California Solar Farms: Largest Projects and Capacity Directory [2026]

California solar farms have reshaped the state’s electricity supply, pushing total installed solar capacity past 53 GW by early 2026—with utility-scale plants contributing more than 30 GW. Over 900 projects are now operating, in advanced development, or under construction, fueled by a decade of module cost declines, federal investment tax credits, and the state’s mandate for 100% carbon-free electricity by 2045. This directory profiles the largest operating utility-scale sites, digs into the economics, grid challenges, and permitting realities facing new projects, and answers the questions developers, offtakers, and market analysts most often ask.

California’s Largest Solar Projects: Capacity and Ownership

Six utility-scale installations that dominate the landscape illustrate the scale, technology mix, and financial structures that have defined California’s solar build-out. The table below summarizes key metrics for the biggest operating plants.

Project	Location (County)	Capacity (MW AC)	Technology	Year Commissioned	Owner/Developer
Topaz Solar Farm	San Luis Obispo	550	PV, thin-film CdTe, single-axis tracking	2014	BHE Renewables (MidAmerican Renewables)
Desert Sunlight Solar Farm	Riverside	550	PV, thin-film CdTe, single-axis tracking	2015	NextEra Energy Resources / GE Energy Financial Services
Ivanpah Solar Electric Generating System	San Bernardino	392	CSP, power towers	2014	NRG Energy, BrightSource Energy, Google
Beacon Solar Project	Kern	250	PV, crystalline silicon, single-axis tracking	2015	Hecate Energy (now Clearway Energy Group)
Genesis Solar Energy Project	Riverside	250	CSP, parabolic trough	2014	NextEra Energy Resources
Mount Signal Solar (Phase I)	Imperial	200	PV, single-axis tracking	2014	8minutenergy Renewables / Capital Dynamics

Topaz Solar Farm occupies 4,700 acres on the Carrizo Plain, using more than 9 million thin-film cadmium telluride panels on single-axis trackers. The 550 MW AC plant, commissioned in 2014, sends an estimated 1,100 GWh per year to Pacific Gas and Electric under a long-term power purchase agreement. Originally developed by First Solar, it is now owned and operated by BHE Renewables, a Berkshire Hathaway Energy subsidiary.

Desert Sunlight Solar Farm sits in Riverside County’s Sonoran Desert and also delivers 550 MW AC via thin-film CdTe modules on trackers. A 25-year offtake deal with Southern California Edison anchors the project, which began operation in 2015 across roughly 3,900 acres. NextEra Energy Resources holds the majority equity stake; GE Energy Financial Services retains a minority interest.

Ivanpah Solar Electric Generating System, in the Mojave Desert, uses three 140-metre power towers surrounded by 173,500 heliostat mirrors. The 392 MW concentrated solar thermal plant reached commercial operation in 2014, backed by developer BrightSource Energy and equity partners NRG Energy and Google. It supplies both PG&E and Southern California Edison under long-term contracts and remains one of the largest solar thermal tower installations worldwide.

Beacon Solar Project deploys 250 MW AC of crystalline silicon PV on single-axis trackers across more than 2,000 acres in eastern Kern County. A 25-year PPA with Southern California Edison started at commissioning in 2015. Hecate Energy developed the site; Clearway Energy Group now operates the asset.

Genesis Solar Energy Project stretches across Riverside County 25 miles west of Blythe. Its 250 MW parabolic trough design pairs synthetic heat transfer fluid with molten salt storage to extend generation past sunset. NextEra Energy Resources owns and operates the plant, which entered service in 2014, selling electricity to Pacific Gas and Electric via a long-term PPA.

Mount Signal Solar began with a 200 MW AC single-axis tracking PV plant in Imperial County in 2014. Developed by 8minutenergy Renewables, it sells output to San Diego Gas & Electric. Subsequent phases have pushed total capacity above 600 MW, with more under development, making it one of the state’s largest multi-phase solar installations.

How to Read This Directory for Your Own Project Assessment

• Decision rule: If you are evaluating potential offtake opportunities, start by checking PPA expiration dates. Many early 2010s contracts for the plants above will roll off before 2030, creating re-contracting windows that can influence forward price curves.
• Common mistake: Comparing projects using only AC nameplate capacity overlooks technology-specific generation profiles. A 550 MW PV plant might deliver 1,400 GWh annually, while a 392 MW solar thermal tower with storage can produce 1,000+ GWh with a far higher evening contribution—critical for resource adequacy value.
• Practical artifact: When screening a plant, pull together a one-page checklist: offtaker credit rating, remaining PPA term, price escalation structure, land lease status, and curtailment risk in the specific CAISO sub-region.

Grid Integration and Energy Storage: What Developers Need to Know

California’s rapid solar expansion has turned the grid integration challenge into a defining economic variable. The famous “duck curve”—deep midday net load followed by steep evening ramps—pushes CAISO curtailment rates higher and forces storage onto virtually every new utility-scale PV project.

The Curtailment Reality

In certain months, CAISO solar curtailment has topped 5% of potential generation, and on individual days peak renewable curtailment has exceeded 2 GW. Projects sited in transmission-constrained zones, such as parts of the Central Valley, face higher economic curtailment risk that directly eats into PPA revenue.

Co-Locating Batteries as the Default

By early 2026, more than 8 GW of battery storage was paired with solar projects in the CAISO interconnection queue. That shift is not just about capturing otherwise wasted kilowatt-hours; it turns a solar plant into a hybrid resource that can qualify for Resource Adequacy (RA) contracts.

