Official: Vermont’s vertically integrated utilities and long-term contracts have kept rates lower, but transmission and REC costs pose pressure

At a Jan. 29 hearing of the House Committee on Energy and Digital Infrastructure, TJ Poor, director of regulated utility planning at the Vermont Department of Public Service, told lawmakers that Vermont’s vertically integrated utility structure and long-term supply contracts have helped keep electric rates lower and more stable than in other New England states — but that several regional and policy-related cost drivers could push rates higher.

Poor told the committee, “At any given point, our utilities are between 85–95% hedged,” and he pointed to the 2022 price spike in other New England states after Russia’s invasion of Ukraine to illustrate how hedging reduced Vermont’s exposure: “In 2022, prices for the rest of New England shot up. What happened in 2022 is Russia Invaded Ukraine.”

Why it matters: Committee members heard that while Vermont’s mix of owned and contracted generation has smoothed short-term market volatility for consumers, transmission charges, the state’s renewable energy standard (and the cost of renewable energy certificates, or RECs), and the expiration of several long-term contracts could raise rates or require new procurement decisions that reshape supply through the 2030s.

Key points from the presentation

- Rate drivers and hedging: Poor said power supply and transmission together account for roughly three-fifths of a typical Vermont retail rate, with transmission alone about 17% of the total. He described utilities’ long-term contracts and ownership stakes — some lasting decades — as the primary reason Vermont’s retail rates were “more stable and lower than other New England states” over the last several years.

- Hedging and market exposure: The department estimates utilities are generally 85–95% hedged through a mix of long-term contracts and owned units, which moderates exposure to short-term price swings when contracts expire and must be replaced in the market.

- Regional reliability costs: Poor noted examples of region-wide reliability interventions that raised costs across New England, including an ISO New England out-of-market contract to keep the Mystic generating station in Connecticut online. That contract cost the region “hundreds of millions of dollars,” and Poor said Vermont Electric Co-op’s share of the Mystic payment was “almost a million dollars.”

- Ownership and incentives for capital investment: Poor said Green Mountain Power is the only investor-owned utility in Vermont; capital spending on infrastructure (for example, substations or undergrounding lines) is the mechanism by which an investor-owned utility recovers investment and earns a return. He described the state’s regulatory review — including multiyear rate plans approved by the Public Utility Commission — as the forum for testing whether capital investments are prudent and whether rate mechanisms align incentives with reliability and resilience outcomes.

- Transmission cost trend: The presentation highlighted rising regional transmission costs and noted Vermont pays about 4% of New England transmission charges; Poor said those network costs are increasing and represent a meaningful portion of future rate pressure. He said some forecasts show transmission costs increasing roughly 4–5% per year.

- Renewable Energy Standard (RES) and RECs: The department is required by statute to estimate the RES cost over the next 10 years; Poor said the modeled effect of the RES equates to roughly 6–8% of rates on average. He explained how renewable energy certificates (RECs) function as the compliance attribute for the RES and that utilities sometimes sell or bank RECs, which affects each utility’s reported system mix. After REC disposition, he said Vermont’s system was roughly 90% carbon free in 2023 by attributes (about 91% carbon free by entitlement before disposition). Poor also described REC market prices for new renewable generation at roughly $34–$40 per megawatt-hour in recent years, while noting those values have been more volatile in the past.

- Contract expirations and future resource need: Poor identified two contractual dates that could reduce existing entitlements if not renewed or replaced: a Seabrook nuclear contract through about 2034 and a Hydro‑Québec contract ending in 2035. He said the state’s integrated resource planning and upcoming procurement decisions will be important to secure supply once those contracts expire.

- Electrification and heat pumps: Poor presented a cost illustration for cold‑climate heat pumps that excluded equipment and installation costs and showed that electricity rates materially affect the economics of electrifying home heating. He said the department’s preliminary usage study suggests typical heat‑pump displacement of existing fuel use may be closer to 25% (versus earlier assumptions near 40%), and he emphasized geographic differences: in some service territories a heat pump will lower annual fuel costs, in others it may increase them depending on local electric rates and fuel prices.

What lawmakers asked and next steps

Committee members pressed for more detail on several topics, including transmission-cost drivers, REC price trends, and how the department evaluates capital investments such as distributed battery programs. Poor said more detailed slides and appendix material — including an org chart and generator locations — would be provided in a follow-up session. He also said the department plans a proceeding over roughly the next 12–18 months to better tie utility performance and earnings to reliability and resilience metrics.

No formal committee votes or policy decisions were taken during this session; the presentation concluded with committee agreement to reconvene a second session to cover demand forecasts (heat pumps, electric vehicles) and additional supply details.

Ending

The department will return for part two of the briefing to present demand forecasts and additional data on REC tiers and cost drivers. Meanwhile, the committee said it will continue to monitor transmission cost growth, REC market developments, and the timing of major contract expirations that could affect Vermont retail rates through the 2030s.