California may be able to get through the coming summer without facing a repeat of last August’s rolling blackouts — if the weather cooperates.
But if the state faces another regionwide heatwave, it will need to rely on gigawatt-hours' worth of newly installed batteries, a smaller but significant amount of extra natural-gas-fired power plant capacity, and a bigger commitment from customers to curtail electricity use during peak evening hours to ride through the emergency.
This snapshot of summer grid readiness has emerged over the past two weeks from the state agencies tasked with avoiding another round of forced outages like those that left hundreds of thousands of Californians without power during the sweltering evenings of August 14 and 15 last year.
Last week, state grid operator CAISO released a summer reliability assessment that highlighted progress in adding more capacity to the grid, adopting energy market reforms and preparing a combination of emergency conservation measures like those that spared the state from even more outages in August and September.
Because of those steps, the grid operator is “cautiously optimistic that there will be enough electricity to meet demand this summer,” CAISO CEO Elliot Mainzer said in a statement last week. Still, natural threats exacerbated by climate change could overwhelm these preparations, he warned.
Those threats include wildfires that could force the outages of transmission lines carrying power into the state, as well as drought conditions that have left large reservoirs in California this year at 70 percent of normal levels, sapping in-state hydropower capacity.
Most critically, regionwide heat waves like those that struck the Western U.S. last August and September could threaten to once again constrain the out-of-state electricity imports that California relies on, as neighboring grids tap those resources to meet their own peak needs.
“We are in better shape this year than we were in 2020,” said Ed Randolph, deputy executive director for energy and climate policy at the California Public Utilities Commission, during a May 4 briefing on the state’s summer preparations. “However, if there is a repeat of extreme weather events, especially a heat event [that affects the entire Western U.S.], there will still be reliance on contingency measures.”
New resources vs. potential import shortfalls
California’s reliance on imports is a key variable for this summer, as officials from CAISO, the CPUC and the California Energy Commission laid out at the May 4 briefing.
August’s rolling blackouts pushed the CPUC to fast-track utility procurement of grid resources, including contracts for about 560 megawatts of natural gas, biomass and “firm imports” committed to serving the state’s grid. In March, it ordered California’s three big investor-owned utilities, Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric, to expand procurements to meet a heightened level of reserves for this summer, which could yield 1,000 to 1,500 megawatts of additional resources.
California’s investor-owned utilities and community choice aggregators have also contracted for about 1.7 gigawatts of capacity set to be online by August 2021 — almost all of it batteries — to meet the CPUC’s 2019 mandate to secure 3.3 gigawatts of new resources by 2023. Ironically, that 2019 order was aimed at quickly replacing capacity that was slated to be lost due to the retirement of gas-fired power plants along the Southern California coast — plants that had their closure postponed for several years after last summer’s grid crisis.
Of the roughly 4,000 megawatts of new grid resources expected to be added to the grid between last summer and September, about 2,200 megawatts can be relied on during risky times on the grid, Robert Emmert, CAISO’s senior manager of interconnection resources, said at the May 4 briefing.
That’s because the remainder of those new resources are mostly solar power, which fades away in the evening while electricity demand remains high. This dynamic causes the "net peaks" that are the state grid's most potentially perilous period and which triggered last year’s outages.
Of the new “dispatchable” resources available, about 1,400 megawatts consist of batteries that can store excess midday solar power and discharge it during net peaks. “We’re working with operators of those systems as they ramp up” to ensure they’re prepared to serve the grid on critical days, Emmert said.
These batteries are being deployed on a tight deadline, and CAISO's summer assessment warns that not all of these new resources have begun commercial operation. But as of yet, the grid operator isn't anticipating significant delays in getting them up and running.
All of these in-state preparations may not make up for a lack of imported capacity during a heat wave in September, however. The "stack analysis" from CAISO shown below indicates that the gap that could emerge if “economic imports” can't be secured. (Economic imports are power supplies obtained in day-ahead and real-time energy markets, rather than those secured under the state’s resource adequacy capacity contract structure.)
This risk appears to be growing this summer, as grid regions across the Western U.S. are facing potential shortfalls in serving their own peak grid needs. The Western Electricity Coordinating Council, which coordinates 38 different “balancing authorities,” or transmission grid regions, across the Western U.S. and Canada, warned in December that much of the region faces “potential over-reliance on imports to maintain resource adequacy.”
Lana Wong, a senior analyst with the California Energy Commission, reiterated this risk in a presentation on the “worst-of-the-worst scenario,” detailing the hour-by-hour imbalance of grid supply and demand that could occur during a hypothetical heat wave in September, when solar and hydropower resources are expected to be lower than in August.
