10 states generating the most solar power in 2026

California still anchors U.S. solar power generation in 2026, but Texas has done more than any other state to reshape the national map. Cheap rural land, strong sunlight across the western half of the state and a grid operator that connects new projects quickly turned Texas into the busiest solar construction market in the country. Florida, North Carolina and Arizona round out a leading group where utility-scale arrays now supply a meaningful share of daytime electricity demand.

The more useful question is not which state holds the biggest capacity number, but what put each one near the top. Some lead because large population centers need generation built close to home. Others lead because open land and steady sun make utility-scale arrays the cheapest new power a utility can buy. A few climbed early through state mandates, renewable portfolio standards or net metering rules that pulled homeowners into the market. A newer group — Virginia and Ohio among them — is adding solar because data centers and chip plants signed contracts that pushed new generation onto the grid.

The Solar Energy Industries Association and the U.S. Energy Information Administration both track installed capacity and generation by state. Their records show the same core group of states holding the top of the national leaderboard for several years running. Rather than attach precise figures to a year still unfolding, this list weighs installed capacity, active project pipelines and policy. Those three factors determine which states keep producing the most electricity from the sun.

Geography alone no longer explains the rankings. Ohio and Indiana get less sun than Arizona and produce less electricity per panel, yet both have added large volumes of utility-scale solar on leased farmland. Georgia's expansion came through utility regulators rather than legislators. Nevada sends much of what it generates to neighboring states.

Homeowners weighing rooftop panels, utilities planning transmission upgrades and analysts tracking the U.S. energy mix all watch these rankings. Here are the 10 states generating the most solar power in 2026 — and the specific forces behind each one.

Illustration: Quartz

California generates more solar electricity than any other state and has held that position for more than a decade. The lead rests on two things no rival has matched at once: a vast fleet of utility-scale desert and valley solar farms, and the country's largest concentration of rooftop systems.

Much of the utility-scale output comes from Kern, San Bernardino and Riverside counties. Flat terrain, strong sun and proximity to existing transmission lines made large arrays financially workable there well before panel prices fell nationwide. Projects such as Solar Star in Kern County and Topaz Solar Farm in San Luis Obispo County rank among the largest photovoltaic plants in the country. The Mojave Desert also holds some of the oldest commercial solar thermal plants in the U.S., built when photovoltaic panels were still too expensive for grid-scale use.

Rooftop solar is where California separates itself most clearly from Texas and Florida. High retail electricity rates give homeowners a strong financial case for generating their own power. Net metering rules, revised repeatedly by the California Public Utilities Commission, pulled hundreds of thousands of households into the market. The state building code has required solar on most new single-family homes since 2020, so residential capacity keeps accumulating even when installation activity slows.

All that midday generation created a problem the state now spends heavily to solve. Grid operators call the daily pattern the duck curve: solar floods the system around noon, then falls away in the early evening as household demand climbs. The California Independent System Operator has recorded negative prices during sunny spring afternoons. The response has been battery storage at a scale no other state matches, including large installations at Moss Landing and across the Central Valley built to shift afternoon output into the evening peak.

Growth has cooled relative to newer markets. Interconnection queues, transmission constraints and land-use disputes slow new projects, and reduced compensation under the current net metering structure has dampened the residential market. The installed base is large enough that California's generation lead should hold even as other states add capacity faster.

Illustration: Quartz

Texas has added utility-scale solar faster than any other state in recent years, closing much of the gap with California on total generation. Cheap rural land, strong sunlight across the western half of the state and a quick interconnection process have pulled large developers there.

The Electric Reliability Council of Texas runs a grid that sits largely outside federal interconnection oversight. Its queue process has let developers energize projects on shorter timelines than regions with layered regulatory review. That speed advantage compounds. A project reaching commercial operation two years earlier starts earning revenue two years earlier, which changes the financing math before a single panel is mounted.

Siting is equally straightforward. The Permian Basin and the surrounding plains offer flat, low-value acreage already threaded with transmission corridors and service roads built for oil, gas and wind. Developers can lease large contiguous tracts from a handful of landowners instead of assembling parcels from dozens of them.

Nearly all of this growth is utility-scale. Texas has no statewide net metering requirement, and residential adoption has trailed far behind the state's generation totals. That inverts the pattern in states where retail rate design pulled homeowners in first. Some municipal utilities run their own buyback programs, but no uniform statewide policy exists.

