The unprecedented heat wave that’s shattered temperature records across the Pacific Northwest this week has forced utilities to beg customers to reduce their energy use. President Joe Biden has promised federal action to assist states and utilities with managing heat-stressed power grids and the threat of powerline-sparked wildfires.
It’s also reinvigorating interest in expanding a resource that could help the region manage heat-driven grid peaks and meet expanding carbon-reduction goals: controlling electricity use by appliances, heaters, air conditioners and other loads to balance the grid.
Hydropower has provided the Pacific Northwest with a cheap, reliable and carbon-free source of power for generations. As a result, the region has had little need for demand response — utility programs or energy markets that reward customers for reducing electricity use during times of peak grid demand — compared to other parts of the country.
But this week’s high-pressure atmospheric “heat dome,” which drove temperatures that melted power cables in Portland, Oregon’s metro transit system and buckled asphalt roadways in Washington state, indicates that climate change is altering the equation for the region’s grid reliability.
Avista, the utility serving eastern Washington, northern Idaho and northeastern Oregon, was forced to cut power to thousands of customers to protect its grid from heat and record-breaking electricity demand — a miniature version of the rolling blackouts that California experienced last year and is preparing to prevent this summer.
Heat also caused outages for thousands of customers of Oregon utility Portland General Electric, although those were due to overheated circuits and transformers rather than an effort to manage high demand. Still, PGE experienced peak loads of 4,230 megawatts on Sunday and 4,441 MW on Monday, shattering the previous record of 4,073 MW set in 1998 — and that was after it joined other utilities in the region in asking customers to conserve as much energy as possible.
PGE's record peak isn’t just notable for its size, said Peter Holzaepfel, director of utility demand response for Enel X. It’s also “pretty unusual given that it’s traditionally a winter-peaking system” — a major change for the grid reliability challenge faced by the region as a whole.
What’s holding back demand response in the Pacific Northwest
“The Pacific Northwest is kind of an interesting beast when it comes to demand response,” Holzaepfel said. Enel X provides agricultural load controls for Northwestern utility PacifiCorp using the water pump and irrigation control technology of M2M Communications, a company that now belongs to Enel X through its 2017 acquisition of EnerNOC. The same technology is used by Idaho Power’s large-scale demand response program, which represents the majority of the roughly 400 megawatts of load-reduction capacity in the region.
But while much of the inland parts of the region are summer-peaking systems, the coastal regions have traditionally seen their grids peak in winter mornings and evenings, due to the high preponderance of electric heating in homes and businesses. That’s a harder peak to reduce with the commercial and industrial loads that Enel X works with, Holzaepfel said.
The Pacific Northwest’s hydropower bounty has similarly reduced the value to be earned from load reduction since “the avoided costs that demand response can deliver have typically been pretty low.” The region also lacks the wholesale energy and capacity market structures that have allowed demand response to flourish in parts of the Eastern U.S., and to a lesser extent in California, he noted.
These factors have constrained demand response in the region, said Tina Jayaweera, power planning resources manager for the Northwest Power and Conservation Council. The group is tasked by federal law with crafting power plans to balance the region’s environmental and energy needs.
The last such power plan in 2016 identified demand response as the least-cost solution for managing the region’s peak demands and suggested that at least 600 megawatts of it should be developed by 2020.
“We did not meet that goal,” Jayaweera said. Most of the region’s utilities have not added significant capacity since then. They have been stymied by a relatively challenging economic case for paying customers to prepare to reduce peaks that may arise only rarely, as well as barriers to being able to easily trade that capacity with other utilities, she said.
The Bonneville Power Administration, the federal operator of most of the region’s hydropower complex and transmission grid network, also hasn’t expanded a relatively small set of demand-side resources it developed in pilot projects over the past decade, she said. That’s despite a set of studies that indicated the region could offset between 15 and 18 percent of its winter and summer peak loads by deploying more than 2 gigawatts of demand response over the next 20 years.
“The central theme is that it’s economics,” Jayaweera said. “It’s hard to determine what is cost-effective.”
How changing energy and climate dynamics could bolster demand-side resources
But there’s quite a bit more demand response in the latest plans from the region’s investor-owned utilities, she said. In Washington state, 2019’s Clean Energy Transformation Act coupled carbon-reduction mandates for utilities with requirements to assess the potential for demand response, as well as energy efficiency, to help reduce their power needs.
“A lot of the investor-owned utilities in Washington,” including Puget Sound Energy and Avista, “are seeing a shorter-term need for [demand response]” as a result, Jayaweera said.
