Peak power demand in the Pacific Northwest is shifting to a pattern in which regional load will no longer peak in the winter months, according to experts analyzing the data.
One "significant preliminary" conclusion is an end to winter-peaking when looking at historical temperatures and load as compared with a combination of three climate change modeling scenarios run by Northwest Power and Conservation Council analysts, according to Portland, Oregon-based consulting firm Energy GPS.
Energy GPS explained its conclusion in an Oct. 9 research note based on data in modeling scenarios conducted by NWPCC for its Resource Adequacy Advisory Committee Technical Committee, presented at its Oct. 6 meeting.
The council is in the process of preparing its 2021 Northwest Power Plan and is looking at resource adequacy for 2025 and 2027.
There is a projected 0.3-percent increase in load in 2024, NWPCC said. Following that, there is "a little bit of load growth and some resource changes." Between 2024 and 2025, some expected net changes will include the addition of 2,144 MW of wind, much of it in Montana and Wyoming; an additional 508 MW of solar; and a loss of 354 MW of thermal generation with 249 MW of independent power producer resources added. NWPCC staff member John Fazio said the latter changes are accounting-based, namely, in which bucket generation from the Hermiston natural gas-fired power plant is counted. It was reclassified from thermal to IPP.
Assessments are typically conducted every five years, but Fazio said that by 2027, the region is expected to lose another 500 MW of generation capacity and that beyond that point, any analysis becomes "too speculative," particularly in light of coal generation retirements. Roughly 4,800 MW of coal plant capacity is forecast to retire between 2018 and 2028.
Fazio showed a chart of the expected change in 2025 average monthly peak loads based on forecast climatic temperatures relative to forecast loads and compared with loads and temperatures recorded between 1948 and 2017. This is the first time that the NWPCC is including climate change data in its planning assessment.
"The result of the explicit recognition of climate change is a decrease of the winter peak of roughly 4,000 MW and an increase in the summer of approximately 2,500 MW," Energy GPS analysts state in their research note. "The combination of the two effects moves the expected peak of the region to the summer season."
The Energy GPS analysts add that the winter peak has been dominant "since the creation of an interconnected power grid in the PNW . . . Although the region is comparatively mild given its latitude, winter peaks are created in the region as a result of multi-day cold spells and the prevalence of electric heating loads from resistance heating, including resistance heating backups in heat pumps. The winter peak of the PNW was seen as complementary to the summer peak of California and the Desert Southwest. The large interties to California and the [Desert Southwest] were justified [based] on this interregional diversity."
When asked about the changes in load peaks, Fazio said that rather than having a single point in the year when the region has to worry about resource adequacy, it may now have "two or three points in the year when we have to seriously look at RA," perhaps March and a couple of summer months.
When possible climate-change-triggered conditions such as increased rainfall and increased use of appliances such as air conditioners are introduced, the complexion of the Pacific Northwest power market changes significantly, according to Energy GPS. "What could this mean for power markets? All things being equal, this should make the price of PNW power in the summer more dear relative to winter."
In comparing the forward price curves for the Mid-Columbia hub to those of South of Path 15, the analysts note that it is possible that these already reflect climate change, but the quarter-to-quarter forward prices could flatten. No specific price examples were provided.
Two key factors the NWPCC said it uses for assessing resource adequacy are loads and river changes. From a pool of 19 possible datasets, they chose three that they expect will provide the council with "the full range of climate change possibility . . . a good representation of what we'd expect in the future." Fazio said in running different climate-change-based modeling scenarios, some years had colder temperatures than have been seen in history. Generally, analysts expect that if the temperatures are warmer, there will be less snowpack and smaller flows for hydro; and in the summer, higher temperatures and higher loads from increased air-conditioner usage.
The key metric used in decisions about procurement is loss-of-load probability. There is a 15.3-percent LOLP in the historical weather and hydro conditions model. This is 16.5 percent in the climate change scenario.
The council aims to have a maximum 5-percent LOLP.
"Under climate change, all the problems occur in the summer," Fazio said. "So we're shifting from a split need using historical data to a summer resource need. That's important and will play a role in the resources we choose to solve the problem."
In most of the NWPCC assessments, there is a clear need for more generation. The council looked at what might happen if a summer spot power market is added. The model assumed that there would be 1,250 MW of energy in that market, except during the hours ending 17 through 22, which is the California peak. Throughout those hours, Fazio said, "We assume California is buying up everything during that period."
The market addition "helps quite a bit," Fazio said. The models show the average LOLP shrinks to 4.4 percent. "Would that market really be there? There's a lot of apprehension about whether that market would be there." The topic has been a point of debate for the last 20 years, he said. Adding or using such a market "is a policy call."
Fazio explained that in modeling, analysts are "not trying to eliminate the worst case . . . We plan for 5 percent LOLP. Capacity need is nonlinear, so we can't take a straight-up average."
One attendee at the NWPCC meeting said he would like to see other potentially useful data included to better assess imports—particularly winter imports—including committed new resources such as batteries, solar hybrid generation and advanced energy efficiency.
These are preliminary studies subject to change, Fazio said. The council is working on refining the existing studies and determining what additional models it might need. Its analysts are looking for a range of data values to share and to inform future decision-making, not a single value.
"We have to plan accordingly. That's how the power plan works," he said. "It's based on future uncertainties. And building the most robust strategy to minimize the potential for having inadequate supplies in the future."