About Us > Key Grid and Market Stats

A Summer Peaking System

New England typically reaches its highest demand for electricity during the summer when warmer weather leads to increased use of energy-intensive air conditioning.

  • Peak demand on a normal summer day has typically ranged from 17,500 MW to 22,000 MW. Summer peaks on the hottest and most humid days have averaged roughly 25,600 MW since 2000. Read about how the ISO prepares for summer operations.
  • In winter, peak demand on a normal day has typically ranged from approximately 18,000 MW to 19,700 MW. Winter peaks on the coldest days have averaged roughly 21,000 MW since 2000. Read about how it can be more challenging to meet the winter peak than summer peak.
  • Typical spring peak demand ranges from 15,000 MW to 16,900 MW; typical fall peak demand ranges from 15,900 MW to 17,300 MW. The peaks can be much higher if summer-like weather creeps into the late spring or early fall periods.

Until 1989, New England was a winter-peaking system, and in the early 1990s, the region had nearly twin winter and summer peaks. Growing use of air conditioning and a decline in electric heating contributed to this dramatic change.

New England’s Electricity Use

The region’s millions of households and businesses create the demand for electricity on the power grid, which must be produced the instant it is needed because electricity cannot easily be stored in large quantities. (Learn how ISO New England runs the power grid.)

Top 10 Demand Days

Peak demand is the highest amount of electricity used in a single hour, and the ISO must ensure that the region has sufficient power resources to meet the peak. The chart below shows the days with the highest peak demand recorded in New England since the ISO began managing the power grid in 1997. The highest peaks typically occur during the work week in summer. Note that as demand for electricity from the regional grid declines, these records are harder to break. Nevertheless, high spikes in demand still occur, and New England’s power system must remain prepared to meet those peaks even if they aren’t historically high.

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Data for the top ten demand days comes from the Daily Summary of Hourly Data Report, available on the Zonal Information page. The daily peak load for the regional system is included in the “System_Peak” column on the “ISONE CA” worksheet. The “DT” (date type) column represents the day of the week, where Monday is 1 and Sunday is 7.

Annual energy use is lower now than it was in the early 2000s. But as shown in the chart below, levels of peak demand—the highest amount of electricity used in a single hour—have not fallen. New England’s power system is planned and operated to serve demand during these peak hours, which still see spikes on hot, humid summer days, even if annual use is not historically high.

Fast Stats
  • 7.5 million retail electricity customers; population 15.1 million
  • 118,878 gigawatt-hours (GWh) total annual energy served in 2022 (subject to adjustments)
  • 136,355 GWh all-time highest total annual energy served, set in 2005
  • 28,130 megawatts (MW) all-time summer peak demand, set on August 2, 2006
  • 22,818 MW all-time winter peak demand, set on January 15, 2004
  • 2.3% average annual increase in regional electricity demand forecast through 2033, factoring in forecasts for energy efficiency, behind-the-meter photovoltaics, and electrification of transportation and heating
  • 1.1% average annual increase in summer peak demand forecast through 2032 under typical weather conditions, factoring in forecasts for energy efficiency, behind-the-meter photovoltaics, and electrification of transportation and heating
Peak demand vs. annual energy use

Growth of Energy Efficiency and Solar Power Is Driving Down Grid Electricity Use

Today, 20% of total system capacity is provided by distributed energy resources that reduce demand from the grid and the need to turn on or build power plants and other generating resources.

State policies and wholesale market revenues are stimulating the rapid growth of energy efficiency (EE) and demand response. New England states invest billions of dollars on EE programs that promote the use of energy-efficient appliances and lighting and advanced cooling and heating technologies (nearly $6.9 billion on EE programs from 2015–2021 and another $10.8 billion between 2023 and 2032). Nearly 4,000 MW of demand capacity resources (including demand response, energy efficiency measures, and distributed generation) reduce electricity demand from New England’s power grid—that’s more than 11% of system capacity acquired in the Forward Capacity Auction. And New England is first in the nation to innovate and enable demand resources to fully participate in the energy and reserve markets.

