Every state and Washington, D.C., graded on its 2026 commercial and industrial solar policy. Amber diamonds mark sub-markets graded separately.
Blog | August 2026
Each year we build a data-backed map of where solar delivers the most value for commercial real estate owners and investors. This is our 2026 edition, and it reflects a market that is maturing quickly in some states and stalling in others.
This year’s update covers policies already in effect as of July 2026, legislation passed or signed into law this year, and key regulatory decisions that have reshaped project economics since our last update. Federal policy uncertainty around the ITC construction start deadline made state-level incentive programs more important than ever, and the states that have strong programs are pulling further ahead of those that do not.
Our grading evaluates the same core levers we have tracked and you can read more about it under our methodology:
Click here to learn more about our methodology.
The biggest story of 2026 is the widening gap between states that are actively building policy infrastructure for commercial solar and states that are moving in the opposite direction.
Virginia moved up to an A. This is the most significant upgrade in this year’s map. The State Corporation Commission issued a favorable NEM 2.0 final order in April 2026 that preserved 12-month netting, rejected proposed application fees, and slightly improved compensation for net excess generation. Governor Spanberger signed a 525 MW shared solar expansion that for the first time includes customers in southwest Virginia and Dominion Energy continues to procure clean energy, enabling roof leases for our real estate clients.
New York State moves to a B. NYC & Long Island remain an A. The standard NY-Sun MW blocks closed in both Con Edison territory and upstate New York over the course of 2025 and early 2026. The VDER structure and community solar adders remain in place, but the loss of the NY-Sun blocks removed a key incentive layer that underpinned many commercial project cases. The ASAP Act passed the New York Senate unanimously and would reverse a lot of this if signed into law, so this is a market worth watching closely in the second half of 2026.
Maine moved down to a B. LD 1777 passed both legislative chambers and directed the PUC to cap net energy billing at no more than 1.5 times the regional average. The replacement program for 2026 has not yet been defined, and retroactive cuts to existing projects remain a possibility. Until the PUC sets the new rate, underwriting new projects here carries real uncertainty.
New Mexico moved up to a B. Permitted PPAs, a workable net metering structure, and a 100% carbon-free energy standard by 2045 give this market a foundation worth taking seriously. The incentive stack is thinner than the Northeast, but the policy direction is right and the market is developing.
Pennsylvania and Hawaii have been downgraded from our 2025 report owing to a lack of strong commercial & industrial solar incentives in the states.
Illinois remains one of our most active solar markets in the country. The Clean and Reliable Grid Affordability Act, signed in January 2026, extended and expanded the existing $300-per-kW distributed-generation rebate for C&I projects and improved project cash flow by paying 50% of the REC contract value at interconnection. Illinois Shines cleared its waitlist and opened new capacity, with project caps of 5 MW.
Maryland launched its permanent community solar program and the Utility RELIEF Act doubled the NEM cap to 6 GW in May 2026. The SREC market remains active and BGE territory continues to deliver some of the strongest Mid-Atlantic project economics. The open question is what the successor NEM rate looks like when the PSC finalizes it in February 2027, which is precisely why clients with Maryland sites should be moving on interconnection today rather than waiting.
New Jersey expanded its Community Solar Energy Program to 3,000 MW across all four utilities. SRECs, per-MWh incentive, stepped down slightly but BPU modeling confirms project economics remain solid. The key nuance this year is utility territory: PSE&G and JCP&L offer meaningfully different economics for solar developers, and the right answer for a client depends heavily on which utility serves their property.
Massachusetts is running SMART 3.0 with 600 MW of available capacity and base incentive rates around $0.31 per kWh for building-mounted rooftop systems. High commercial electricity rates above 15 cents per kWh and strong upfront payment provisions make Massachusetts one of the most reliable project economics in the country. A short-term processing delay from an ongoing DPU tariff review should clear up with permitting reforms taking effect July 1, 2026.
Connecticut extended its NRES tariff program through 2035 after Governor Lamont signed HB 5340 in July 2026. The Buy-All tariff at $0.33 per kWh locked for 20 years is still available for projects interconnecting before the successor program launches.
Rhode Island continues to deliver consistently strong economics with the REG program paying $0.27 per kWh locked for 15 to 20 years, combined with the highest commercial electricity rates on the East Coast outside Hawaii.
A D rating does not mean solar will never work in these markets. It means that right now, the available incentives and regulatory environment make it very difficult for typical commercial projects to pencil. Some D states have high electricity rates that partially offset weak policy. We evaluate every site on its own merits.
What the D designation tells you is that these markets require more creative structuring, more careful site selection, and more patience. They are not where we focus our pipeline, but they are not automatically off the table for every client.
The states where policy is strong are not waiting. Maryland, Illinois, New Jersey, Massachusetts, Connecticut, and Rhode Island all have active programs with capacity that fills on a first-come basis. Virginia has opened up meaningfully this year. New York is in a transitional moment where the outcome of the ASAP Act will determine whether it strengthens or weakens further.
If you have properties in these markets and have not yet had a solar conversation, now is a good time to start. Use the map above to explore your state, see what is working and what is not, and reach out if you want to talk through what it means for your specific portfolio.
Curious what this means for your properties? Connect with a SolarKal advisor.
Talk to a Solar Advisor: Inquiries@SolarKal.co
An inside look at how SolarKal grades each U.S. jurisdiction for commercial and industrial solar.
Updated July 2026 · 50 states + DC + LADWP + NYC and Long Island
Each jurisdiction’s performance across the four criteria resolves into a single letter grade. Where a jurisdiction lands is calibrated against real-world deal economics.
Every jurisdiction’s grade comes out of these four inputs, read together. We rebuild the grades twice a year, and on any docket that meaningfully shifts the picture.
We score the strength and durability of program-based incentives: SRECs, performance-based payments, capacity rebates, community-solar carve-outs, and storage adders. The best states layer multiple programs—Illinois Shines plus Adjustable Block, NJ SuSI, and Massachusetts SMART—so projects can monetize generation across years.
Predictability matters as much as size. A state that posts published block prices for 24 months wins over one with bigger headline numbers but quarterly reauthorization risk. We discount programs that have hit caps or waitlists, and we trust near-term contracted REC values over speculative ones.
The cheaper grid power is, the harder solar has to work to beat it. We grade C&I retail rates—energy, demand, and delivery—across each state’s major investor-owned utilities. High-rate states like Massachusetts, California, Hawaii, and Connecticut give solar a tailwind even when incentives are modest.
We also look at rate-class detail: time-of-use shapes that line up with solar production, demand-charge structures that storage can shave, and rider history that signals where rates are heading. A 12-cent state with strong demand growth often beats a 14-cent state with declining demand.
Net metering—and increasingly its successor tariffs—is the single biggest swing factor for behind-the-meter C&I. We grade based on credit value, system-size caps, rollover rules, and the longevity of grandfathering provisions.
A retail-rate NEM at 2 MW with a 20-year contract beats a complicated value stack at 75% credit every time. We track docket activity carefully: states moving toward export-rate compression get marked down even before final rules land.
Sunlight is the cheapest input on the spreadsheet. We use NREL kWh/m²/day means by climate zone, then adjust for typical commercial array orientation and seasonality. The Southwest delivers 20% to 25% more energy per installed kilowatt than the Pacific Northwest or New England.
Strong resource can rescue a weak-policy state for utility-scale or PPA-driven deals. But for behind-the-meter projects, irradiation rarely overcomes a broken NEM regime: the economics still need the policy stack to monetize the kilowatt-hours.
