California’s community-choice aggregators (CCAs) are contracting large-scale renewable-storage projects and building up behind-the-meter resources at a record clip, boosted by their clean energy priorities and a flexibility in rolling out new customer programs that the state’s investor-owned utilities lack.
That could allow the city and county entities that serve about one-quarter of the state’s electricity customers to help provide the grid reliability California regulators are desperately seeking before next summer to forestall a repeat of this August’s rolling blackouts.
But CCAs face similar barriers as utilities and project developers to quickly adding batteries to large-scale renewable energy projects, as well as uncertainty as to their long-term grid value. They also contend with statewide policy disconnects that solar-battery aggregators and demand-response providers say are holding back the full potential of those distributed energy resources (DERs).
It’s unclear whether a newly launched order instituting rulemaking from the California Public Utilities Commission, seeking proposals to enhance the state’s grid reliability by August 2021, will be able to spur efforts that can meet that deadline. But changes to how batteries and demand response are valued for the grid could help.
So says an October letter to state lawmakers and regulators from the California Clean Resource Adequacy Coalition, a group of CCAs and DER vendors including Tesla, Sunrun, Enel X, Voltus, Leap and OhmConnect.
The letter highlights the key problems outlined by an analysis of August’s rolling blackouts from the CPUC and state grid operator CAISO, and proposes five “immediate, specific regulatory actions” to help solve them:
- Provide certainty for the reliability value of 4-hour energy storage resources.
- Ensure energy storage resources can respond to grid stress.
- Fully value behind-the-meter energy storage.
- Eliminate limitations on the procurement of demand response.
- Streamline and simplify the CPUC load impact protocol process.
While the list appears straightforward, the issues it references predate California’s August grid emergency and are far from simple to fix. That’s because they involve adjustments to the complicated and controversial revamp now underway to California’s resource adequacy (RA) regime, which sets the terms by which utilities, CCAs and retail electricity providers procure grid capacity.
Even so, CCAs say they could allow them to tap their inherent flexibility compared to California’s investor-owned utilities, which must undergo lengthy regulatory proceedings before they can make changes. That flexibility, in turn, is attractive to third-party DER and demand-response developers, which have been increasing their activity with CCAs as they expand across the state.
In that sense, “I think the letter is even more timely in the context of this [order instituting rulemaking],” said Nick Chaset, CEO of East Bay Community Energy, one of the seven CCAs that signed the letter. “If you want to create more opportunity for demand-side resources, you have to make those changes that letter laid out…and those barriers are all the more significant in the matter of moving quickly.”
Supply-side proposals and pitfalls
The CPUC’s new order instituting rulemaking doesn’t make any policy changes. Instead, it proposes a long list of possibilities and asks stakeholders for their opinions on them.
The first item focuses on supply-side generation resources. The CPUC has proposed increasing efficiency at the natural-gas-fired power plants that make up the majority of its RA capacity or retrofitting power plants that are set to retire, like the once-through cooling power plants along the Southern California coast that have already had their operating lives extended by a lack of replacement capacity.
CAISO, which has long demanded more RA capacity, said in a CPUC filing that it supports expanding natural-gas capacity and extending the life of plants nearing retirement. But renewable energy groups are opposed, with the American Wind Energy Association of California saying in its CPUC filing that it “regrets that the commission has come to a point where discussion of extending or expanding California’s existing fleet of conventional resources is within scope.”
The CPUC is also seeking ways to speed the rollout of utility-scale battery installations to meet its order last year to add gigawatts' worth of RA by 2023. That includes more than a gigawatt of storage from Southern California Edison and Pacific Gas & Electric. It also includes hundreds of megawatts from CCAs across the state, enough to meet their collective 2021 targets.
In fact, California’s 23 CCAs have added 1,700 MW of renewable energy and more than 1,000 MW of battery energy storage over the past year, bringing total capacity to more than 6,000 MW, according to the California Community Choice Association trade group.
In particular, energy storage capacity is up fourfold from a year ago, and CCAs contracted for their first baseload geothermal project, California Community Choice Association Executive Director Beth Vaughan said in an interview last month. That helps meet California’s growing need for storage capacity to manage the “net peaks” — the evening demand peaks that come after the state’s solar power has faded from the grid — that drove August’s rolling blackouts.
But massive battery and solar-storage projects like these will be hard to speed up. Energy storage groups are already struggling to meet the August 2021 deadline for the first tranche of projects contracted under the CPUC’s order.
What’s more, adding or increasing batteries at existing projects could run afoul of CAISO’s rules on making a “material change” to existing interconnection agreements, East Bay Community Energy’s Chaset said. “Until the CAISO is to say they will, on an extremely expedited timeline, review and approve those changes, nobody is going to make those changes.”
California grid operator CAISO has been working on new rules for “hybrid” solar-storage projects that could ease bottlenecks like these. But it and the CPUC are still in the midst of other decisions that could erode batteries’ value over time, according to the California Clean Resource Adequacy Coalition (CCRAC).
First, there’s the risk that changes to RA methodologies could see existing standalone batteries lose reliability value as new storage comes online, undercutting their economics. The CCRAC wants the CPUC to either guarantee the longevity of the existing RA counting methodology or set up a “marginal counting approach that would ensure a resource's marginal RA value will be respected.”
Second, CCRAC wants CAISO to reconsider a proposed “minimum charge requirement,” which would essentially require batteries to maintain a certain level of charge at all times to prove they’ll be able to provide the energy they’ve promised the grid. But storage groups say this would constrain batteries from using that charge for other revenue-generating purposes.
Stakeholders have argued that CAISO could use other more fine-grained forecasting and dispatching tools to assure batteries’ reliability. But CAISO has pointed out that it would be “technically and operationally infeasible” to integrate these concepts into real-time market software systems that are already “time- and computationally intensive” — a nod to the fact that grid operators like CAISO are in need of IT to manage the increasingly complex mix of resources they’re being asked to forecast and manage.
