CMP power corridor begins delivering power to the grid

The New England Clean Energy Connect (Central Maine Power) 145-mile transmission corridor began delivering power from Hydro-Québec to the New England grid on Jan. 16, with expected capacity of 1,200 MW and a 1.2-mile 345 kV AC tie into the Larrabee Road substation in Lewiston. Avangrid says the project—with approximately $1.6 billion in capital expenditures—is backed by a 40-year Transmission Service Agreement with Hydro-Québec and 20-year contracts with Massachusetts utilities and Hydro-Québec, providing inflation-protected revenue and an estimated ~$23 million in year-one property tax benefits to host communities; construction resumed in Aug. 2023 after legal and referendum challenges and a federal judge declined to revoke Army Corps permits in April 2025.

Analysis

Market structure: The NECEC adds ~1,200 MW of low‑marginal‑cost hydro into ISO‑NE, immediately pressuring winter peak and energy nodal prices in Northern/New England hubs by an estimated $10–30/MWh on stressed hours and compressing spark spreads for gas peakers. Regulated/transmission owners (Avangrid/AGR, and counterpart Massachusetts utilities like Eversource/ES, National Grid/NGG) gain stable, inflation‑linked cashflows; merchant gas generators and short‑duration batteries/peakers lose pricing power and capacity revenue.

Risk assessment: Key tail risks are regulatory reversal or Hydro‑Québec curtailment (drought/hydro constraints) and transmission failure; a prolonged outage or legal setback could remove ~1,200 MW and spike regional prices >50% in stress hours. Immediate: volatility in ISO‑NE day‑ahead prices (days–weeks); short‑term: capacity auctions and utility filings reprice (months); long‑term: capacity market clearing prices and generator fleet economics shift over years, potentially lowering capacity prices 10–30%.

Trade implications: Favor regulated utilities and transmission credit exposure; underweight merchant generators and regional gas basis. Use equity + credit long in AGR/ES/NGG and short NRG (merchant); implement options to express directional and volatility views (LEAP calls on AGR, put spreads on NRG). Bond markets: buy IG utility paper if spread >150bp to Treasuries for 3–7y tenor.

Contrarian/second‑order: Consensus underestimates contract counterparty and water‑risk: Hydro drought or political pressure in Quebec could flip the narrative quickly; capacity market repricing may produce stranded‑asset risk for merchant developers, accelerating M&A/asset sales. Historical parallel: large interconnects (e.g., PJM import ramps) reprice local generators for a decade, not months—position sizing must assume multi‑year repricing.

Key Decisions for Investors

• Establish a 2–3% long position in Avangrid (AGR) equity within 2–6 weeks, target +20% upside over 12 months, stop‑loss at -10%; rationale: 40‑year TSO + inflation‑linked cashflows de‑risk earnings and should compress equity beta.
• Initiate a 2% long in Eversource (ES) or National Grid (NGG) (choose based on relative valuation) and buy 3–7y IG utility bonds if spread to Treasuries exceeds 150bp; exit or trim if spreads tighten <100bp or stock rises >25%.
• Open a pair trade: long AGR (1.5%) / short NRG (1.5%) — target relative return +15% in 6–12 months; hedge directional market beta with index futures. Place short stop on NRG at +8% and long stop on AGR at -10%.
• Deploy options: buy 9–15 month LEAP calls on AGR ~10–15% OTM (allocate 0.5% capital) and buy a 3–6 month put spread on NRG (sell higher strike) to capitalize on near‑term capacity/energy reprice and volatile merchant earnings.
• Monitor legal/regulatory catalysts closely: if any new federal/state court filings or Hydro‑Québec supply notices appear within 30–60 days, reduce AGR/ES/NGG exposure by 25% and tighten stops; if no adverse developments after 90 days, consider scaling longs +50%.