Draft load forecast indicates energy usage and peak demand will decline slightly over the next 10 years
Thursday, March 29, 2018 at 11:47AM
ISO New England in Industry News & Developments, demand resources, energy efficiency, fcm, forecast

ISO New England develops an annual projection of how much electricity the region will use every year for the next 10 years, as well as how high demand will peak during each of those years. The 10-year forecast is a key system planning tool, helping ensure New England has an adequate supply of resources to meet future demand and a transmission system that can do the job of carrying power to residents and businesses.

The draft long-term forecast for 2018 to 2027 projects that energy usage and peak demand will decline slightly in New England over the 10-year period. The primary factors are continuing installation of energy-efficiency measures and behind-the-meter photovoltaic (BTM PV) arrays throughout the region.

The long-term forecast for electricity use is developed each year using state and regional economic forecasts, 40 years of weather history in New England, federal appliance efficiency standards, the results of both the ISO’s energy-efficiency (EE) forecast and solar photovoltaic (PV) forecast, and other factors. The ISO develops a gross load forecast that reflects what load would be without reductions from EE and BTM PV, and then applies the EE and BTM PV forecasts to develop a net load forecast, which reflects load actually observed on the system. The draft EE forecast is still being finalized.

The finalized long-term load forecast, including the final EE and PV forecasts, will be part of the annual Forecast Report of Capacity, Energy, Loads, and Transmission (CELT) which is published May 1. The CELT report is a primary source for assumptions used in ISO system planning and reliability studies. Additional information related to the annual forecast is published on ISO’s website.

The draft 2018 gross forecast—without the effects of EE and PV—projects a compound annual growth rate (CAGR) of about 0.9% in total energy usage in New England, from 142,488 gigawatt-hours (GWh) this year to 154,364 GWh in 2027. When the preliminary EE and PV forecast estimates are taken into account, net energy usage is expected to drop by a CAGR of -0.9%, from 124,252 GWh this year to 114,981 GWh in 2027. The draft EE forecast projects annual energy savings that will average about 2,059 GWh each year through 2027.

Peak gross demand, a measure of the highest amount of electricity used in a single hour in New England, is projected in the draft gross forecast to rise by a CAGR of 0.8%, from 29,060 MW this year to an estimated 31,192 MW in 2027 with normal summer weather conditions. However, when the demand-reducing effects of PV and EE are taken into account, the draft net forecast projects that peak demand will fall slightly over the 10-year period, by about -0.4% annually, from 25,729 MW to 24,912 MW. If extreme summer weather were to occur, preliminary numbers indicate net peak demand could decline slightly, by an average of about 0.2% annually, from 28,120 MW to 27,548 MW. The draft EE forecast projects that EE will shave about 281 MW, on average, off summer peak demand each year of the forecast period. The net forecast also projects slightly declining peak demand in extreme winter conditions, from 21,057 MW in 2018 to 19,833 MW in 2027, for a CAGR of -0.7%.

The PV nameplate forecast estimates the level of BTM PV capacity that will be added each year through 2027. (Nameplate refers to the maximum amount of energy a resource is capable of producing.) The draft nameplate forecast projects about 3,442 MW of cumulative BTM PV will be added over the next 10 years, for a total of about 5,833 MW installed in New England in 2027. The final published PV forecast will also include estimates of energy and peak demand reductions for the entire New England system, each state, and Regional System Plan subareas.

Draft
Long-term load forecast 2018-2027
(compound annual
growth rate)

Gross Forecast
Net Forecast
(minus load reductions
from EE & PV)
Annual Energy Usage 0.9%

-0.9%

Peak Demand (extreme weather)

0.8% -0.4%

Draft Data: Annual Energy Use With and Without PV and EE Savings

Draft Data: Summer Peak Demand With and Without PV and EE Savings, 50/50 Forecast

Draft Data: Summer Peak Demand With and Without PV and EE Savings, 90/10 Forecast

2017 Energy and Demand

Looking back at 2017, total annual weather-normalized electric energy usage declined by 2.6%, to 120,668 GWh, compared to a 2016 weather-normalized value of 123,953 GWh. Those figures are based on energy use adjusted for variations in weather. Actual energy usage numbers show a 2.6% decline, from 124,425 GWh in 2016 to 121,134 GWh last year.

In 2017, demand peaked at 23,968 MW on June 13, 2017, during the hour from 4 to 5 p.m. Without the demand reductions from the region’s active demand-side resources, energy-efficiency measures, and behind-the-meter solar arrays, the peak would have been 27,014 MW. A summer peak in June is unusual; summer demand more typically peaks in July or August but weather during these months was relatively mild in 2017. Had the heat and humidity of June 13 occurred in July or August, the ISO estimates that actual peak demand would have been about 2,050 higher.

During winter 2017/2018, demand peaked at 20,599 MW during the hour from 5 to 6 p.m. on January 5. Without active demand-response resources and energy-efficiency measures, the peak would have been 23,528 MW. Behind-the-meter solar does not contribute to reducing winter peak load because demand peaks in winter after the sun has set.

Article originally appeared on ISO Newswire (http://isonewswire.com/).
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