California is facing a major decision under a tight deadline — whether it should push for large-scale power plants and batteries to prevent a repeat of its August 2020 rolling blackouts this coming summer or turn to behind-the-meter resources such as batteries and demand response. 

Right now, the California Public Utilities Commission is moving more quickly to find supply-side solutions. But a rising chorus of stakeholders, from smart thermostat kingpin Google Nest to major demand-response provider Enel X, are demanding an equivalent push to free up behind-the-meter flexibility. 

Last week, the CPUC issued a ruling asking the state’s three big investor-owned utilities to seek out ways to expand supply-side capacity before August 2021, the next step in an effort launched in November to prepare for the possibility of another regionwide heat wave pushing the state’s grid past its limits. The options could include expanding existing power plants, adding new utility-scale battery capacity, and securing contracts from out-of-state resources. 

State grid operator CAISO has proposed expanding its reserve margins and using its emergency procurement authority to enlist resources that can supply electricity in hot evening hours when California’s solar power is fading — the same hours it was forced to turn off power to hundreds of thousands of customers on Aug. 14 and 15 last year. 

But critics of this supply-side approach worry that new large-scale projects are highly unlikely to be able to be brought online by the CPUC’s August deadline. That could lead to utilities in a state with aggressive decarbonization goals paying natural-gas-fired power plants to expand their role in meeting grid demand. 

What’s more, those plants would be asked to work hardest in the midst of a heat wave — the same conditions that forced several gas-fired plants offline last August, exacerbating the conditions that led to the rolling blackouts. 

The open-ended nature of last week’s ruling also makes it unclear whether utilities would be able to turn to backup generators or other highly polluting resources, rather than seeking out carbon-free resources first, as required under the CPUC’s loading order regulations, Ed Smeloff, director of grid integration at Vote Solar, said in an interview. 

“There’s no statement about cost, or operating characteristics, or what the contract term is,” he said. “Is it just for the summer of 2021 or are they going to be multiyear? None of that is specified.”  

Demand-side solutions — behind-the-meter batteries, smart thermostats, and commercial and industrial demand response — may well be a more realistic set of options to meet the CPUC’s August 2021 deadline. In fact, the joint California agency root-cause analysis into last summer’s grid emergency highlighted “demand response and flexibility” as the resources most likely to be able to be added by mid-2021. 

Utilities agree. Southern California Edison’s filing noted that of the choice between decreasing demand or increasing supply, “reducing demand by enabling more participation in demand response programs is more likely to be achievable in meaningful quantity prior to summer 2021.” Pacific Gas & Electric’s filing highlights the need to avoid using the procurement “to expand the gas fleet in a way that sets the state back on its decarbonization path.” 

The CPUC last month issued a call for new demand response proposals, expected to yield a proposed decision by March 2021. But in the meantime, “it does seem like supply is moving ahead of load reduction, and that’s concerning,” Smeloff said. 

Growing demand for expanding demand response 

Both the CPUC and CAISO have expressed concern about relying on demand response for grid reliability, citing data that indicates it might not be showing up for grid relief at promised levels.  

But demand response companies have pointed out that voluntary conservation efforts in the days following the rolling blackouts were able to deliver about 4 gigawatts of load reduction, indicating that customers can be counted on to meet grid emergencies. And while most of that conservation was essentially charity, finding ways to pay for it could create a persistent and reliable resource, they say. 

Google Nest’s filing noted that its smart thermostat utility programs with Southern California Edison, San Diego Gas & Electric and Los Angeles Department of Water and Power, along with its third-party partners Leap and OhmConnect, were able to shift about 60 megawatts of load during the Aug. 14 and 15 grid emergencies. With the right policies in place, it estimated it could double or triple that by next summer. 

But to get there, California will need to revamp its demand response programs in multiple ways, according to these and other stakeholders. 

Demand response “did come to the rescue, and more could if the rules were relaxed to some degree,” Greg Wikler, executive director of the California Efficiency + Demand Management Council, said in an interview. But “it’s not capable of participating in the marketplace given the rules that have been put in place,” he added. 

