With hurricanes and wildfires across the country making concerns about reliability more urgent than ever, there is much to learn from how a regulatory decision weakened a fragile collaboration between California’s traditional and new load-serving entities (LSEs).
Primarily because of new community and customer choice providers’ success in the last decade by marketing to customers who want more clean energy, California now has over 40 LSEs, led by the fast-growing Community Choice Aggregations (CCAs). But regulators’ May 20 decision disrupted a budding collaboration and increased tensions between investor-owned utilities (IOUs) and the new LSEs by delaying reallocation of existing reliability resources among them, leaving the new LSEs with the growing costs of procuring reliability through power markets.
Reliability “is being reinvented on the fly in California, with the threat of blackouts or shortfalls now not just during peak summer days but all the time,” said Center for Energy Efficiency and Renewable Technologies (CEERT) Executive Director V. John White. “This decision settles compliance with the LSEs’ renewables mandates but meeting the reliability obligation has become more difficult and expensive.”
This decision on reliability — labeled resource adequacy (RA) in California — in the Power Charge Indifference Adjustment (PCIA) proceeding, revealed two important things, White, along with utility and other LSE executives told Utility Dive.
The power outages and uncertain system reliability made clear last August in California, last February in Texas, and threatening other parts of’ the country this summer have focused policymakers in most states on the new need for RA.
The absence of a definitive decision in California on who owns resources to provide that reliability has aggravated tensions between the emerging LSEs and the long-dominant IOUs, Pacific Gas and Electric (PG&E), Southern California Edison (SCE) and San Diego Gas and Electric (SDG&E). In the golden state, it could impede California efforts to avoid new power outages. For the rest of the country, it may be a lesson in what NOT to do to avoid reliability crises.
Beyond charges to allocation
The PCIA proceeding was initiated in 2017 to calculate the per-kWh charge to compensate IOUs that lost customers to the new LSEs for generation already procured to meet state renewables mandates. A high PCIA could unfairly shift “legacy” above-market costs to new LSEs. But a low PCIA could allow new LSEs to benefit from newer “vintage” low-cost renewables by leaving higher-cost, older vintage renewables in utility portfolios, disadvantaging IOU customers who would bear the higher costs.
Decisions in 2018 partially settled the compensation debate to the satisfaction of both parties, allowing new LSEs’ load shares to rise.
PG&E now serves “less than half” of the load in its territory, said PG&E Director of Energy Policy Analysis and Design Erica Brown. Over one-fourth of SCE retail load is served by CCAs, SCE Director of Portfolio Planning and Analysis Joshua Copenhaver added. And SDG&E expects lo lose “more than half of its load” by 2022, an April 26 CPUC filing reported.
But the state’s need for new procurement of generating capacity is growing. Since 2019, the CPUC has ordered procurements for new generation totaling 14.8 GW. Both IOUs and new LSEs now have significant unmet renewable portfolio standard (RPS) and RA obligations.
The California Public Utilities Commission’s (CPUC) May 20 PCIA decision addressed allocation between the LSEs of the legacy utility resources’ “attributes,” including the attribute of generation that fulfills an LSE’s obligation to meet the state’s renewables mandate and the attribute of generation that specifically fulfills the LSE’s obligation to meet the state’s resource adequacy requirement for reliability.
SCE, independent LSE Commercial Energy, and trade group California Community Choice Association (CalCCA) led a stakeholder process to a breakthrough compromise on allocation of all attributes.
There was “general stakeholder support” on their compromise proposal to use a “Voluntary Allocation and Market Offer” (VAMO) mechanism to allocate attributes of the resources in the utility portfolios among all LSEs to meet their RPS and RA obligations, the CPUC decision acknowledged. But there were also “significant reservations” and opposition, including from PG&E and SDG&E, it added.
All three IOUs and most other parties agreed the VAMO mechanism will fairly share “RPS attributes,” the decision approving the VAMO mechanism for voluntarily allocating and reselling RPS resources said.
The VAMO allows RPS attributes “to follow the customers as they depart to new LSEs,” SCE’s Copenhaver said.
