State modeling shows renewable energy standard raises ratepayer costs while producing larger societal climate benefits

TJ Poor, director of Regulated Utility Planning at the Vermont Department of Public Service, told the House Energy & Digital Infrastructure Committee on Wednesday that modeling of the state's renewable energy standard (RES) shows appreciable rate impacts for Vermont ratepayers while producing larger monetized societal benefits when the social cost of carbon is included.

"In every scenario, the benefits were greater than the cost in the societal perspective when we look at it societally," Poor said, summarizing results from a stakeholder-vetted modeling effort the department contracted with Sustainable Energy Advantage.

Poor said distribution utilities reported RES program costs rising from roughly $5 million in 2017 (when requirements were low) to about $32 million in 2023. Department modeling asked the statutory question of RES costs through 2034 and produced a set of scenarios showing a 6'to'8% annual-average rate impact on Vermont customers in many modeled pathways. Poor said spikes in modeled cost around 2030 and 2032 reflect stepped increases in statutory requirements, including a point where a 100% regional-tier requirement would take effect.

The presentation separated ratepayer impacts from societal benefits. Poor explained that the model monetized greenhouse-gas reductions using a social cost-of-carbon framework: earlier Vermont practice used a fixed $100-per-ton proxy and later moved to a higher series (the state's climate council and EPA inputs); Poor said the updated stream of values equates to roughly $200 per ton in current estimates, but he noted the metric can change with federal assumptions.

When the avoided tons of carbon are multiplied by a social-cost value, Poor said the RES's estimated societal benefits can be substantially larger than the program's direct costs. He also pointed to other modeled benefits such as price suppression in the regional wholesale market, avoided distribution losses and reduced capacity needs. Poor cautioned that most price suppression accrues regionally via ISO New England rather than directly to Vermont ratepayers and that utilities are substantially hedged, which reduces how much local customers capture that value.

Poor described modeling assumptions and caveats: the analysis used multiple scenarios (none precisely matched legislation as enacted), it assumed no required infrastructure upgrades to support some load-side electrification in certain scenarios, and it did not assume resilience services from storage unless those services are explicitly managed and compensated. On distributed resources, Poor told the committee Vermont has roughly 375 megawatts of net-metering generation and about 545 megawatts of solar in total; about 74 megawatts of battery storage were operational at the time of the presentation (roughly 9% of Vermont's summer peak), with additional projects permitted or in interconnection queues.

Poor said the department is initiating a resilience proceeding to improve how the state values investments such as undergrounding lines, vegetation management and targeted storage, and to develop methods to measure resilience benefits and costs. He said that work is intended to inform how utilities and regulators weigh investments that reduce outage duration and harden the grid.

Committee members asked technical and policy questions on how the modeling treats contractual entitlements, the effect of hedging on local rate impacts, how long-range plans account for load management and storage, and how the social cost of carbon is constructed. Poor said the modeling was reviewed by a stakeholder advisory group, and that the department will continue to refine questions about valuation of resilience and the role of storage.