California’s demand response resource has fallen from about 2,000 MW in 2015 to about 1,500 MW today. According to demand response companies, that’s due to the CPUC’s shift over the past five years away from traditional, utility-program-centric demand response approaches and toward models based on participation in wholesale energy markets similar to other “dispatchable” resources like power plants.   

While this effort was well-intentioned, “there were so many rules and barriers put in the way to allow that resource to flourish,” Wikler said — a view echoed by many California demand response participants. 

The CPUC’s emergency reliability order does offer the potential for new approaches to capture the value of demand-side flexibility. One such proposal is the creation of an Emergency Load Reduction Program that could offer out-of-market compensation for resources that can be made available during critical moments like last August’s heat wave.  

But Google Nest argued in its filing that the CPUC’s August 2021 deadline makes developing entirely new demand response programs unfeasible, compared to expanding current programs. 

The critique of California’s approach to demand-side flexibility 

The demand response auction mechanism (DRAM) pilot program, which allows aggregated batteries, electric vehicle chargers, smart thermostats and other sources of load flexibility to participate in California’s power markets, was the earliest example of the CPUC’s shift to market-based participation. 

But after the program came under scrutiny in 2018, its budget was cut in 2019 and 2020, reducing the total amount of flexible load under contract. Many stakeholders are calling for a supplemental DRAM auction with a higher budget to help enlist demand response for summer 2021, but it’s not clear if the CPUC will take up the suggestion. 

DRAM participants Enel X, OhmConnect, Leap and Stem contributed a collective 410 megawatts of load reduction in the week following the rolling blackouts, according to Wood Mackenzie. That’s nearly four times the amount of capacity those four companies have officially enrolled in the DRAM program, however — a nod, critics say, to the restrictive nature of the rules that determine how much capacity participants are allowed to claim. 

One of the biggest challenges cited by demand response participants lies in the CPUC’s “Load Impact Protocol” study process, which puts load-modifying resources through a complex series of calculations to determine their capacity value. 

Among other things, these rules won’t allow any newly enlisted demand-side resources to be compensated as resource adequacy — California’s regime for valuing grid capacity — unless they’ve already been available for at least a year. Demand response providers Enel X and CPower suggested in their joint filing that the CPUC waive that rule for new demand response resources being sought for summer 2021 grid relief, but it’s unclear if the CPUC will consider this step. 

What’s more, the “baselining” methodologies used to determine how much load reduction happens at customers’ sites compared to their normal operations may be undercounting their value during grid emergencies like last summer’s heat wave, many participants say. That’s primarily because baselines taken during previous days of normal temperatures underestimate the spike in electricity use during extremely hot days, and the adjustment methods for taking this into account aren’t rigorous enough to capture the difference, stakeholders say. 

An analysis by the California Efficiency + Demand Management Council indicates that many demand-response participants during the August 2020 heat waves may not receive credit for their reductions because of this problem with baseline methodology, Wikler said. In fact, some may end up being penalized for underperformance, he added. 

These barriers haven’t stopped companies from enlisting new demand-response and behind-the-meter-battery customers in California. Oakland, Calif.-based startup OhmConnect last month raised $100 million from Google-affiliated Sidewalk Infrastructure Partners to build out 550 MW of residential load flexibility via smart thermostats and Wi-Fi-connected smart plugs. It and other companies are asking the CPUC to lift a standing 8.3 percent cap on the share of resource adequacy for utilities and community choice aggregators resource that can be served by demand response. 

U.S. residential solar leader Sunrun is enrolling tens of megawatts of battery-backed solar systems as virtual power plants. It and other behind-the-meter battery vendors are asking for rule changes that would allow excess battery capacity to be fed back to the grid. 

But the rules that now exist may well be dampening the potential for capturing California’s nation-leading roster of behind-the-meter resources, which adds up to gigawatts’ worth of latent capacity, according to Wood Mackenzie’s analysis.