Over the past month, the California Public Utilities Commission’s effort to reform its Resource Adequacy program has hit a major snag, one centered on longstanding conflicts about how to value out-of-state imports as part of the state’s future grid capacity mix.
California has faced numerous challenges in its year-long effort to change the RA program, which sets the rules for how investor-owned utilities, community-choice aggregators and other load-serving entities contract for future generation or load-reduction capacity. These challenges include how to measure the value of all kinds of future grid resources, from the economically struggling natural-gas-fired power plants that have been closing across the state, to utility-scale solar-battery projects that are contracted for but have yet to be built.
One of the most contentious aspects of the RA debate has been over the value of imports from outside the boundaries of California grid operator CAISO. These can range from Pacific Northwest hydropower connected via the Pacific DC Intertie to a variety of fossil-fueled or renewable-powered resources from across the Western U.S.
In simple terms, the argument over imports breaks down to what rules California should use to determine whether the imports can be relied on in future years when the grid needs them the most.
Stakeholders such as the California Community Choice Association (CalCCA) have argued that import RA should retain its place as part of a diverse portfolio of resources, and that the California Public Utilities Commission’s proposed remedies would undercut that value. Other stakeholders, including CAISO but also environmental groups such as the Natural Resources Defense Council and the Environmental Defense Fund, have expressed concern that growing demand for carbon-free capacity resources across the Western U.S. could put pressure on California’s reliance on out-of-state resources and sap efforts to secure in-state resources to meet the same goals.
All of these arguments have been sidelined at present to address a much more pressing concern. On Oct. 17, the California Public Utilities Commission issued a decision (PDF) affirming its new Resource Adequacy rules for 2020. Included in the decision are new requirements for import RA that the CPUC said are needed to assure that future reliability.
But according to stakeholders, these new rules are not only legally flawed, but will also force them to renegotiate or cancel tens of millions of dollars' worth of import RA contracts for the new year.
The firestorm over new import Resource Adequacy rules, explained
According to the community-choice aggregators (CCAs), generator groups and others, the CPUC’s decision uses a faulty legal premise to throw many existing RA contracts into doubt. CalCCA filed a motion to stay the decision, along with an application for rehearing (PDF), telling the CPUC that its decision “violates state and federal law.”
What’s worse, the CPUC’s new rules came mere weeks before the Oct. 31 deadline for load-serving entities to file their year-ahead compliance “showings” for meeting 2020 RA needs as well as a Nov. 17 deadline for RA showings for January 2020. That’s given the LSEs almost no time to absorb the changes before presenting new or existing contracts for approval.
This has thrown an estimated $47 million in existing 2020 import RA contracts held by CCAs into question, CalCCA says. Without a stay in the decision, its members could be forced to renegotiate replacement contracts at an incremental customer cost as high as $87 million.
“We’ve already bought RA for the year ahead,” Beth Vaughan, CalCCA’s executive director, explained. “We don’t want to do last-minute deals. And we don’t want to do waivers,” which refers to the last resort available to LSEs that can’t contract for their RA needs by the CPUC’s deadline.
But that’s exactly what some CCAs are being forced to do, Vaughan said. For example, Marin Clean Energy, the state’s oldest CCA, noted in its filing that it has been “forced to remove its import [RA] resources from its January 2020 month-ahead filing due to confusion.”
“I get that there’s concern about resiliency and about reliability deficiency,” Vaughan said. But “knee-jerk reactions,” as she characterized the CPUC’s import RA decision, “can have enormous financial implications, and who ends up paying for that? The ratepayers.”
State grid operator CAISO, which has generally been supportive of more conservative methods to calculate the value of import RA, wrote a supporting filing (PDF) agreeing that the CPUC’s new rules would force “significant changes to RA import contracts” in ways that have created “significant uncertainty for all market participants.”
In fact, CAISO noted, the new rules are significantly different from those laid out in a proposed decision in September, but stakeholders haven’t had an opportunity to comment on the changes. That suggests the CPUC “has not fully considered the potential capacity and energy market impacts” of its new rules, CAISO noted.
