Investor-owned utilities (IOUs) are keeping final responsibility for maintaining a reliable power system as California pursues new resource adequacy (RA) solutions to address the challenges from rising renewables penetration.
System operators have long relied on reserve generation to supplement basic capacity for meeting system peak demand. A new law and a new regulatory proposal are allowing the state's three dominant IOUs to remain final backups.
But renewable generation's variable supply and a shifting customer load due to increased adoption of distributed energy resources (DER) demand new solutions to protect reliability California power system stakeholders agree.
Today's RA paradigm "is based on central generation to meet a few predictable peaks," Energy Innovation Senior Fellow Eric Gimon told Utility Dive. "Today's digital economy makes a new approach possible. But implementing that approach could threaten [to create] turmoil that is self-defeating unless policymakers see that implementing flexible demand can produce rewards without excess risk."
California's energy transition includes another disruptive force, the proliferation of load serving entities (LSEs). Changes in resources, demand and providers have accelerated the state's need to protect reliability.
Many stakeholders have urged the state's policymakers to set a national precedent by balancing the IOUs' traditional centralized solutions with a bigger role for DER in maintaining reliability. The new law and regulatory proposal don't do that but stakeholders say the debate is not over.
RA "is pretty much a universal concept in electricity planning," Energy Innovation Vice President Sonia Aggarwal told Utility Dive. "All generation is counted in some kind of resource adequacy framework, and most are based on capacity plus a reserve margin."
California's RA program was put in place following the state's 2000-2001 energy crisis. Its goals are "to ensure the safe and reliable operation of the grid in real time" and to provide incentives for "new resources needed for reliability in the future," according to the California Public Utilities Commission (CPUC).
System RA obligations, which apply to the 80% of California load served by the California Independent System Operator (CAISO), require procurements to meet the annual system demand forecast plus a 15% reserve margin. Local RA obligations require capacity to meet a 1-in-10-year weather event and an N-1-1 contingency event determined by the CAISO. Flexible RA is to meet an LSE's biggest monthly three-hour ramp.
Planners also need "to get away from the idea that demand rises until there is no more supply and then the system drops off a cliff."
Senior Fellow, Energy Innovation
Until around 2015, procurement to meet all these RA obligations was largely done by California's three IOUs — Pacific Gas and Electric (PG&E), Southern California Edison (SCE) and San Diego Gas and Electric (SDG&E). Each managed reliability in its territory.
Rising penetrations of variable renewables have raised concerns from regulators and system operators about RA because fluctuations in solar and wind can compromise reliability, stakeholders told Utility Dive. Rising penetrations of DER add to the urgency because customers' use of them can shift load unpredictably.
But in the last four years, procurement for RA obligations set by the CAISO has become disaggregated across 44, more narrowly focused LSEs, including 19 CCA programs serving over 10 million former IOU customers. The CPUC expects CCAs to take over 80% of IOU customers by the mid-2020s. And a 2018 law increased the 21 registered energy service providers' share of IOU commercial-industrial load to 15.4%.
Policymaker concerns that disaggregated RA procurements could leave unfilled local needs that prevent reliably balancing supply and demand led to regulatory and legislative proposals to protect reliability.
The new law
The CPUC's proposed decision in the state's RA proceeding (R.17-09-020) was the second big step taken by California in recent months to resolve reliability concerns. The first, Senate Bill (SB) 520, signed by Gov. Gavin Newsom, D, last October, requires IOUs to be the electricity providers of last resort (POLR) if any LSE does not meet its obligations to its customers.
The bill also orders the CPUC to establish a process through which an IOU can file a "joint application" with another LSE in its territory to transfer the POLR responsibility, under CPUC jurisdiction.
While PG&E did not take a position in last fall's SB 520 debate, SCE supported it. But CCAs adamantly opposed the bill, East Bay Community Energy (EBCE) Senior Director of Public Policy and Deputy General Counsel Melissa Brandt told Utility Dive.
"The IOUs essentially have veto power over whether CCAs can be the POLR, and even if the CPUC prefers a CCA as the POLR, if the utility doesn't want to go along, the CCA cannot do it," Brandt said.
SB 520 also imposes costs and criteria on CCAs in the POLR role that are stricter than those imposed on IOUs and could over-reach CPUC authority to regulate CCAs, she added. Because CCAs oppose this kind of use of commission authority, they are unlikely to be willing to take on POLR responsibilities.
Since SB 520 is now law, they are likely to accept the IOUs in the POLR role, unless it drives up CCA costs, because it is unlikely to impact concerns about the use of local distributed energy resources for RA. They are, however, not ready to accept the RA procurement entity defined in the proposed decision, Brandt said.
The proposed decision
The proposal addresses the bigger question of how to implement a centralized procurement process to meet local RA needs if individual LSEs fail to do their share.
CCAs have consistently challenged any proposals from lawmakers that might threaten the emerging LSEs' "right to self-procure," Brandt said.
