VELCO warns of transmission overloads within decade unless load management steps are taken

Shana Loisel, representing Vermont Electric Power Company (VELCO), told the Vermont House Energy and Digital Infrastructure Committee on March 20 that VELCO’s long‑range transmission plan shows significant transmission constraints within 10 to 20 years if current trends continue.

“The analysis showed that we we had 75 miles of overloaded transmission lines by 2043, and 19 overloaded transformers,” said Zakiyyah El Amari, senior transmission planning engineer with VELCO, summarizing results of the study. The committee convened to discuss H.278 and to hear VELCO’s update on transmission planning, distributed generation growth and storage implications.

VELCO’s modelling examined two time horizons and multiple scenarios. Under a 20‑year “roadmap” policy case (to 2043) that incorporates expected electrification (electric vehicles and heat pumps) the company found up to 75 miles of overloaded transmission and 19 overloaded transformers. In shorter‑term, 10‑year scenarios the company identified specific problem corridors that could require upgrades as early as 2029–2034 if non‑transmission alternatives are not deployed.

Why this matters: overloaded transmission and sub‑transmission facilities can compromise reliability and trigger the need for major line or transformer projects that require long lead times, regional cost allocations and permitting. VELCO emphasized the planning horizon and the need to compare transmission builds against non‑transmission alternatives (NTAs), such as batteries, demand response or other load controls, to identify lower‑cost solutions.

Key findings and locations

- Northern Vermont: VELCO said a new line between Essex and Williston or an aggregate load reduction of roughly 75 megawatts in that northern area would be needed by 2033 to avoid thermal overloads and potential voltage issues. Zakiyyah El Amari said the 75 MW figure is the 2033 requirement for that area.

- Northwest (Middlebury/West Rutland): VELCO identified an overload on the West Rutland–Middlebury line and recommended rebuilding that line by about 2029, or alternatively achieving a targeted load reduction for the northwest zone.

- Central Vermont: Overloads at several transformers (North Rutland, Otter River and others) could require rebuilding the Coolidge–North Rutland corridor (115 kV) by roughly 2034 unless NTAs are effective.

- Southern Vermont: VELCO identified a need for a new 345 kV line between Vernon and an Eversource interconnection by about 2034 in the transmission solution; without that, loads would need to remain near 2033 levels to avoid the overload.

Distributed generation and daytime minimums

VELCO reported rapid growth in small‑scale distributed solar. Shana Loisel said small‑scale solar (less than 1 MW) already totals about 550 megawatts, and the plan used a 1,300 MW distributed generation target (roughly the state’s projected rooftop/DER build under the policy case) as a stress test. Under that distributed generation projection, VELCO found about 156 miles of overloaded transmission and 10 overloaded transmission transformers at daytime minimum conditions, which it flagged as a separate risk from peak‑hour, winter reliability concerns.

The company also ran an “optimized DER location” scenario, placing distributed resources where the existing transmission capacity could accept them. That exercise produced about 1,053 MW of DER capacity that could be accommodated without system upgrades if deployments are sited and coordinated to avoid constrained corridors.

Non‑transmission alternatives, storage and load control

VELCO repeatedly framed NTAs as the next step. “Our long range transmission plan identifies system deficiencies; the next step is to go through a non‑transmission alternative study that will be led by the distribution utility through the Vermont System Planning Committee process,” Shana Loisel said.

VELCO’s high‑level NTA estimates showed the scale of possible needs: to relieve winter peak transmission constraints the system would need roughly 439 megawatts of aggregated load reduction statewide and about 400 megawatts for summer peaks. Conversely, to absorb daytime excess distributed solar under the 1,300 MW scenario, the system would need roughly 480 megawatts of load‑increase or absorption capacity (for example, batteries operating in charge/absorb mode or increased controllable load).

Zakiyyah El Amari explained that the NTA modelling was technology‑agnostic: “In the model, as long as we have a load reduction, it could come from anything. It could come from an actual generator, could come from battery storage, could be an actual load control.”

Committee members pressed for examples and timing. Several representatives noted that distribution utilities already run demand‑management and EV charging‑management programs and asked how those programs were reflected in VELCO’s baseline. VELCO said it deliberately excluded assumed managed EV charging at the high assumed rates used in VELCO’s 2021 plan because the company lacked statewide, verifiable data demonstrating a particular adoption and control rate. VELCO said the 2024 plan will inform an NTA study that the distribution utilities will lead and that will evaluate concrete stacks of solutions (demand response, batteries, siting of new DERs) and their cost allocation.

Cost allocation and regional context

Committee members asked how much of a transmission project cost would be socialized regionally. VELCO answered that Vermont’s current regional “load ratio” share would be roughly 4 percent for transmission projects designated as regional transmission facilities; the remainder would be allocated across the region through ISO New England and regional planning processes. VELCO emphasized that projects seeking regional funding and regional inclusion must pass ISO‑NE processes and secure regional participants’ buy‑in.

Next steps and committee context

VELCO said its long‑range transmission plan is updated every three years, the Vermont System Planning Committee will begin the NTA work this year, and distribution utilities’ integrated resource plans (IRPs) are an important complementary source of information. VELCO recommended that distribution utilities participate in H.278 hearings because the bill’s data requests and cost‑benefit questions focus on retail utilities’ territory‑level decisions.

Quotes

- “The analysis showed that we we had 75 miles of overloaded transmission lines by 2043, and 19 overloaded transformers,” — Zakiyyah El Amari, senior transmission planning engineer, Vermont Electric Power Company (VELCO).

- “The next step is to go through a non‑transmission alternative study that will be led by the distribution utility through the Vermont System Planning Committee process,” — Shana Loisel, VELCO.

Ending

Committee members said they would also hear from Green Mountain Power and other distribution utilities in subsequent hearings. VELCO recommended coordination through the Vermont System Planning Committee and noted that updated data and expanded managed‑charging pilots could materially change modeled needs in future plan iterations.

(Reporting based solely on VELCO presentation and committee discussion recorded March 20, 2025.)