How the commercial solar market differs by state
Three questions frame every state. First, what pays for the production: a state tariff, a competitive procurement, bill credits, or simply avoided retail cost? Second, how is exported energy valued, and what does that imply for system size relative to load? Third, how long and how expensive is interconnection on the feeder that serves your site? The summaries below are starting points, not pro formas.
Massachusetts
Our home market and the most incentive-rich of the eight. The SMART 3.0 tariff pays a 20-year production-based rate set annually by DOER, and new private solar generally receives net metering credits at 60 percent of the retail components on exported energy. Municipal light plant territories sit outside SMART, and interconnection group studies with Capital Investment Project fees are the main schedule risk above a few hundred kilowatts.
Connecticut
Commercial solar is driven by the Non-Residential Renewable Energy Solutions (NRES) program administered through the utilities under PURA oversight. It is a competitive, category-based program authorized to select up to 100 MW per year over six years, and PURA's 2025 review raised price caps to reflect federal tax credit changes. Winning a bid, not just qualifying, is the gating step.
Rhode Island
The Renewable Energy Growth (REG) program lets commercial-scale projects sell their output under long-term fixed-price tariffs, with ceiling prices and megawatt allocations revised each program year by the Distributed Generation Board and administered by Rhode Island Energy. Rhode Island is effectively a single-utility state, which simplifies interconnection coordination but concentrates queue risk.
New Hampshire
No production tariff comparable to SMART. Economics rest on avoided retail cost, net metering, and group net metering arrangements that let a host share credits with other accounts. Projects tend to be sized tightly to on-site load, and the federal credit and depreciation carry more of the return.
Maine
Net Energy Billing has driven most distributed solar growth, with a kWh credit program and a tariff rate program for non-residential customers, both limited to projects under 5 MW. The Legislature reformed the program in 2025, and the PUC set tariff rates in December 2025, so eligibility and credit values depend heavily on a project's timing. Confirm current rules with the Maine PUC before modeling.
Vermont
Net metering under PUC Rule 5.100 is the primary pathway, with siting adjustors that favor preferred sites such as rooftops, parking lots, and previously developed land. Small, well-sited rooftop and carport systems fit the rule best; greenfield ground mounts face both lower compensation and more rigorous Certificate of Public Good review.
Florida
Strong solar resource, no state production incentive. Investor-owned utilities offer net metering for customer systems up to 2 MW under the Public Service Commission rule, and commercial value comes from avoided energy and demand charges. Wind load design for hurricane exposure is a larger engineering driver here than anywhere else we work.
Texas
Most of the state sits in the ERCOT competitive retail market, where there is no statewide net metering mandate and export compensation depends on the retail electric provider's buyback plan. Commercial projects are therefore designed around self-consumption, demand charge reduction, and resilience, and battery storage often carries a larger share of the value than in New England.