ISO-NE LMP Merchant Curve: New England Power Price Forecasts

Gas-fired generation accounts for roughly 50% of ISO-NE’s installed capacity and a higher share of actual energy output, making it the marginal price-setting resource in the vast majority of hours. New England imports most of its natural gas via interstate pipelines from the mid-Atlantic and Canadian systems, with the Algonquin Gas Transmission and Tennessee Gas Pipeline systems serving as the primary supply routes into the region. These pipelines were built to a capacity that is insufficient during extreme cold events when residential and commercial heating demand surges simultaneously with power generation fuel demand. When pipeline throughput is constrained, the spot price at the Algonquin Citygate delivery point disconnects sharply from the Henry Hub benchmark, sometimes reaching multiples of the hub price during the most severe events. Gas generators facing high spot fuel costs offer into the ISO-NE day-ahead and real-time markets at elevated prices, setting the system LMP at levels that can reach hundreds of dollars per megawatt-hour during the most acute events. New England’s limited cross-border electricity interconnection also limits the ability to import power from neighboring markets as a substitute, amplifying the price response. This dynamic is the primary reason why ISO-NE historically has among the highest average winter power prices of any organized market in the United States.

Massachusetts and Connecticut have contracted over 6 GW of offshore wind capacity, with projects including Vineyard Wind and Revolution Wind expected to deliver into SEMA and CT zones beginning around 2027. The structural effect on ISO-NE power prices will unfold over multiple years as successive tranches of offshore wind enter service. The primary near-term effect will be suppression of on-peak summer prices in southern zones, as offshore wind output correlates with high summer afternoon demand. The medium-term effect will be displacement of some gas-fired generation, reducing the frequency with which gas price spikes translate directly into power price spikes. However, offshore wind does not solve the winter gas constraint problem: offshore wind output in New England peaks in winter but the critical pipeline constraint events are driven by overnight heating demand during cold snaps, and the coincidence of peak offshore wind with peak winter heating demand is imperfect. The longer-term trajectory depends on whether storage procurements, demand response, and additional interconnection to Quebec hydro develop alongside offshore wind to provide a complete winter reliability solution. Noreva models a range of build-out scenarios to capture the timeline uncertainty and the conditional price impact in each season and load period.

NEMA, or Northeastern Massachusetts, is ISO-NE Zone H and encompasses the Greater Boston metropolitan area and the surrounding northeastern Massachusetts load corridor. It is the highest load-density zone in the ISO and faces binding transmission constraints on the import paths bringing power from western Massachusetts and Connecticut into the Boston area. When load in the NEMA zone exceeds what can be imported across the constrained transmission interfaces, the ISO must dispatch in-zone generation to maintain reliability, and this in-zone generation typically operates at higher marginal cost than the system average, setting the NEMA zonal LMP at a premium above the ISO-NE system LMP. The NEMA premium is not constant: it widens during high-load summer days and periods of system stress, and narrows during moderate conditions when import capacity is not binding. For asset owners and buyers in the Boston area, the NEMA premium is a material consideration in both revenue forecasting and power procurement cost analysis. Offshore wind projects delivering into the NEMA zone will partially relieve the congestion premium over time, though the transmission constraints must be explicitly addressed through grid upgrades for the full benefit to be realized.

Noreva’s ISO-NE winter scarcity modeling uses a stochastic approach rather than a single deterministic forecast path. The model draws on historical distributions of cold-snap frequency (measured in heating degree days per winter), Algonquin Citygate basis above Henry Hub during constrained periods, dual-fuel switching rates in the gas-fired fleet, and available firm pipeline capacity relative to demand at various temperature scenarios. These inputs generate a conditional distribution of winter LMP outcomes rather than a single average price. For project finance and asset valuation purposes, this probabilistic approach allows Noreva to produce P50, P75, and P90 winter revenue estimates that accurately reflect the fat-tailed nature of ISO-NE winter price risk. Single-path forecasts using average or expected-value gas prices systematically underestimate winter average power prices because they cannot capture the asymmetric impact of tail events: a single extreme cold-snap week can contribute disproportionately to the annual average LMP. The stochastic framework also enables scenario analysis around structural changes such as new pipeline additions, LNG facility changes, or significant demand response program expansions that alter the effective pipeline constraint severity. See our related analysis at ISO-NE Capacity Market.