The Western Power Trading Forum, a group of utilities, generators, developers, investors and energy companies, also supported CalCCA’s motion for stay, noting that many of its members believe the new rules will have “negative effects on the RA market.” It also noted “there is a strong likelihood that legal challenges” to the new rule “will prevail on the merits,” indicating willingness to seek legal redress at the state or federal level.
In particular, the WPTF took issue with CPUC’s new requirement for certain classes of import RA to comply with “self-scheduling” requirements. Somewhat counterintuitively, the term “self-scheduling” refers to resources that must be made available to accept the clearing prices in CAISO’s markets at all times, rather than being allowed to set the prices at which they’re willing to enter the market, as was previously the case.
The CPUC’s perspective
Despite these strong statements against the decision, the CPUC has not yet acted on CalCCA’s motion for stay or request for rehearing. In an email statement on Monday, CPUC spokesperson Terrie Prosper said the RA import decision “speaks for itself” on the need for rule changes to assure that import capacity can be relied upon.
In fact, the market change that has drawn the ire of CalCCA, WPTF and other groups — the need for some types of import RA to “self-schedule” — was identified by the CPUC as a key fix to assure this reliability. That’s because, according to a report from CAISO’s Department of Market Monitoring, under the old rules, RA imports were allowed to set any price they desired in CAISO’s day-ahead markets — including prices as high as $1,000 per megawatt-hour, which would obviously fail to clear the market.
That’s a problem because the RA program is designed to pay resources now in exchange for them being available in the future. But if import RA resources end up bidding ridiculously high prices in day-ahead markets, they may never get called on to provide their capacity, effectively avoiding doing the job they’re already been paid to do.
The CPUC’s decision also cited CAISO stakeholder comments to the RA proceeding, noting that the old rules may allow some RA imports to represent "speculative supply," capacity resources that may not yet be built or fully contracted with or which may be committed to providing capacity for other regions. That’s a particular issue with the category termed “non-resource-specific RA” as well as with claims to future capacity that aren’t linked to a single, specific power plant or other resource.
"Certainly due to our increasing reliance on imports in the RA context, and our increasing shortages, it’s understandable that the CPUC would explore the requirements for import RA capacity,” Seth Hilton, a partner in law firm Stoel Rives’ Energy Development practice, said in an interview last week.
At the same time, he said, “It’s obviously a difficult situation for the CCAs, and the compliance deadlines have now passed. [...] It would be helpful for some clarity from the PUC on how they intend to proceed with this.”
The big picture for California grid reliability
This isn’t the only short-term grid capacity challenge facing California. For example, the CPUC’s integrated resource plan, meant to align long-term planning with the state’s decade-out energy needs, has led to the creation of a brand-new, 3.3-gigawatt all-source procurement order meant to forestall the potential for gigawatts of capacity shortages on the grid in the 2021-2023 timeframe.
This large-scale procurement also took up the issue of imports, but it did so in a way that few stakeholders found satisfying, Hilton said. At first, the CPUC proposed discounting all imports to one-third of their nameplate value, but most stakeholders protested that decision, calling it arbitrary and not based on facts. The CPUC's final decision allowed incremental imports to count for up to 20 percent of each LSE’s procurement. But it also requires them to “meet all of the other RA requirements associated with imports,” including the new rules under dispute.
Meanwhile, amid the imbroglio over using imported capacity to serve California’s systemwide RA requirements, the state’s LSEs are continuing to struggle to secure the local resources they need, Hilton said. With more and more natural-gas generation retiring, “prices are going up, there’s less capacity available and there are more load-serving entities that need to procure it,” he added.
Last year, 11 LSEs, including utility San Diego Gas & Electric, six CCAs and three retail energy providers, submitted local waiver requests “due to their inability to procure sufficient capacity in one or more local areas,” according to the CPUC’s report on the RA market in 2018 (PDF). That was a record number of waivers; it was cited as a key driver of the CPUC's current RA reform efforts.
As of Monday, 20 LSEs have submitted local waiver requests for the upcoming year, including SDG&E and Pacific Gas & Electric, 9 CCAs and 9 retail electricity providers.
This tightening of local RA capacity is not specifically related to the import RA issue, but it does highlight California’s growing challenge in meeting its grid reliability needs, both within and outside its borders.