Corporate buyers have underwritten a large share of the pipeline. Technology firms building data centers in the state, along with industrial and retail companies, have signed long-term power purchase agreements that give developers the contracted revenue lenders require.

Solar also fits the state's existing wind fleet. Output from West Texas and Panhandle wind farms tends to rise overnight and fall during the day, while solar peaks in the afternoon alongside air conditioning load. That complementary shape has carried more weight since the February 2021 winter storm exposed how thin reserve margins could become.

Friction remains. Some rural counties and landowners have opposed large arrays over land use and property value concerns. Transmission capacity in parts of West Texas has not kept pace with the generation being built behind it.

Illustration: Quartz

Florida's solar fleet ranks among the largest in the country, and a utility built most of it without a state mandate requiring it. Florida Power & Light, the state's biggest electric utility, has installed large arrays across the central and southern peninsula as part of a long-term plan to cut fuel costs and emissions.

Economics drove that decision more than policy did. Florida has no statewide renewable portfolio standard obliging utilities to source a share of their power from renewables. The utilities built anyway, because new photovoltaic generation came in cheaper than most other ways of adding capacity, and because the state's demand curve matches the hours when panels produce.

Daytime load is the structural advantage. Air conditioning demand in Florida peaks through hot afternoons, the same hours a solar farm reaches full output. A utility serving millions of customers in a subtropical climate can put that midday electricity to work immediately rather than storing or exporting it.

The climate is not the cloudless desert sky of the Southwest. Humidity and afternoon thunderstorms cut into production on many summer days. What Florida offers instead is consistency — sunlight is dependable year-round, and winter brings none of the snow cover and low sun angles that drag down output in northern states. Flat terrain across the interior of the peninsula keeps siting and construction straightforward.

Hurricanes add a cost developers in calmer regions avoid. Panels, racking and tracking systems have to be engineered for severe wind loading, and that requirement is priced into every project on the peninsula.

Rooftop solar has had a rougher ride. Florida regulators require investor-owned utilities to offer net metering, but the compensation rooftop customers receive for exported power has been fought over repeatedly in the legislature and before the Public Service Commission, leaving homeowners unsure what the payback period on a system will be. Utility-scale construction has moved ahead regardless of how those retail rate disputes land.

Illustration: Quartz

North Carolina produces more solar electricity than any other Southeastern state, and the reason traces back to a 2007 law. The Renewable Energy and Energy Efficiency Portfolio Standard, passed that year, was the first renewable mandate adopted in the Southeast. It required the state's electric utilities to supply a set share of their power from renewable sources.

That mandate arrived alongside a second advantage. Federal rules under the Public Utility Regulatory Policies Act obliged utilities to buy electricity from qualifying small generators. North Carolina's standard-offer contract terms made projects of five megawatts or less financeable, so developers built hundreds of modest arrays rather than a handful of giant ones. The resulting fleet looks structurally different from the concentrated desert installations farther west — dispersed, small and scattered across dozens of rural counties.

Most of that capacity sits on the coastal plain and the eastern Piedmont, much of it on leased farmland, including acreage once planted in tobacco. Fragmented landownership in those counties made assembling thousands of contiguous acres impractical, which pushed developers toward the smaller footprints the contract structure already favored. Lease payments have become a steady secondary income line for landowners in counties with thin agricultural margins.

Duke $DUK Energy, which serves most of the state through two subsidiaries, has since shifted procurement toward competitive bidding under a 2017 state law that replaced the older standard-offer approach. A 2021 law layered carbon reduction targets onto the utility's planning obligations. That gave solar a continuing role in long-term resource decisions rather than leaving it dependent on the original 2007 quota.

Rooftop installations remain a small share of state output. Residential compensation terms are less generous than those in California, and Duke's revised net metering structure moved new customers onto rates that reward electricity use aligned with midday generation. Homeowner adoption has grown as equipment prices fell, but at a slower clip than the utility-scale sector.

The state also hosts a cluster of solar developers, engineering firms and construction contractors built up over nearly two decades of continuous project work. That base of experience supports steady construction even as newer procurement rules replace the original mandate.

