

Choosing a commercial solar installer

CSLB's C-10 (Electrical) and C-46 (Solar) classifications both explicitly cover photovoltaic installation. Verify the exact contracting entity and its current license, bond, and disciplinary record at the CSLB lookup before signing anything. Ask each bidder to state the DC system size and cash price separately from any financing terms; itemize roof work, electrical upgrades, storage, and interconnection separately from the solar-only price; put expected production, remaining utility bill, and interconnection assumptions in writing; and get ownership, warranty, transfer, and service responsibilities spelled out as their own contract terms, not assumed. See what to compare across commercial solar companies for the full comparison guide.

California Rate Relief is a referral service. We are not a licensed contractor. This page does not quote a system price, install equipment, or determine project eligibility; every figure above is a published third-party benchmark or a statutory rule, dated and cited, not a live bid.

Frequently asked questions

For the size-specific breakdowns and ownership comparison referenced above, see 100 kW, 500 kW, 1 MW, and PPA versus purchase.

Sources

Every figure above traces to one of the primary sources below, checked September 22, 2026; the cost figures, tax statements and SGIP status were re-checked September 23, 2026. Rates, incentive budgets, and program status change; confirm anything you intend to rely on directly with the source.

• LBNL, Tracking the Sun 2024 Edition (full report, Oct. 2024) and executive summary (Aug. 2024)
• LBNL, U.S. Distributed Solar and Storage: 2025 Data Update (Aug. 2026)
• NREL, Documenting 15 Years of Reductions in U.S. Solar PV System Costs (Jan. 2025) and U.S. Solar PV Cost Benchmark Q1 2022 (Sept. 2022)
• SEIA / Wood Mackenzie, U.S. Solar Market Insight, Q4 2025 executive summary (Dec. 2025)
• 26 U.S.C. §48E, §6417 and §6418 (Office of the Law Revision Counsel, text in effect September 22, 2026); IRS Notice 2025-42 (Sept. 2, 2025) and Notice 2026-15 (Feb. 12, 2026)
• 26 U.S.C. §168 and §50 (House OLRC, §50)
• California Franchise Tax Board, 2025 Form 100 Booklet
• CPUC, California Solar Consumer Protection Guide (version 4, 2025)
• California State Board of Equalization, Letter to Assessors 2026/034 (Sept. 1, 2026) and Assessors' Handbook annotation 610.0089 (2012)
• CDTFA, Regulation 1521 and manufacturing/R&D/power equipment exemption guidance
• Cal. Gov. Code §66015 (statute); City of San Diego, Information Bulletin 301
• PG&E, Schedule B-10 and Schedule B-19 tariff sheets (eff. Mar. 1, 2026)
• SDG&E, Medium Commercial and Large Commercial rate summary tables (eff. Jun. 1, 2026)
• CPUC, Net Energy Metering and Net Billing; PG&E, Solar Billing Plan; SMUD, Solar and Storage Rate
• PG&E, Rule 21 interconnection, interconnection process timeline, and Distribution Interconnection Handbook; SCE, Rule 21 FAQ
• Appraisal Institute, Commercial Green and Energy Efficient Addendum (2015); Appraisal Foundation, Valuation Advisory #9 (2018)
• Eichholtz, Kok & Quigley, American Economic Review 100(5) (2010) and Review of Economics and Statistics 95(1) (2013)
• CBRE, Impact of On-Site Rooftop Solar PV on Logistics Property Values (2023) and U.S. Cap Rate Survey H1 2026 (Aug. 2026); JLL, Optimizing Rooftop Potential (Jun. 2026)
• LBNL, Selling Into the Sun (2015, residential); Dastrup et al., NBER Working Paper 17200 (2011, residential, California)
• SGIP, Program Metrics; USDA, REAP FAQ (Mar. 31, 2026) and REAP Notice of Funding Opportunity (Oct. 16, 2024)
• DFPI, PACE Program Administrators
• California Energy Commission, 2025 Nonresidential Solar PV and What's New for 2025 Nonresidential (battery)
• CPUC, Prevailing Wage for Qualified Renewable Energy Facilities (AB 2143)
• CSLB, C-10 and C-46 license classifications