As the day moves into evening, “resources are insufficient to meet our target system requirements, which would trigger the use of contingencies.” In the worst case, this could include forced outages like those that California underwent last summer, or those which Texas grid operator ERCOT instituted during February’s winter cold snap — a last-resort step meant to prevent an even greater grid collapse that could take days to weeks to restore.
Contingency plans and demand-side options
California does have other contingencies at hand before rolling blackouts, of course—and CAISO, the California Public Utilities Commission and the California Energy Commission have spent much of the past eight months working to expand the roster of options available. One of the most quickly attainable, albeit uncertain, options is convincing electricity customers to cut power use during emergencies —either for free or in exchange for payment.
It was a combination of these "demand-side" efforts, along with emergency measures from California Gov. Gavin Newsom allowing the use of backup generators, microgrids and other resources of last resort, that helped cut roughly 4 gigawatts of load from CAISO’s grid in the days after the August rolling blackouts.
But it also exposed serious conflicts between demand-response providers — companies that enlist customers to reduce loads during grid emergencies in return for payment from utilities — and the CPUC and CAISO rules that determine whether they’ve succeeded in performing that task.
Companies active in California’s demand-response markets collectively claimed hundreds of megawatts' worth of load reduction during the evenings of August 14 and 15, including OhmConnect, Enel X, CPower, Leap and Google Nest. But those load drops are measured by comparing them to the previous 10 days of load at each customer site, including cooler days with lower air-conditioning demand, which led to many demand response providers seeing their efforts discounted, overlooked or left wholly uncompensated.
Both the CEC's and CAISO’s projections for summer 2021 underplay the ability of demand response to reduce load during emergencies, partly due to measurements from last year that indicate many resources didn’t provide as much load reduction as they’d been contracted to deliver.
CAISO’s models presume that about 1,200 megawatts of demand response will be available this summer, which is lower than the estimated 1,600 megawatts available in previous years. At the same time, CAISO is testing different methodologies in hopes of yielding more accurate measurements of the grid value of demand response this summer, Anna McKenna, CAISO vice president of market policy and performance, said during the May 4 event.
Demand-response companies have been pressing the CPUC to alter its regulations to avoid these kinds of problems this summer. But the CPUC’s Ed Randolph said at the May 4 briefing that the commission has postponed taking on these kinds of “longer-term innovations,” opting instead to focus on “what we can do for 2021.”
Solutions for this summer vs. "longer-term innovations"
The CPUC’s March decision on demand-side programs does make several changes to existing demand-response programs. Those include increasing incentives and expanding enrollment options for “base interruptible programs” for commercial, industrial and agricultural customers, which are expected to add from 167 to 367 megawatts of capacity this summer, Randolph said.
The March decision also created an Emergency Load Reduction Program (ELRP) that will offer $1 per kilowatt for load drops, a lucrative incentive corresponding to CAISO’s maximum wholesale energy market price. The ELRP will also allow behind-the-meter batteries and electric vehicles to export power to the grid — a first for demand response in the state.
The CPUC predicts it will be able to get 500 to 720 megawatts of load reduction through ELRP, Randolph said. He also addressed complaints from demand-response companies that the lack of an upfront payment for pre-enrolling in ELRP could limit participation, noting that creating those capacity payment structures would be “a challenge to do in a couple of months.”
But Randolph highlighted the steps being taken independently of CPUC action that are boosting the potential demand-side relief that could help the grid this summer. Marin Clean Energy and East Bay Community Energy, two of the state’s rapidly expanding roster of community choice aggregators, have launched programs that are enlisting customers outside of California’s existing resource adequacy constructs, for example.
The CEC’s Electric Program Investment Charge program has awarded grants for demand-response providers to quickly enlist megawatts for this summer, CEC Executive Director Drew Bohan said. Those include 24 megawatts that demand-response provider and Google Nest partner OhmConnect is enlisting in low-income communities and 18 megawatts being enrolled by agricultural demand response provider Polaris Energy Services. EPIC is also the primary funding source for a number of in-state microgrids that helped provide megawatts' worth of grid relief during last summer’s grid emergencies.
Grid-responsive loads could play a valuable role in balancing California’s grid as it shifts from natural-gas power plants to renewable energy, batteries and other carbon-free resources to reach its decarbonization goals. Studies from Lawrence Berkeley National Laboratory indicate that shifting electric loads to match an increasingly solar-powered grid could greatly reduce the costs of making this shift.
But with the state relying on a rapid response to manage what could be a very tight summer for grid supplies, deeper changes to the state’s demand-side regimes must wait, Randolph said.
“In the long term, there’s great potential there,” he said. “For this summer, we have to chase the megawatts we can get.”
(Article image courtesy of Sterling Davis)
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