Some of the public utility districts that serve much of the state are also ramping up their demand-side efforts, she said. Snohomish County Public Utility District’s FlexEnergy pilot programs offer time-of-use pricing for homes with electric vehicle chargers, as well as free smart thermostats for homes that use electricity for heating.
PacifiCorp recently issued a solicitation for demand response resources in Oregon, Washington and Northern California, Holzaepfel said. That’s part of a much bigger procurement of wind and solar power and energy storage the six-state utility plans to build in the coming years.
In Oregon, which passed its own 100 percent clean power law this year, “Portland General Electric has probably the strongest activity toward developing a demand response portfolio,” Jayaweera said. The utility’s grid modernization plan calls for a major expansion of “distributed flexibility” from homes and businesses using smart thermostats, water heaters and other grid-responsive loads. PGE plans to achieve about 200 megawatts of summertime and 140 megawatts of wintertime load reduction capacity by 2025.
“Demand response programs made a real difference” in managing this week’s heat wave, PGE spokesperson John Farmer said. In the past few years, these programs have grown from pilots to a “much more cost-effective” and “programmatic part of our resource portfolio,” he said. Offerings include peak-time rebates and smart thermostat programs for residential customers, grid-responsive water heaters for multifamily housing, and commercial demand response.
PGE’s latest effort on this front, its Smart Grid Test Bed project, is pairing these grid-responsive devices with behind-the-meter batteries and testing their cost-effectiveness against other options to manage grid reliability. The utility’s aim is to create a “virtual power plant” that can respond as quickly and effectively as natural-gas-fired peaker plants. That could help balance the utility’s system as it strives to reach net-zero carbon emissions by 2040.
The combination of aggressive carbon-reduction goals and proliferation of new grid-balancing technologies makes for the “potential to support distributed energy resources that is much higher than it was even five years ago,” said Matthew Plante, president of demand response provider Voltus.
That kind of flexibility will be important for meeting the region’s future grid needs, Jayaweera said. The Northwest Power and Conservation Council’s next power plan, set for draft release by late summer, “has shown that certain types of [demand response] show a good deal of value,” she said, specifically singling out “those that help meet the morning and evening ramps — the duck curve.”
The term “duck curve” describes the grid conditions that California’s solar-rich grid is facing. Large amounts of solar power flood the system at midday, causing a “belly” in the supply-demand curve, only to fade away in the late afternoons and evenings, leading to a “neck” of rapidly rising demand. As the Pacific Northwest continues to make progress on decarbonization goals, similar patterns can be expected to emerge on its grids as well, she said.
Hydropower does provide some flexibility, she noted — California regularly imports Pacific Northwest power to meet its own summer peaks. But “as more and more renewables come on, there will be more need for some flexible resources, because that will likely be more than what the hydro system can provide on its own,” she said.
That’s backed up by another finding from the council’s upcoming power plan, Jayaweera said. Unlike previous plans that relied on historical data, the new plan analyzes future hydropower capacity based on the expected impacts of climate change on the region’s water supplies.
“Annually, the amount of hydro may not change, but the timing of it may change,” she said. “We may have a lot more rain in the winter and more potential power in the winter. But in the summer, it may be drier. Late summer volume is already low, and it may be lower. The likelihood of inadequacy events in the late summer is growing” as hotter summers drive up electricity demand.
Similar climate-change impacts are stressing water and electricity supplies across the U.S. West, putting utilities and grid planners in the greater region under pressure to find ways to shave and shift peak demand to avoid grid emergencies.
That could open up opportunities for utilities to tap the load flexibility being opened up by technological advances, whether from novel resources including batteries and electric vehicle chargers or from commonplace appliances such as air conditioners and water heaters. As states push policies to shift transportation and building heating from fossil fuels to electricity, being able to adjust these types of devices will become more important as a tool to balance the grid.
Jayaweera noted that Washington and Oregon have passed laws requiring new water heaters to come embedded with technology that allows them to be controlled by utilities or other third parties to reduce power consumption to match grid needs. That’s a potentially valuable resource in a region where about half of all homes use electricity to heat water, she said.
Enel X has enlisted EV chargers as a significant part of its demand response portfolio in California, Holzaepfel noted. In 2019 it launched a program to manage EV charging for Seattle City Light and Puget Sound Energy, although “we’re not at the scale where curtailing those loads is super valuable.”
“But with the proliferation of advanced building management systems, electric vehicle infrastructure, general electrification, battery assets — combined with the broader benefits that demand response can deliver, as highlighted by these extreme conditions — I do think this will create a greater opportunity in the future,” Holzaepfel said.
(Article image courtesy of Elena Kuchko)
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