In an August 2019 Settlement Agreement that preceded the CPUC's proposed decision in the RA docket, CalCCA, representing all of the state's CCAs, SDG&E, the Independent Energy Producers Association (IEPA) and five other stakeholder groups proposed a "residual central procurer" for RA. Reliability procurement would be left to the LSEs, unless there were residual unfilled needs after an LSE's procurements were reported.
The agreement did not "identify or designate" who the residual procurer would be, but required it be "a competitively neutral, independent, and creditworthy entity" that coordinates with state regulatory agencies.
SDG&E declined Utility Dive's request for comment but its support of the agreement aligns with its November 2018 proposal for "a glide-path out of the energy procurement space."
Utility-scale renewables developers "have completed transactions with CCAs" and have also endorsed the agreement because they could see "a residual central procurer would address procurement gaps," IEPA CEO and former CAISO Board of Governors member Jan Smutny-Jones told Utility Dive.
But the CPUC, in its proposed decision, rejected the settlement, because it represented only eight of 60-plus stakeholders, was not the best solution for overall grid reliability, and omitted the "critical component" of identifying a specific procurement entity.
The proposed decision also rejected the Settlement Agreement's residual central procurement concept, and named PG&E and SCE as central procurement entities for local RA in their territories, largely eliminating the right to self-procure of the emerging LSEs, including CCAs.
A central procurement entity for SDG&E's territory was deferred because system, local, and flexible RA capacities overlap, the proposed decision says. LSEs there "will continue to receive a local requirement and self-procure local resources as is currently done."
"The argument in the 1990s was a strict market approach would be more efficient, and it worked perfectly until market failures led to the energy crisis,"
Executive Director, Independent Energy Producers Association
The proposed decision would have the IOUs do "hybrid procurement," which "is similar to full procurement" in that it gives the IOUs most of the control, but gives LSEs an opportunity to procure local resources for RA.
SCE and PG&E, as hybrid central procurement entities, are allowed cost recovery for procurements that mitigate "load uncertainty and migration" and align with "the state's environmental goals and preferred resource procurement mandates," the proposed decision adds.
The residual model in the Settlement Agreement seemed to balance meeting the system's needs with some LSE autonomy, IEPA's Smutny-Jones said. "But there was no meeting of the minds between parties on who would be the central procurement entity and the commission understandably chose to settle that important question."
The proposed decision does not give CCAs and other LSEs the opportunity to procure for themselves, and that is "a step backwards for what California is trying to achieve," EBCE's Brandt said. "It is going to be very highly contested."
Stakeholder comments are due in mid-April and the final decision is expect in June.
While the CCAs were dissatisfied with the control given to the IOUs by the proposed decision, most stakeholders, including the IOUs, saw the decision as a failure to come to terms with reliability in a transitioning power system.
A new paradigm
While there are different opinions on the best approach to a central procurer, IOUs, CCAs and others agreed significant changes are needed for RA in California.
The existing RA program is "based on capacity available over peak hours" but high penetrations of renewables and DER creates a need for RA "not just during peak hours" as the dynamics of supply and load change, PG&E spokesperson Ari Vanrenen emailed Utility Dive.
SCE Manager of Wholesale Market and GHG Market Design Eric Little agreed, calling for "a more complete integration" of RA and resource planning. He also noted SCE's proposed new metrics for valuing co-located renewables and storage as RA, which could begin opening up a role for DER in RA.
Here, CCAs agree. "Historically, we've relied on the 15% planning reserve margin for meeting the system peak," EBCE Principal Regulatory Analyst Stefanie Tanenhaus told Utility Dive. But variable resources create "capacity needs to serve load at all hours of the day."
Regulators have committed to addressing the impacts of rising renewables, DER, and shifting load on reliability in Track 3 of the proceeding that led to the proposed decision, Tanenhaus said. It will begin this summer and consider "alternate reliability metrics to replace the reserve margin and new ways to value the reliability contribution" of all resources, including local DER and, especially, solar plus storage.
Efforts by regulators to develop new metrics within the existing program show RA is "stuck in an outdated paradigm," Energy Innovation's Gimon said. "New metrics will accommodate new resources, but will not make that [old] paradigm work."
The solution begins with moving away from a "commodity mindset," said Gimon, who just published a paper on RA's role in the energy transition. "Capacity as a commodity needs to make way for technology portfolios that accommodate a variety of possibilities."
Planners also need "to get away from the idea that demand rises until there is no more supply and then the system drops off a cliff," he added. System operators have reserves, the ability to curtail load, and out of state markets and resources that prevent a "cliff."
And demand side resources can now be foundational in the resource mix as a way to increase reliability, Gimon said. "In a digital economy, customers can respond to prices and consume more electricity when it's cheap and consume less when it's expensive, which also prevents the cliff."
It is, though, "not clear how to transition away from the existing RA paradigm without the perception of undermining regulatory authority and creating turmoil that defeats the transition," he acknowledged. It would require showing that the threat to reliability is greater than the threat of change.
But in California's haunted institutional memory, change is a real threat. "The argument in the 1990s was a strict market approach would be more efficient, and it worked perfectly until market failures led to the energy crisis," IEPA's Smutny-Jones remembered. "We have been down that road before and it does not have political traction."