The new LSEs’ access to IOUs’ contracted RPS attributes, like those from wind and solar, at the market price benchmark — which is the PCIA charge plus the market price — is now especially important because Senate Bill 350 requires that 65% of all RPS requirements be met through contracts of ten or more years starting this year. Access to the legacy contracts of the needed length in IOU portfolios reduce the burden on the new LSEs to procure and build new resources in the needed timeframe.
LSEs can reject the voluntary allocations from utilities, but that is unlikely because they still pay for their customers’ shares of IOU portfolios at the market price benchmark through the PCIA mechanism, stakeholders said. Rejected RPS attributes will be auctioned or go back into utility portfolios.
The RPS attributes are “money in the bank,” said Staff Attorney Matthew Freedman for customer advocacy group The Utility Reform Network (TURN). “Even entities that don’t need them will probably take them to resell.”
Most parties approved the VAMO for allocating RPS attributes, PG&E’s Brown agreed. Because LSEs are expected to use or sell their allocations from utility portfolios, PG&E expects to need more RPS procurement sooner to meet its obligations, “though it will not change California’s total new renewables procurement, only who does it.”
CCAs supported the VAMO because with the market price benchmark “we pay an above market price for the legacy assets and should get their attributes,” said former SCE executive and Clean Power Alliance (CPA) Chief Operating Officer Matt Langer.
The mechanism allows LSEs “to make their own choice” on how to meet their RPS obligations, added Commercial Energy Co-Founder and CEO Ron Perry. He, Langer, and TURN’s Freedman agreed with PG&E’s Brown that the VAMO will likely lead to IOUs procuring new renewables sooner but make no change in California’s total new renewables procurement.
Renewable energy developers support the VAMO because it does not change existing contracts as it only allocates attributes, said American Clean Power-California Director Danielle Mills Osborn. The Independent Energy Producers Association agreed.
The commission validated the VAMO approach for RPS attributes and seemed ready to end the hostility between new LSEs and IOUs over the issue. But it undermined the hard-won compromise among SCE, CalCCA and Commercial Energy by rejecting, along with the other utilities, the VAMO approach for the RA attribute crucial to system reliability.
Reliability blows up the compromise
Although the May 20 decision set up a process for more transparency about the utilities’ resource adequacy resources, it denied the use of the VAMO for allocating attributes for resources procured specifically to meet resource adequacy requirements and left them in the IOUs’ control. And developments in the commission’s RA proceeding and in the state’s need for reliability were determinative in rejecting the same mechanism for RA allocations, the decision reported.
After California’s August 2020 blackouts and this year’s continuing threats, it is clear utilities do not have “excess and/or uneconomic RA,” the decision said. Allocation of resource adequacy attributes must now “be tailored to minimize the risk of unintended consequences.”
The compromise also “does not consider the potential impact” of the June 2020 RA proceeding (D.20-06-002) decision to establish Central Procurement Entities for part of the RA obligation, the May 2021 PCIA decision said. That proceeding decision designates IOUs as “central procurement” entities for resource adequacy and could change the amount of RA attributes needed by other LSEs.
PG&E did not support the compromise PCIA proposal on RA because utilities are prepared to sell only excess IOU assets “after we meet our customers’ needs,” PG&E’s Brown said. With the emergence of LSEs, IOUs slowed procurement of resource adequacy resources because “we were counting on new LSEs assuming their share” of procurements, but that has left the RA market “very tight.”
The final decision “is responsive to the significant reliability questions confronting the Commission today,” PG&E’s filing reported. It also prevents the shift of rising reliability costs to IOU customers, it acknowledged.
SCE’s partners in the PCIA compromise see that shift as unfair.
“The RA market is extraordinarily and unprecedentedly constrained right now,” CPA’s Langer agreed. But the decision allows the IOUs to not share RA attributes with new LSEs, “which protects IOU customers, shifts the higher costs for acquiring new RA resources to the newer LSEs’ customers, and puts new LSEs at risk of draconian penalties for failing to meet the RA requirements.”
