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.

Despite significant declines in grid energy use on an annual basis, hot, humid summer days can still cause high spikes in electricity demand, as shown in this graph.

Fast Stats
  • 7.2 million retail electricity customers; population 14.8 million
  • 116,863 gigawatt-hours (GWh) total annual energy served in 2020 (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
  • 1.1% average annual increase in regional electricity demand forecasted through 2030, factoring in forecasts for energy efficiency, behind-the-meter solar photovoltaics, and electrification of electric vehicles and air-source heat pumps
  • 0.1% average annual decrease in summer peak demand forecasted through 2030 under typical weather conditions, factoring in forecasts for energy efficiency, behind-the-meter solar photovoltaics, and electrification of electric vehicles and air-source heat pumps
Peak demand vs. annual energy use

Steep 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 generating resources power plants.

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 $5.4 billion on EE programs from 2013–2018 and another $11.9 billion between 2021 and 2030). Nearly 3,000 MW of EE measures and 500 MW of demand response can reduce electricity demand from New England’s power grid—that’s 10% 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. New England started the decade with 40 MW of behind-the-meter solar photovoltaic (BTM PV) resources. Today, more than 209,000 installations span the six states, with a combined nameplate generating capability of approximately 4,000 MW. The region is on track to exceed 10,000 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 usage and peak demand will increase slightly in New England over the 10-year period. The primary factors for this increase are the additional energy and loads resulting from the new electrification forecast for electric vehicles (EVs) and air-source heat pumps (ASHPs). 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 the EV/ASHP 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.

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

  • Overall electricity use in New England is expected to grow 1.6% annually over the 10-year period, from the expected 140,836 gigawatt-hours (GWh) this year to 165,116 GWh in 2030
  • Peak demand under typical summer peak weather conditions (the “50/50” forecast) is expected to rise annually at a rate of 0.71%, from 28,324 megawatts (MW) this year to 30,177 MW in summer 2030 (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 30,225 MW in 2021 and 32,197 MW in 2030
  • Winter peak demand under typical winter peak weather conditions (the “50/50” forecast) is expected to rise by an average 1.34% annually, from 22,214 MW in 2021 to 25,041 MW in 2030
  • Winter peak demand under below average winter peak weather (the “90/10” forecast) is forecasted to rise annually as well, from 22,853 MW in 2021 to 25,821 MW in 2030

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

  • Overall electricity use is expected to increase, by 1.1% annually, from 121,692 GWh this year to 133,960 GWh in 2030.
    • EE is projected to save the region 15,879 GWh in 2021 and up to 22,423 GWh in 2030
    • BTM PV is projected to reduce grid demand by 3,265 GWh in 2021, rising to about 6,733 GWh in 2030
    • Light-duty EVs are expected to account for 3,554 GWh of grid demand in 2030, while ASHPs are expected to account for 2,526 GWh that year
  • Peak demand under typical summer peak weather conditions is expected to remain flat over the 10-year period, decreasing from 24,810 MW this year to 24,796 MW in 2030.
    • The net forecast includes peak demand reductions of 836 MW this year and rising to 1,087 MW in summer 2030 as a result of behind-the-meter PV
  • Peak demand under above average summer peak weather is expected to remain essentially flat, with a slight annual decline, from 26,711 MW in 2021 to 26,639 MW in 2030
    • Transportation electrification from EVs is forecasted to contribute 675 MW to peak demand in 2030
  • Winter peak demand is forecasted to increase an average of about 0.72% annually under normal conditions, and 0.77% under below average conditions. For normal winter weather, net peak demand is expected to increase from 19,710 MW this year to 21,031 MW in 2030-2031; for below average winter weather, the net peak is forecasted to increase from 20,349 MW this year to 21,811 MW in 2030-2031
    • Transportation electrification from EVs is forecasted to contribute 916 MW to the winter peak in 2030-2031
    • Heating electrification is forecasted to contribute 1,556 MW to the winter peak in 2030-2031

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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