Behind-the-meter battery proposals
On the demand side of the equation, the CPUC’s order also opens up the possibility of expanding utility demand-response offerings for large commercial, industrial and agricultural customers, expanding the residential Critical Peak Pricing programs, or initiating another round of the Demand Response Auction Mechanism that allows DER aggregators to earn RA revenue and bid capacity into CAISO markets.
But CCAs argue that more fundamental changes to the state’s RA construct are needed to tap into their growing roster of behind-the-meter resources, starting with batteries being installed to back up communities facing the state’s wildfire-prevention blackouts. East Bay Community Energy has teamed up with Peninsula Clean Energy and Silicon Valley Clean Energy to install 30 MW of behind-the-meter storage and solar. Marin Clean Energy is deploying 15 MW of batteries to customers over the next two years, and multiple CCAs are working on tapping Self-Generation Incentive Program funds to back up critical facilities.
But as GTM has noted in previous coverage, homes and buildings with behind-the-meter batteries are limited to reducing their loads to zero in terms of their RA value. Being able to actively export excess power could boost their grid value, but only if RA rules change to credit them for it, Chaset said.
That’s why CCRAC is advocating for CAISO to change its Proxy Demand Resource tariff to allow exported energy and for the CPUC to assign RA value to that exported energy. The CPUC’s November order instituting rulemaking actually suggests allowing this — but only as part of a proposed “emergency load reduction program” that could be dispatched outside of the demand response programs and RA framework to meet next summer’s emergencies.
CAISO’s recent filing “strongly agrees” that “any such program must remain separate and distinct from the resource adequacy program,” since it wouldn’t be linked to its market modeling or dispatch systems and thus shouldn’t be compensated in its wholesale markets.
Demand response proposals
As for demand response, lots of CCAs are promoting load-reduction incentives and technologies for their customers. One noteworthy example is Sonoma Clean Power’s GridSavvy program that connects smart thermostats, heat-pump water heaters and home EV chargers to drop load during emergencies; another example is Marin Clean Energy’s smart thermostat load controls.
But while these programs may help fulfill CCAs' conservation goals and reduce their risk of needing to buy energy during times of peak demand, they aren’t integrated into the Proxy Demand Resource programs that allow them to count as RA. That means they “do not get the capacity value for those resources,” said Thomas Folker, CEO of Leap.
Last month, Leap signed a first-of-its-kind agreement to provide 12.5 MW of RA capacity to CCAs Redwood Coast Energy Authority (RCEA) and Valley Clean Energy (VCE), starting in June 2021. Leap will source that capacity from its growing roster of Nest smart thermostats, EV chargers, water pumps and commercial-industrial load controls that it’s bidding into CAISO markets.
Leap is already orchestrating the participation of these DER aggregations through the Demand Response Auction Mechanism pilot program and was able to provide about 60 MW of daily load reduction through the dicey days in late August and mid-September when California came close to experiencing rolling blackouts again. But the program "is just for the [investor-owned utilities] to acquire third-party demand response, which kind of limits the pool,” he said.
Leap's new 12.5 MW rollout with RCEA and VCE represents a new opportunity for CCAs to combine load reduction with filling their RA requirements, said Gordon Samuel, VCE’s director of power resources. “We’re pretty small load-serving entities, so we decided to join forces, hoping to maybe get a little economy of scale.” While VCE also contracted for a battery project and RCEA is building a microgrid, both found that tapping Leap’s statewide resource mix was a cost-effective way to get the RA they need.
“I think the CCAs are much more nimble” that utilities, said Samuel, a 15-year veteran of major utilities including Arizona Public Service. “We’re able to quickly transact on the projects [without] as much bureaucracy. As CCAs are becoming more...established, the counterparties are getting more comfortable with our creditworthiness.”
But to make the most of that flexibility, CCRAC is asking the CPUC and CAISO to lift some restrictions on bringing demand-side resources to bear as RA — one of them relatively recent and the other stretching back to regulations in place for more than a decade.
The first, more recent issue has to do with the CPUC’s decision this year to cap procurement of demand-response resources by any utility to no more than 8.3 percent of its RA requirements. This cap is structured in a way that prohibits any single CCA from making use of the “unused [demand response] headroom” from utilities, effectively limiting the overall share of demand response the state can achieve, the group argues.
That’s a problem for a state that’s seen demand-response participation fall from about 2,000 megawatts to about 1,500 megawatts over the past five years. But both the CPUC and CAISO have expressed concern about relying on an increasing level of demand response for grid reliability, citing data that indicates it might not be showing up for grid relief in the levels that have been promised in RA contracts.
Demand-response providers and customers, however, have been arguing that the problems with demand response are rooted more in the overly complex and restrictive structures the state has set up for it to participate. One of the thorniest parts of this is the CPUC’s “Load Impact Protocols,” a structure adopted in 2008 that puts all load-modifying resources through a complex series of calculations to determine their RA value.
Amaani Hamid, Leap’s market development manager, said that one of the most limiting factors of these load impact protocols is that it’s based on two-year-old data. “We filed a load impact report for 2021,” she explained in an interview last month, but under the look-back rules, “we have to use data from 2019. It doesn’t take into account any of the changes in customers you’ve brought in, changes to how you deliver resource adequacy, changes to CAISO or CPUC rules,” or any other developments.
Another problem with using rules first created in 2008 is that they’re structured for centralized, utility-run programs, not for the third-party, market-based programs in use today, she said. While recent work at the CPUC is starting to clean up the protocols to better match today’s resources, it’s not clear if that will happen quickly enough to increase the scope of demand response for next summer.