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.
  • 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.
  • 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. However, as state policies drive adoption of electric space and water heating systems, New England is expected to again have a winter peaking system by the mid-2030s.

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.

Top 10 Demand Days

Peak demand is the highest amount of electricity used in a single hour, and ISO New England 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, system peaks are less likely to reach record levels. 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—can vary significantly from year to year. 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
  • 114,726 gigawatt-hours (GWh) total annual energy served in 2023 (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
  • 1.8% 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 2033 under typical weather conditions, factoring in forecasts for energy efficiency, behind-the-meter photovoltaics, and electrification of transportation and heating

Annual Energy Use vs. Peak Demand, 2000-2023

Peak demand vs. annual energy use

* Annual energy use, also known as net energy for load (NEL), is the total amount of grid electricity produced by generators in New England and imported from other regions during the year to satisfy all residential, commercial, and industrial customer demand.

** Peak demand represents the sum of metered generation and metered net interchange, less demand from pumped storage units. Starting with full market integration of demand response on June 1, 2018, this total also includes the grossed-up demand response value.

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

Today, about 25% 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 support energy efficiency (EE) and demand response programs. New England states invest billions of dollars in EE programs that promote the use of energy-efficient appliances and lighting and advanced cooling and heating technologies (about $7.8 billion has been budgeted for EE programs from 2015–2022 and another $10.7 billion is expected between 2024 and 2033). Nearly 3,600 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 4,000 MW. The region is on track to exceed 8,000 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.

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.

  • Net electricity use is expected to increase, by an average of 1.8% annually, from 119,179 GWh in 2024 to 140,001 GWh in 2033.
    • EE is projected to save the region 10,618 GWh in 2024 and 11,210 GWh in 2033.
    • BTM PV is projected to reduce grid demand by 5,444 GWh in 2024, rising to 9,975 GWh in 2033.
    • Electric vehicles (EVs) are expected to account for 15,182 GWh of grid demand in 2033, while heating electrification is expected to account for 7,996 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 24,553 MW in 2024 to 27,052 MW in 2033.
    • The net forecast includes peak demand reductions of 1,097 MW in summer 2024 and rising to 1,284 MW in summer 2033 as a result of behind-the-meter PV.
  • Peak demand under above-average summer peak weather is expected to rise from 26,383 MW in 2024 to 29,007 MW in 2033.
    • Transportation electrification from EVs is forecast to contribute 2,391 MW to above-average summer peak demand in 2033.
  • Winter peak demand is forecast to increase an average of 3.1% annually under normal conditions. For normal winter peak weather, net peak demand is expected to increase from 20,308 MW in 2024/2025 to 26,768 MW in 2033/2034; for below-average winter peak weather, the net peak is forecasted to increase from 21,089 MW in 2024/2025 to 28,270 MW in 2033/2034.
    • Transportation electrification is forecast to contribute 3,348 MW to the winter peak under typical conditions in 2033/2034.
    • Heating electrification is forecast to contribute 3,604 MW to the winter peak under average weather in 2033/2034.

Summer vs. Winter 50/50 Net Peak Forecast, 2024–2033

Projected Summer Peak Demand With and Without EE and Savings

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