Renewable Energy Standard: witness tells House committee RECs are how Vermont legally claims renewable power; benefits and rate impacts debated

Peter Sterling, executive director of Renewable Energy Vermont, told the House Energy and Digital Infrastructure Committee on Feb. 6 that the state’s Renewable Energy Standard (RES) depends on retiring renewable energy credits, or RECs, and that retiring those credits is how utilities can legally claim renewable electricity.

Sterling told the panel that the REC system is an accounting mechanism layered on top of the physical grid: "The only way you can legally say you use renewable power is to retire the renewable energy credit from Hydro Quebec or a NIPO dam in Northern New York," he said, using a raffle-certificate analogy to explain ownership of RECs. He said that without the RES requirement to retire RECs, almost 60% of Vermont’s electricity would be accounted for as coming from the region’s nonrenewable sources.

Why it matters: The RES determines what Vermont can claim about the carbon intensity of its electricity supply and affects whether more renewable projects get built in state. The committee heard competing framings: Sterling emphasized modeled air-quality and health benefits, price-suppression effects and local economic gains from distributed generation; some committee members pressed on near-term rate impacts and reliability during extreme cold.

Sterling reviewed modeling the Department of Public Service supplied to the committee and said the department’s compliance model shows both costs and benefits. He cited a calculation attributed to Renewable Energy Vermont that reducing electric-sector emissions under the RES would be "equivalent to taking 470,000 cars off the road between 2025 and 2035." He also said the department’s model likely underestimates climate benefits because it used a social cost of carbon that Sterling said was lower than federal guidance and other recommendations.

On costs, Sterling acknowledged the department’s compliance numbers showing a measurable rate impact. He summarized remarks from department staff that, in the department’s view, RES compliance increased rates by roughly 3.5 percent so far and could add more over time under some scenarios. Sterling urged committee members to consider benefits not fully captured in that simple cost column, including price suppression (lower wholesale prices when midday solar floods the market), reduced line-loss and transmission costs, and local lease and income payments from solar projects.

Committee members asked about reliability during the recent cold snap. Sterling and other witnesses said that during very cold weather the New England system was supplemented by oil as well as gas and that the marginal fuel on the grid remains natural gas; they said that adding renewables plus storage and load management reduces reliance on marginal fossil plants over time. Sterling said, "When we bring more renewables online, we decrease our reliance on those natural gas grids." He also emphasized the difference between where electrons flow and what a state can legally claim via REC retirement.

The committee discussed interactions between the RES and other programs such as net metering. Sterling said RECs make many small projects financially viable because developers can sell both the energy and the associated RECs. He noted some stakeholders’ concerns about how net-metered resources and other incentives interact with rate impacts and said those are separate questions from the department’s compliance-cost calculation.

Sterling answered detailed committee questions about modeling assumptions, the ISO New England energy mix, and how the REC market functions. He offered to follow up with more data by email. The committee did not take formal votes on the RES during this hearing.

Sterling and committee members also discussed distributional impacts—where projects are built and who captures benefits—and the committee exchanged questions about whether RES-driven projects disproportionately affect particular ratepayer groups. Sterling said the mix of benefits—local leases, below-market electricity for some customers, and broader system-price effects—should be included in evaluations of RES value.

The committee set further hearings and asked staff and intervenors to provide additional material on cost, modeling assumptions and interactions between the RES and other procurement and net-metering programs.