Council briefings: NW sets summer record for peak power demand & an update on the Western Resource Adequacy Program

Transmission lines near Boundary Dam on the Pend Oreille River in northeastern Washington state. Boundary Dam supplies about one-third of Seattle's energy needs.

For the second time in 2024, the Pacific Northwest has set a new record for peak seasonal power demand. A heatwave that hit the region in early July sent demand on the grid surging to 33,300 MW, which is slightly higher than the previous summer peak of 33,000 MW set during the June 2021 heat dome. In a cold snap that hit in January 2024, the Northwest set the record for winter peak demand at 35,500 MW.

During the Council's September meeting in Astoria, Ore., Senior Power Analyst Tomás Morrissey reviewed the July heatwave's impact on the power grid, how utilities' demand response programs helped, and key lessons for future power planning work in the Northwest. (Read presentation | watch video)

WRAP moves ahead on new timeline

The Council also listened to a presentation by Ryan Roy, Director of Operations and Technology for the Western Power Pool, on the status of the Western Resource Adequacy Program. (Read presentation | watch video) The Council and WRAP are complementary: the Council develops a long term, 20-year power plan, with recommendations for a six-year resource strategy for the region to ensure adequacy, while the WRAP is focusing on near-team adequacy planning.

Unlike other parts of the U.S., the Northwest doesn't have a Regional Transmission Organization (RTO) or an Independent System Operator (ISO) that does adequacy planning and compliance. Instead, these duties are shared among a mix of entities, including the Council. The WRAP aims to bolster these efforts. It has been in development over the past several years, and is a voluntary program with participation from utilities and energy providers across the Western U.S.

Currently, Bonneville Power Administration and public as well as private utilities in Oregon, Washington, Idaho, and Montana are participating, along with utilities in Wyoming, Utah, Nevada, California, Arizona, New Mexico, and British Columbia. Because electricity demand typically peaks during winter and summer, six to seven months prior to these seasons, WRAP participants engage in planning to ensure they have sufficient resources to meet forecasted demand. The next part of the program occurs during those seasons, when the WRAP will evaluate near-term forecasts for load and resources and identify utilities that may be in surplus or deficit. Utilities that are short can match with utilities showing surplus in hours of highest needs, using existing trading mechanisms in the power system.

Roy told the Council that the WRAP is extending its transition phase so that it'll occur between June 2025 and March 2029, while the program is still in development. The transition to the full binding program phases in compliance obligations and penalty charges over time. WRAP participants are targeting 2027 for achieving critical mass and deciding to move forward with the full, binding program. In the transition period, Roy said WRAP has calculated 500 MW would be available to share among subregions, benefiting the Northwest in winter and the southwest in summer.

Reserves are a key part of the 2021 Power Plan. A successful launch of the WRAP as well as day-ahead markets will likely provide signals for sufficient reserves in the long-term. Near-term, utilities are using the existing system more conservatively, and relying on the market. The Council is tracking and evaluating progress on balancing reserves through its 2021 Power Plan Mid-Term Assessment.

How the Northwest grid navigated July's heatwave

Temperatures began warming over the Fourth of July holiday weekend and peaked on July 9. That day, it hit 104 degrees F in Portland, 108 in Boise, 104 in Spokane, and 101 in Helena. July 9 also had the highest load on the grid, and Bonneville Power Administration hit a record high for peak demand in its balancing authority that day, with 9,223 MW.

While the 2021 heat dome had even higher temperatures in the Northwest - it reached 116 degrees in Portland - 2024 had slightly higher energy use. Morrissey said that could likely be attributed to increased use of air conditioning in parts of the region that historically didn't need space cooling in summer months, like western Oregon and western Washington, and increased load from data centers and the tech sector in the Northwest.

Still, utilities and energy providers were able to navigate the heatwave successfully, and Morrissey credited demand response programs and the work to acquire cost-effective energy efficiency as helping. For example, Portland General Electric's demand response program was able to shift over 200 MW of demand to off-peak hours on July 8 and July 9.

Demand response programs are also a vital component of the 2021 Power Plan, which identified roughly 720 MW of potential for low-cost DR products that can be regularly deployed with minimal or no impact on customers. Two possibilities include demand voltage regulation and time of use rates, although more options exist. The Council encourages Northwest utilities to explore demand response options and the benefits they deliver in their service territories as well as to the region overall.

Morrissey contrasted the power system's experience during the July heatwave with what occurred during the January winter storm. Power prices from wholesale market purchases were markedly lower in the summer, peaking at roughly $140/MWh. In January, when temperatures plunged to -12F in Spokane, -24F in the surrounding region, and down to -36F in Helena, wholesale prices for power sent to the Northwest exceeded $1,000/MWh.

During that winter storm, some Northwest utilities had to navigate disruptions in natural gas and renewable energy supplies. The AC-DC intertie, which connects the Northwest power grid to California and the Southwest, also experienced issues. The DC intertie was down for maintenance and under a forced outage, while the AC intertie flowing south-to-north was at its full limit during the event. Utilities were able to avoid widespread outages despite these challenges, but the amount of power imported to the Northwest exceeded market reliance caps and came at much higher costs. Market purchases exceeded 5,000 MW during the storm.

Morrissey also noted that loads behaved differently in the summer, as temperatures dropped at night and cooling demand decreased, while it stayed higher throughout day and night during wintertime because of continuously cold temperatures.

In the summer, even though energy demand hit a peak on July 9, the Northwest didn't import much electricity to get through the heatwave. It also exported electricity to other regions in days preceding and the days following. Morrissey created graphics showing which resources the Northwest grid used in July and in January.

July 2024 heatwave:

This resource stack graphic for the July 2024 heatwave includes portions of utilities' service territories that are outside of the Council's geographic area: PacifiCorp East in Utah and Wyoming as well as Northwestern in eastern Montana.

January 2024 winter storm:

This resource stack graphic from the January 2024 winter storm also includes portions of utilities' service territories that are outside of the Council's geographic area: PacifiCorp East in Wyoming & Utah as well as Northwestern in eastern Montana.Utilities and energy providers in the Northwest imported large amounts of power to meet demand during a winter storm in January 2024, exceeding limits set in market reliance caps.

The Council's power planners are using events like these to test whether the Northwest will have adequate and reliable power supplies in the future. The Council's new Climate and Weather Advisory Committee is helping to inform strategies that will ensure the power system has adequate resources to withstand extreme weather and climate change without experiencing prolonged or significant power outages.

Expected impacts of climate change include more extreme weather events hitting the region, as well as shifts in temperatures and precipitation. For upcoming work on the Ninth Power Plan, which is expected to be adopted in late 2026, the Council will continue to collaborate with the region on capturing climate change and weather impacts in power system modeling.

As the process for developing the ninth plan ramps up in 2024 and 2025, the Council will be inviting and encouraging public participation throughout Oregon, Washington, Idaho, and Montana to inform decisions on the cost-effective strategy that will ensure the Northwest power system remains reliable, affordable, efficient, and has adequate resources to address future heatwaves and winter storms.

Further reading:

• During the Council's March meeting in Portland, Morrissey and James Gall, Electric Integrated Resource Planning Manager for Avista, debriefed the January 2024 winter storm. (Read presentation | watch video)
• Read the Council's 2029 Adequacy Assessment for the Northwest power system.

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