Providing incentives for local/residential solar power is also a top priority for New England policymakers, with the states spending billions of dollars on making solar energy affordable for consumers. In 2010, New England had about 40 MW of behind-the-meter solar photovoltaic (BTM PV) resources. Today, the region's BTM PV installations have a combined nameplate generating capability of more than 3,000 MW. The region is on track to exceed 6,000 MW over the next decade. Though these resources don’t participate in the markets, the markets are flexible to changes in grid demand, so grid electricity is not over produced—or over purchased. See how hourly load varies by season and with the impact of solar power.

ISO New England’s 10-Year Electricity Demand Forecast

The ISO forecasts that both energy use and peak demand will increase in New England over the next 10 years. The primary factors for this increase are the additional energy and loads resulting from the electrification of the transportation and heating sectors. The ISO develops the gross long-term forecast for electricity demand using state and regional economic forecasts, years of weather history in New England, and electrification forecasts. Results of both the ISO’s energy efficiency (EE) forecast and solar photovoltaic (PV) forecast are applied to the gross forecast to develop a net long-term forecast. Since EE and PV reduce the amount of electricity consumers draw from the bulk power system, the net forecast represents actual grid demand.

Gross forecast, not including EE, behind-the-meter PV:

  • Overall electricity use in New England is expected to grow 2.4% annually over the 10-year period, from the expected 138,081 gigawatt-hours (GWh) in 2023 to 171,050 GWh in 2032.
  • Peak demand under typical summer peak weather conditions (the “50/50” forecast) is expected to rise annually at a rate of 1.2%, from 27,556 megawatts (MW) in 2023 to 30,599 MW in summer 2032 (peak demand is a measure of the highest amount of electricity used in a single hour).
  • Peak demand under above-average summer peak weather (the “90/10” forecast), such as an extended heat wave, pushes the gross forecast for peak demand up to 29,372 MW in 2023 and 32,526 MW in 2032.
  • Winter peak demand under typical winter peak weather conditions (the “50/50” forecast) is expected to rise by an average 3.0% annually, from 22,053 MW in winter 2023-2024 to 28,810 MW in winter 2032-2033.
  • Winter peak demand under below-average winter peak weather (the “90/10” forecast) is forecasted to rise annually as well, from 22,816 MW in in winter 2023-2024 to 30,611 MW in winter 2032-2033.

Net forecast, including latest EE, behind-the-meter PV forecasts:

  • Overall electricity use is expected to increase, by an average of 2.3% annually, from 122,057 GWh in 2023 to 150,073 GWh in 2032.
    • EE is projected to save the region 11,582 GWh in 2023 and 12,810 GWh in 2032.
    • BTM PV is projected to reduce grid demand by 4,442 GWh in 2023, rising to 8,168 GWh in 2032.
    • EVs are expected to account for 13,961 GWh of grid demand in 2032, while heating electrification is expected to account for 7,334 GWh that year.
  • Peak demand under typical summer peak weather conditions is expected to rise annually at a rate of 1.1% over the 10-year period, increasing from 24,605 MW in 2023 to 27,046 MW in 2032.
    • The net forecast includes peak demand reductions of 981 MW in 2023 and rising to 1,117 MW in summer 2032 as a result of behind-the-meter PV.
  • Peak demand under above-average summer peak weather is expected to rise from 26,421 MW in 2023 to 28,974 MW in 2032.
    • Transportation electrification from EVs is forecasted to contribute 2,346 MW to summer peak demand in 2032.
  • Winter peak demand is forecast to increase an average of 3.0% annually under normal conditions. For normal winter weather, net peak demand is expected to increase from 22,053 MW in 2023 to 28,810 MW in 2032-2033; for below-average winter weather, the net peak is forecasted to increase from 22,816 MW in 2023 to 30,611 MW in 2032-2033.
    • Transportation electrification is forecast to contribute 3,420 MW to the winter peak in 2032-2033.
    • Heating electrification is forecasted to contribute 2,965 MW to the winter peak under average weather in 2032-2033.

Projected Annual Energy Use With and Without EE and PV Savings

Projected Summer Peak Demand With and Without EE and Savings

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