Illustration: Quartz

Arizona produces more electricity from each installed watt of solar capacity than nearly any other state. Sonoran Desert sunlight reaches the ground with little cloud interference for most of the year. The state's total fleet trails California and Texas, but the output a given array delivers makes southern Arizona one of the most productive places in the country to site panels.

Phoenix and Tucson rank among the sunniest large metropolitan areas in the U.S., and that irradiance advantage shows up directly in capacity factors. A panel that generates a set amount of power in the Midwest will produce measurably more in Maricopa, Pinal or Yuma counties. Utility-scale developers have clustered projects across the southern and western parts of the state rather than spreading them evenly.

Arizona Public Service and Tucson Electric Power, two of the state's largest utilities, have increasingly paired battery systems with new solar plants. The reason is a load profile particular to the desert. Extreme summer heat keeps air conditioners running long after sundown, so peak demand lands in the evening, when photovoltaic output has already fallen to zero. Storage moves midday electricity into that window, and the combination has become standard practice in recent Arizona procurements rather than an optional add-on.

Arizona was one of the earliest residential solar markets in the country, built on incentive programs that made rooftop systems common across Phoenix suburbs before panel prices fell nationally. The Arizona Corporation Commission voted in 2016 to end retail-rate net metering and compensate exported rooftop power at a lower rate. Homeowner adoption cooled afterward, and more of the state's growth shifted toward large, utility-contracted arrays.

Water scarcity has shaped the technology mix as well. Photovoltaic panels need almost no water to operate beyond occasional cleaning, which suits a state managing Colorado River allocations. Concentrating solar thermal plants, which generate heat and typically consume more water, remain a small share of capacity. The Solana Generating Station near Gila Bend, a parabolic trough plant with molten salt storage, is the exception rather than a model Arizona has repeated.

Illustration: Quartz

Nevada holds one of the country's highest concentrations of utility-scale solar relative to its population. The buildout sits on open Mojave Desert land near Las Vegas, and much of it is financed by corporate buyers — casino resorts, data center operators and technology firms contracting directly with developers.

Desert valleys south of Las Vegas receive among the strongest sunlight in the U.S., so an array there generates more electricity per installed watt than one in most other states. Clark County also holds large tracts of federal land managed by the Bureau of Land Management, which opens up acreage for projects measured in thousands of acres. The Gemini Solar Project northeast of Las Vegas, built on federal land and brought online in 2024, ranks among the largest solar-plus-storage facilities in the country.

Corporate procurement separates Nevada from the other leading solar states. A provision of state law known as 704B lets very large customers leave bundled NV Energy service by paying an exit fee and buying power directly from generators. Casino companies and the data center firm Switch have used it. That mechanism pushed corporate clean energy budgets into new in-state projects rather than renewable energy credits bought elsewhere. Apple $AAPL contracted with NV Energy for solar capacity serving its northern Nevada data center under a comparable direct-supply arrangement.

NV Energy has signed long-term solar contracts of its own as it moves off coal. The Reid Gardner plant closed in 2017, and solar has absorbed much of the replacement load. State policy reinforced the shift: a 2019 law raised Nevada's renewable portfolio standard to 50% by 2030, giving the utility a fixed target to procure against.

Rooftop solar followed a different course. Regulators cut net metering compensation sharply in 2015, several national installers pulled out of the state, and lawmakers restored more favorable rates in 2017. Residential adoption still trails California's, leaving Nevada's totals weighted toward large arrays rather than homes.

Illustration: Quartz

Georgia built one of the Southeast's largest solar fleets without ever adopting a statewide renewable portfolio standard. The driver was the Georgia Public Service Commission, the five-member elected body that approves what Georgia Power builds, and which has repeatedly signed off on utility-scale solar as the lower-cost option against new fossil fuel generation.

That regulatory route makes Georgia unusual among the leading solar states. California and Virginia lean on statutory mandates. Georgia's capacity moves instead through integrated resource plan proceedings, where commissioners weigh cost projections for solar against gas plants and authorize procurement in blocks. Solar has won those comparisons often enough to push the state near the front of the regional pack.

Coal retirements created much of the room. Georgia Power has closed or converted a series of coal units over the past decade, and the replacement capacity approved in their place has included large solar procurements. The long-delayed, over-budget construction of two new reactors at Plant Vogtle shaped the same proceedings, with settlements between the utility, commission staff and intervening parties adding renewable procurement to the terms.

