California’s Latest Demand-Side Emergency Plan Takes Heat from Providers

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“Disappointing.” That’s how a range of clean energy advocates and demand response providers are describing the California Public Utilities Commission’s latest plan to prevent a repeat of the state’s August 2020 rolling blackouts this coming summer.

The proposed decision (PDF) released last week is meant to expand demand-side programs to boost grid reliability. But it doesn’t include any of the proposals that demand response and distributed energy resources providers including Tesla, Ohmconnect, Leap, Enel X, Cpower and Google Nest have testified could expand capacity quickly enough to meet potential shortfalls this year.

The proposal’s primary innovation, an Emergency Load Reduction Program that would pay customers to cut power use during grid emergencies above and beyond their existing demand response commitments, offers lucrative incentives. But it lacks up-front payments and clarity on how it will credit participants, which demand response providers say could limit its effectiveness.

In terms of positive reforms, the proposal is “completely underwhelming for the demand response community and the state,” Jennifer Chamberlin, executive director of market development for demand response provider CPower, said in an email.

Meanwhile, a proposal to increase the reserve margin requirements for the state’s three big investor-owned utilities, Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric, could lead to a rush to secure up to 1,500 megawatts of generation capacity for the coming summer—another step in an emergency response to last summer’s grid emergency that demand response and clean energy groups say favor new generation over demand-side solutions.

And unlike last month’s CPUC order to utilities to boost grid supply under short-term contracts, the new proposal might allow contracts of five years or longer to expand or repower natural gas-fired power plants, which environmental groups say could set California back on its aggressive carbon emissions reduction goals.

“I think this reflects an overall hostility on the part of the Public Utilities Commission staff to demand response, and sort of missing the point about how important load flexibility is now and will be in the future,” V. John White, executive director of the nonprofit Center for Energy Efficiency and Renewable Technologies, said in a Tuesday interview.

California’s share of demand response capacity has shrunk from about 2,000 megawatts to about 1,600 megawatts over the past half decade, even as state regulators have sought to increase its role in balancing an increasingly renewable-powered grid. CPUC and state grid operator CAISO have highlighted problematic data on the effectiveness of demand response during last summer’s grid emergency. But demand response providers say the problems lie in complex and restrictive program rules, rather than in their ability to deliver grid relief.

While the CPUC proceeding launched in November was aimed first and foremost at preventing more rolling blackouts, not boosting demand-side resources, “what disturbs us is this sort of unequal treatment of the demand side versus the gas side,” White said.

What’s in the CPUC’s proposal

The CPUC’s proposal, set for a vote on March 25, does take several steps to expand the role of customer load reductions. It would expand marketing budgets for the Flex Alerts program that asks customers to save energy during grid emergencies, in hopes of tapping more of the approximately 4 gigawatts of voluntary load reduction that helped CAISO weather more grid emergencies in August and September.

The proposal would also increase incentives for so-called “base interruptible programs” that reward commercial, industrial and agricultural customers for cutting electricity use when the grid is facing emergencies, and allow customers to enroll on a month-to-month basis rather than once a year.

It’s also proposing an emergency load reduction program (ELRP), which the CPUC described as “an insurance policy” against future rolling blackouts. The program would offer $1 per kilowatt for load drops, a high value pegged at the maximum wholesale energy market price that CAISO is permitted to charge.

The ELRP will also allow behind-the-meter batteries and electric vehicles to export power to the grid — the first time a demand response program has permitted this key request from energy storage players like Stem and Sunrun.

Ed Smeloff, director of grid integration at advocacy organization Vote Solar, called this the “only glimpse of something positive” out of a proposal he otherwise found “very disappointing.”

But the pilot program’s lack of up-front payments could limit its effectiveness in signing up new customers, demand response companies have told the CPUC. “There’s no way we’re going to be able to bring new resources to the fore and guarantee performance on a voluntary, energy-only basis,” said Marc Monbouquette, Enel North America’s manager of western U.S. regulatory affairs.

Demand response providers also worry that the ELRP may face similar measurement and verification challenges that left many of them unable to earn payment for the hundreds of megawatts of load reduction their customers delivered for hours at a time over days of rising heat during the August 2020 grid emergency.

Ohmconnect has gone public on how these rules forced it to absorb “hundreds of thousands of dollars” of losses per day, as company co-founder and chief risk officer Matt Duesterberg told Greentech Media earlier this month.

What isn’t in the proposal

Monbouquette acknowledged that solving these underlying challenges will take time that the schedule of the CPUC’s emergency reliability efforts may not be able to spare. “We’re trying to counteract a decade or more of really topsy-turvy policymaking with demand response,” as well as make critical changes to the state’s resource adequacy regime for assuring grid reliability.

But he also said Enel X was “disappointed to see that the [proposed decision] largely relied on the utilities’ testimony in coming up with the things it does approve on the demand side,” while the CPUC “largely ignored most of the testimony that came from any non-utility party.”

Multiple demand response groups asked the CPUC to expand the demand response auction mechanism (DRAM) pilot program, the primary route for third parties to aggregate batteries, electric vehicle chargers, smart thermostats and other sources of load flexibility. DRAM has had its budget cut over the past two years, slashing about 150 megawatts of demand response capacity from the grid.

Enel X and CPower also asked the CPUC to waive a rule that requires any new resources to go through a lengthy “load impact protocol” process that bars new resources from being credited as resource adequacy until a year after they’re signed up. Google Nest sought commitments to expand incentives for smart thermostats, while Polaris Energy Services sought changes to bring more certainty to agricultural demand response customers it works with in the state.

Even some of the utility proposals, such as expanding incentives for automated demand response technology, weren’t taken up, Polaris CEO David Meyers noted. And the document doesn’t set any targets for increasing demand-side participation in terms of additional megawatts, something multiple parties had sought.

“There are no goals and no accountability here,” Meyers said. “The rest of the stuff was nibbling around the edges.”

A worrisome opening for more fossil fuels

But it’s the proposal for allowing utilities to procure up to 1,500 megawatts of generation that “really got my blood pressure up,” Vote Solar’s Smeloff said. That’s because any resources capable of coming online by this summer are “likely to be mostly natural gas, with some accelerated storage happening as well.”

The CPUC has already ordered California utilities and community choice aggregators (CCAs) to procure 3,300 megawatts of capacity resources by 2023, with half of that set to come online by August. Battery-backed solar projects make up the vast majority of the procurements to date, and while some of those projects may be able to expand their storage capacity to meet the CPUC’s emergency orders, supply chain and interconnection bottlenecks will make that difficult.

That’s likely to force California’s utilities to ask existing natural gas plants to remain open past planned retirement dates or expand their capacity to meet the emergency requirements. Utilities have already contracted for about 550 megawatts of fossil-fueled capacity under the CPUC’s previous emergency order, although multiple parties have said these contracts may be for power plants that were already providing power during last summer’s crisis.

The CPUC’s new proposal bars new natural gas construction, but will also allow contracts of longer than five years to be considered for “repowering” projects that replace older equipment, which Smeloff described as a “sleight of hand … it’s new gas, where there was an old gas plant. And to do that repowering will require a long-term contract.”

Clean energy and environmental groups are already concerned that the CPUC’s long-term planning will increase carbon emissions from an electricity sector that’s under state mandate to reach 60-percent carbon-free renewables by 2030.

Even if the proposal is passed as written later this month, however, that additional procurement is “not a done deal,” Smeloff noted. Utilities that do intend to sign long-term contracts will “need to come back on these long-term contracts with a Tier 3 advice letter — and a Tier 3 advice letter does require a vote of the commission.”