by Jeff St. John
September 06, 2019

Back in March, we covered the ongoing impasse over what could be a looming problem for California’s grid reliability: creating some kind of central authority to manage the state’s resource adequacy program.

It’s a tricky problem, featuring a cast of stakeholders — utilities, generators and the community-choice aggregators (CCAs) that are taking on a big share of California’s future grid needs — who agree there’s a problem, but haven’t yet been able to agree on a solution. 

Last week, a big subset of those stakeholders filed a settlement agreement (PDF) with the California Public Utilities Commission that represents an important step forward in this debate, albeit one that leaves a major question unanswered. 

That’s because, while the agreement lays out a detailed plan for a “Resource Adequacy-Central Procurement Entity" with final authority to procure reliability resources for utilities, CCAs or independent energy providers, it declines to name the agency, entity or authority that should be in charge.  

This omission is by design, according to Beth Vaughan, executive director of the California Community Choice Association (CalCCA), which led the settlement agreement. Other parties to the plan include independent power producers representing the natural-gas-fired power plants that deliver much of the state’s grid resources of last resort, including Calpine Corporation, Middle River Power, NRG Energy, Inc., Shell Energy North America, and the Independent Energy Producers Association. 

And while the settlement agreement doesn’t include major investor-owned utilities Pacific Gas & Electric and Southern California Edison, it does include San Diego Gas & Electric. That’s noteworthy, as SDG&E is reported to be exploring the opportunity to exit the electricity procurement business, amid a push by the city of San Diego to form a CCA that would essentially cut the utility’s customer base in half. 

“It was quite a diverse group of stakeholders at the table,” CalCCA's Vaughan said in an interview this week. The final agreement represents “some really diverse viewpoints. That’s why this document is knitted together so carefully.” 

But while stakeholders largely agree that a central RA procurement authority could help solve some of the market’s most pressing problems, they’ve been unable to agree on the agency that should be vested with that authority. 

As Vaughan put it, “The moment you get hung up on ‘who,’ nobody can talk about the ‘how’ and ‘why.’ That’s why we stayed away from the ‘who,’” and instead worked out the details that participants were able to agree on — namely, reforming the known faults in California’s existing resource adequacy system. 

A fix for California's capacity market

The California Public Utilities Commission (CPUC) has been rejecting gas-fired power plants in recent years in favor of portfolios of efficiency, demand response, solar, storage and other clean alternatives.

That’s created a challenging environment for independent generators like CalpineNRG and Dynegy, some of which have turned to seeking reliability must-run contracts from state grid operator CAISO in lieu of resource adequacy contracts they say won’t keep their remaining plants open.

But these are the same power plants that utilities, CCAs, independent electricity service providers and other load-serving entities largely rely on to help meet their year-ahead and month-ahead resource adequacy (RA) commitments.

The resulting tight market led to a number of electricity suppliers failing to secure their RA commitments last year, forcing the CPUC to issue waivers to allow CAISO to secure contracts under its backstop authority — something it’s done only rarely in the past, and never at that scale. 

As CPUC Commissioner Liane Randolph laid out in a February blog post, “there is a narrowing number of gas-fired plants in the state that provide local reliability, and the plant owners are increasingly able to exercise market power.” 

This is the set of conditions that the Resource Adequacy-Central Procurement Entity is meant to solve. In simple terms, the RA-CPE would become the default reliability agency for the state, taking on full responsibility for ensuring that the state’s RA needs are met. But it would only do so after load-serving entities have the option to self-procure some or all of their required resources, and it would bill them for the costs of whatever share they end up picking up. 

In laying out the details of how the RA-CPE would function, the settlement agreement also fleshes out broader parts of the CPUC’s called-for changes to the RA program, Vaughan said. That includes the important shift from one-year procurements to three-year procurements, a move that should make for more attractive market opportunities for generators unwilling to commit to one-year terms.  