The land works in the state's favor. South Georgia is flat, rural and planted largely in row crops such as cotton and peanuts, where commodity prices swing from year to year. Long-term lease payments from a developer give landowners predictable income on acreage that may be marginal for farming, and county governments collect property tax revenue on the equipment.

Manufacturing followed the market. Qcells operates panel production in Dalton and has expanded into Cartersville, part of a wider effort to build solar supply chains closer to U.S. customers rather than shipping finished modules across the Pacific.

Rooftop solar remains a minor share of the total. Georgia offers limited residential incentives, and its net metering terms are less generous than those in states where distributed generation took hold, which keeps home systems a small fraction of output. Nearly all of the state's solar electricity comes from large projects owned by the utility or contracted under long-term purchase agreements.

Illustration: Quartz

Ohio now ranks near the top of the Midwest for installed solar capacity, built almost entirely on large utility-scale arrays in rural counties rather than rooftop systems. The state reached that position despite a cloudier climate that yields less electricity per panel than the Southwest.

Developers have favored Ohio for reasons that have little to do with sunshine. Flat, contiguous farmland leases at relatively low rates. High-voltage lines already cross much of the state. Projects also sit inside PJM Interconnection, the regional transmission organization covering the mid-Atlantic and parts of the Midwest. A solar farm there can sell energy and capacity into a competitive multistate market rather than rely on one in-state utility as its only customer.

Siting has been the central constraint. Senate Bill 52, signed in 2021, let county commissioners designate restricted areas where large wind and solar projects cannot be built. It also allows a county to reject a proposal before it reaches the Ohio Power Siting Board. Several counties have used that authority, which is why Ohio's solar growth clusters unevenly instead of spreading statewide.

State policy has pulled in the opposite direction from most leading solar states. House Bill 6, passed in 2019, scaled back Ohio's renewable energy standard and set it to end rather than rise over time. Growth since then has rested on project economics and private contracts instead of a mandate.

Industrial demand is reshaping that math. Intel $INTC's semiconductor manufacturing site under construction in Licking County, east of Columbus, represents a large new electrical load, and data center development around central Ohio has added more. Corporate buyers with clean energy commitments have signed long-term power purchase agreements with Ohio developers, giving projects the revenue certainty lenders require.

Some arrays have gone up on reclaimed strip-mined land in southeastern Ohio, acreage with limited agricultural value and few competing uses. That approach sidesteps the farmland objections that have stalled proposals in other parts of the state.

Illustration: Quartz

Virginia's solar buildout is driven by electricity demand from data centers more than by any other factor. Loudoun County and the surrounding Northern Virginia corridor hold one of the world's densest concentrations of data center capacity, and the power those facilities draw has pulled new generation onto Dominion $D Energy's system faster than any other source of load in the state.

The policy backbone is the Virginia Clean Economy Act, signed in 2020. The law requires Dominion Energy to deliver carbon-free electricity by 2045 and sets interim renewable procurement targets along the way. That mandate separates Virginia from states where utility cost calculations, rather than statutory deadlines, set the pace of construction. Dominion's long-range plans pair solar with offshore wind off the coast of Virginia Beach, giving the state a generation mix unusual on the East Coast.

Most of the solar capacity sits far from the servers it powers. Southern and eastern Virginia, including counties across the coastal plain and the Southside region, offer the open, inexpensive acreage that Northern Virginia's developed suburbs cannot. Electricity from those rural arrays moves north across the transmission network to reach the load centers in Loudoun, Prince William and Fairfax counties.

Corporate contracting has shaped the market as much as regulation. Technology companies running data centers have signed power purchase agreements directly with solar developers, financing projects that might otherwise wait for utility procurement. The arrangement gives operators a claim on clean generation tied to their consumption. It also gives developers the revenue certainty lenders want before construction begins.

The friction point is timing. New data centers can come online faster than new solar farms and transmission lines can be permitted, built and energized. Dominion Energy and Virginia regulators have both flagged that mismatch as a planning problem. Interconnection queues and transmission capacity — not panel supply or available land — now set the practical ceiling on how quickly Virginia's solar fleet can grow.