Other stakeholders see the regulatory process as the solution. The market for resource adequacy is constrained, and “the state needs to resolve the year-to-year uncertainty through the resource adequacy proceeding,” ACP-California’s Osborn Mills said.
The decision to not use the VAMO for RA is because the RA proceeding’s central procurement framework, appointing IOUs to manage resource adequacy for all LSEs, is the beginning of a “comprehensive redesign” of California’s RA framework, SCE’s Copenhaver said. “That is likely to make RA compliance very different than RPS compliance.”
But new LSEs are concerned about the seemingly contradictory decision’s immediate consequences.
The proposal for RPS and RA attributes was “the same fundamentally fair construct,” CPA’s Langer said. “The commission accepted it for RPS but rejected it for RA and that is a contradiction. If the PCIA properly values RA, all LSEs are indifferent between existing portfolios and the market. That is why it is called an ‘indifference’ adjustment.”
In the decision, “the CPUC chose to protect IOU customers, and make the new LSEs’ customers pay for the higher cost RA in the market,” agreed East Bay Community Energy (EBCE) Director of Regulatory Affairs and Deputy General Counsel Todd Edmister. “If all customers were treated equally in this decision, they should be indifferent on cost.”
The commission affirmed that customers should be treated equally in the RPS decision, but gave utility customers preference in the resource adequacy decision, Langer said. “That cost shift is fundamentally inconsistent with regulatory principles.”
This technical debate about regulatory principle is likely to aggravate rather than settle the now re-emerging hostility between California’s IOUs and new LSEs. And it could significantly impact California’s growing reliability challenges.
The fight goes on
Collaboration between IOUs and new LSEs in the PCIA proceeding was “a mixed bag,” EBCE’s Edmister said. In the working groups, “PG&E negotiated in good faith” despite disagreement, “but it was infuriating when PG&E blew that up at the end of the process.”
But collaboration with SCE on the VAMO compromise “was extraordinarily constructive and built mutual trust and respect, and Edison deserves a lot of credit,” Langer said. “It stood by the compromise when other IOUs opposed it, and showed it is principled and wants to do the right thing.”
But after “hundreds of hours of meetings and stakeholder feedback and interactions with other IOUs, the CPUC accepted an alternative proposed by PG&E at the end,” he said. “It’s unfathomable why.”
PG&E “participated in all workshops and provided comments during the workshops verbally and in written comments after the workshops,” PG&E’s Brown responded. “The CPUC chose something similar to PG&E’s middle ground proposal on RA, which is similar to current requirements with increased transparency.”
The CPUC decision rejecting the compromise “created a disincentive for future collaboration,” Langer said. “PG&E did not compromise and was rewarded. We are open to working with IOUs again, but we hope the commission rewards collaboration and compromise.”
The CCAs applied to the CPUC for a rehearing, but “don’t feel confident the RA decision will change,” he added.
They also took the issue to California’s legislature. “We drafted Senate Bill 612 tightly to require the commission to make a fair allocation to all LSEs of equal shares of all attributes, so that customers get equal benefits,” EBCE Senior Public Policy Director and Deputy General Counsel Melissa Brandt said. The bill was passed by the Senate and is working its way through the Assembly, she added.
The need to build almost 15 GW of new resources by 2026 could be a leveler by shifting new procurement obligations across the new LSEs and IOUs, some stakeholders said.
The transition to a system with multiple off-takers “has happened, the model has proved itself, and developers are comfortable with it,” said ACP California’s Osborn Mills.
New LSEs have credit ratings and customers and can acquire resources like the utilities, Freedman agreed. The February bankruptcy of Western Community Energy highlighted longstanding financial weaknesses of new providers, but IOUs face new risks from wildfires and changing demand, too, he added.
“The grid is not working in California and many other states, and we have to rethink and innovate,” CEERT’s White said. “The debate over the PCIA decision shows how this is a new procurement era, and the driver has shifted from RPS attributes to reliability attributes everywhere.”