• Expert nuance: A solar-plus-storage facility’s Net Qualifying Capacity (NQC) can be significantly higher than a stand-alone PV plant’s. While a typical solar farm might get an NQC value of just 25–35% of nameplate during summer peak hours, adding a 4-hour battery can lift that to 70% or more, dramatically improving revenue stacking.
• Decision rule: If your project site sits in a high-congestion area, start the feasibility analysis by modeling co-located storage capacity of at least 30% of the solar AC rating with a 4-hour duration. This unlocks RA contracts and hedges curtailment.
• Common mistake: Assuming that the MW AC rating of a solar plant equals its contribution during the system peak. In California’s resource adequacy framework, the “unforced capacity” value of an un-stored PV plant is modest, and developers who size their project revenue model solely on nameplate often overestimate merchant income.

Land, Permits, and Environmental Review for Utility-Scale Solar

Siting a large solar facility in California means navigating a dense regulatory landscape that varied by land ownership—private, state, or federal—and by technology type.

Permitting Pathway	Typical Lead Agency	Approximate Timeline (for a 100 MW PV plant)	Key Requirements
County Conditional Use Permit (CUP)	County planning department	18–24 months	CEQA review, biological surveys, visual impact analysis
Bureau of Land Management (BLM) Right-of-Way Grant	BLM (for federal desert lands)	24–36 months	Desert Renewable Energy Conservation Plan (DRECP) compliance, NEPA review
California Energy Commission (CEC) Opt-In Certification	CEC (thermal plants ≥50 MW)	18–24 months	Comprehensive environmental review, public hearings, facility licensing

Avoiding Lengthy Entanglements

• Specific scenario: A developer proposes a 150 MW PV site on private land in Kern County. The county’s Zoning Ordinance will likely classify the use as a “solar farm” requiring a CUP. If the parcel contains even a small drainage feature considered a state watercourse, a Streambed Alteration Agreement from the California Department of Fish and Wildlife can add 6–12 months to the schedule.
• Common mistake: Underestimating the time and cost of a California Environmental Quality Act (CEQA) review when sensitive habitat or cultural resources are discovered. A full Environmental Impact Report (EIR) with mitigation can stretch permitting to three years and add substantial consultant costs.
• Source interpretation: The Desert Renewable Energy Conservation Plan’s “development focus areas” are often cited as pre-approved zones, but in practice many parcels still require site-specific surveys for desert tortoise, Mojave fringe-toed lizard, and cultural resources, and mitigation ratios can be as high as 5:1 for temporarily disturbed land.
• Expert nuance: For large concentrating solar thermal plants above 50 MW, the CEC’s opt-in process can consolidate air, water, and biological reviews into a single certificate, but choosing that route commits the developer to full commission oversight for the life of the facility—a trade-off that some PV developers avoid by staying below the threshold or using county permits.

Economics and PPA Benchmarks for California Solar Projects

A utility-scale solar plant’s financial viability hinges on three levers: capital cost per installed watt, capacity factor at the specific site, and the offtake price a developer can secure.

What Power Purchase Agreements Look Like Now

Recent power purchase agreements for California solar reflect increasing competition from storage and a build-out that has doubled utility-scale capacity since 2020.

Technology	PPA Price Range ($ / MWh)	Typical Contract Term	Common Offtaker Types
Single-axis tracking PV (no storage)	$25–$35	15–20 years	CCAs, IOUs, corporate buyers
PV + 4-hour battery (solar-plus-storage)	$40–$60 (blended)	20–25 years	CCAs, IOUs, municipal utilities
Concentrating solar thermal with storage	$60–$90	25–30 years	IOUs (legacy contracts), a few CCAs

Note: Price ranges approximate observed bilateral PPA levels in CAISO as reported by LevelTen Energy and market participants; actual negotiated prices vary with delivery point, shape, and hour-ending profiles.

• Decision rule: When your development-stage project’s all-in levelized cost of energy (LCOE) exceeds $35/MWh for a PV-only plant, securing a PPA above $30/MWh can be difficult in current competitive solicitations. That means the margin for incremental costs like avian-friendly fencing or extra transmission upgrades must be scrutinized.
• Expert nuance: Community choice aggregators (CCAs) have become the dominant offtakers for new solar farms in California, often offering more flexible contract durations and shape-based pricing than investor-owned utilities. However, a CCA’s credit quality can vary significantly; developers frequently require an investment-grade rating or a letter of credit enhancement to achieve bankability.
• Common mistake: Ignoring the phasedown of the federal Investment Tax Credit (ITC) beyond 2032. Projects that begin construction before the step-down guarantee a higher credit rate, and modeling a project on the assumption that the full 30% ITC will be available in 2034 can produce unrealistic pro forma returns.

What Drives the Profitability Range?

Well-sited solar plants in California with long-term PPAs from investment-grade offtakers typically generate unlevered internal rates of return in the mid-single digits to low teens. Strong solar irradiation, elevated wholesale summer prices, and the ITC are the main value drivers. Plants that rely heavily on merchant revenue after their initial PPA expiry assume a much wider band of possible outcomes, making storage co-location even more critical for revenue stabilization.

Download the Full California Solar Project Dataset

Gain a competitive edge with our complete, free directory of over 400 California solar installations. The CSV file includes capacities, locations, owner details, and operational status for everything from operating giants to projects in advanced development. Download it to screen off-takers, benchmark project sizes, or populate your own GIS layers.