The settlement agreement also makes some changes to the three-year framework laid out by the CPUC. For example, the CPUC’s order only envisioned opening three-year procurements for local RA, the relatively small share of capacity required for local grid constraints. 

But the settlement agreement calls for using three-year “showings” for all three types of RA, including systemwide capacity, and the “flexible” resource adequacy capable of providing fast-ramping response to deal with California’s solar-influenced “duck curve” supply-demand imbalances. The share of each load-serving entity’s requirement under RA-CPE backstop authority would be adjusted over a rolling three-year basis, as the following chart indicates.

Moving to three-year contracts does open some challenges in a state where the share of electric customers is changing so rapidly, however.

CCAs have grown from a handful of counties and cities at the start of the decade to 19 operational programs serving about 10 million customers today. PG&E, already in bankruptcy due to its multibillion-dollar wildfire liabilities, has lost 2.4 million of its 5.4 million electricity customers to the 12 CCAs in its region, with more planned to open this year.

The settlement agreement deals with this load migration challenge with an “ex-post cost allocation approach,” Vaughan said. In simple terms, the mechanism will adjust costs between the time they’re forecast, when the resources are actually purchased, and when the costs are allocated to participating load-serving entities.

In a state where load is increasingly shifting from investor-owned utilities to CCAs, this essentially helps shelter utilities from paying for RA for customers that are no longer theirs by the time it’s delivered. 

But who's in charge? 

All told, the RA-CPE presents the CPUC and stakeholders with a plan for “what we like to call reliability insurance,” Vaughan said. “The idea is that, as we make these changes like a multiyear framework, and push that idea even further, this framework will encourage there to be a greater supply in the market.” 

But on the key issue of how the RA-CPE will come into being, the settlement agreement “does not identify or designate a specific entity as the central buyer,” except to demand that it be a “competitively neutral, independent and creditworthy entity” that would coordinate with the CPUC, California Energy Commission and CAISO.

This is a reflection of the difference of opinion between stakeholders, as laid out in confidential settlement meetings held over the spring and summer, Vaughan said. It’s also a clearly defined fault line over the more than a year of discussion on the CPUC’s reworking of its RA rules.

In fact, a state bill that attempted to take on the central RA procurement issue, AB 56, faltered earlier this year in the face of these complex conflicts. The bill’s fate was sealed after the head of the agency it named to take on the task came out against it, telling lawmakers that the agency wasn’t equipped to take on the role’s legal and financial responsibilities. 

As we noted in our March coverage in GTM Squared, these filings were full of contrary observations from stakeholders. Many agreed that the investor-owned utilities or state grid operator CAISO were the only parties ready to take on the role of a central buyer of RA. But proposals to actually vest them with that authority were rebuffed by multiple parties, including the utilities and CAISO themselves. 

CAISO’s objections lie primarily in the regulatory uncertainty associated with expanding its scope of authority over the RA market. As for utilities, the CPUC noted in its February order that it is leery of the “costs and risks associated with the central procurement function.” 

Southern California Edison is the only utility that’s so far expressed willingness to take on the central procurement role, but only for its own service territory, and only under certain conditions to ensure cost recovery. 

Another option put forward by SDG&E and PG&E was “a new state agency or private entity selected through a competitive solicitation process or through legislation.” Of course, creating this entity would involve “substantial time and expense,” as well as legislation to authorize it. 

Absent an existing party willing to accept the role, it would appear that this type of legislative approach is the most likely path forward for the market reforms envisioned in the RA-CPE. Given that the settlement agreement sets 2021 as the first year to implement its reforms, that does give regulators and lawmakers some time to consider alternatives. 

The settlement agreement is now open to a 30-day comment and 15-day reply period, which will provide so-far silent parties such as SCE and PG&E to weigh in. The CPUC’s Energy Division will incorporate these comments into any proposed order that may emerge from the discussion, which would then go through comment and reply periods before being taken up for vote by the CPUC, possibly as early as December.