by Jeff St. John
April 17, 2020

After years of trying to get California’s disparate energy industry parties to agree on a way to centralize procurement for its Resource Adequacy (RA) program, the California Public Utilities Commission has moved to break the impasse. 

But California’s community-choice aggregators (CCAs) say that the new plan, far from strengthening the state’s system for securing grid reliability in future years, could actually undermine a host of clean energy projects they’re working on — and they’re demanding some key fixes before the CPUC moves to vote on making it final in May. 

The key problem with last month’s proposed decision (PDF), CCAs say, is that it hands the responsibility for procuring “local” resource adequacy to utilities Pacific Gas & Electric and Southern California Edison, and in doing so, takes away the financial incentives that CCAs have to contract for their own resources. 

Local RA is the share of capacity identified by state grid operator CAISO to serve the urban centers of San Diego, Los Angeles and Ventura regions and the greater San Francisco Bay Area, which combine high energy demand with transmission constraints that limit how much energy can flow from beyond their boundaries. 

Compared to “system RA,” which can be located anywhere in the state, prices for this locally constrained RA are significantly higher — about 38 percent higher than system resource adequacy for the L.A. Basin and 25 percent higher for the Bay Area and Ventura areas in 2018, according to CPUC data. That’s largely because these constrained areas have fewer natural-gas plants, which still provide the majority of the state’s capacity needs. This scarcity tends to drive up the prices they can command from entities seeking local RA.  

California utilities and CCAs are quickly contracting for more “preferred resources” — solar, wind, energy storage, demand response and other carbon-free resources — both to meet the state’s clean energy goals, and to fulfill their share of the CPUC’s November order seeking 3.3 gigawatts of resources to meet the state’s looming short-term reliability needs. 

And many of these projects are planning to provide local resource adequacy, and are expecting the higher payments for that service to serve as part of the revenue stack they’ve built to be financially viable, according to Nick Chaset, CEO of East Bay Community Energy, the CCA serving the Bay Area’s Alameda County.

For example, EBCE plans to purchase local RA from the 36-megawatt Oakland Clean Energy battery project being built to replace an oil-fired power plant in west Oakland, he said. It’s expecting to be able to earn local RA from its 10-megawatt share of a joint procurement with other Bay Area CCAs of 30 megawatts of behind-the-meter storage and solar to provide resiliency against wildfire-prevention power outages for residents and critical facilities. The same goes for a 57.5-megawatt wind power project in rural Alameda County it’s planning to contract with to meet its reliability obligations. 

All told, “we have contracts for just about 100 megawatts of local resource adequacy,” Chaset said.

But “now, suddenly, there’s a huge uncertainty injected into those contracts — they may not count for local RA.”  

Monica Padilla, power resources director for CCA Silicon Valley Clean Energy, agreed that the CPUC’s proposal could undermine its plans to procure the roughly 5 megawatts of behind-the-meter solar-storage it’s seeking as part of the joint 30-megawatt procurement. “This would definitely put that at risk.”

Why CPUC’s proposed remedies won’t work for CCAs

The CPUC’s central procurement structure wasn’t meant to undermine the work of the state’s 21 CCAs, which serve more than 170 cities and counties and more than 10 million customers. In fact, it decided against making San Diego Gas & Electric a central procurement entity, since its relatively isolated grid system requires it to obtain local resource adequacy for more than 80 percent of its total capacity, leaving little left for any other entity to procure on its own. 

The CPUC didn’t see the same problem for PG&E and SCE, where local capacity accounts for 43 percent and 38 percent of total RA requirements, respectively, leaving CCAs with “substantial procurement autonomy.” 

To allow them to make use of that autonomy, it proposes allowing CCAs to “show” their existing local RA values to reduce their procurement obligations, or to bid them against all the other resources, including natural-gas plants, that are competing for PG&E and SCE’s business as buyers. 

But according to Melissa Brandt, EBCE’s senior director of public policy and deputy general counsel, these are poor substitutes for being able to meet CCAs’ local RA requirements. The first option, of “showing” local RA, may reduce the total amount of local RA the utility needs to buy, but the CCA’s customers pay full price and only receive the same small fraction of the benefits as all other utility customers, Brandt said.

The second option may offer revenue, but only “if the procurement entity buys our project at auction,” which is a “very risky” proposition. Given these risks, it’s far less likely that CCAs will choose to invest in locally sited projects that require local RA revenue to pencil out economically, she said.

In contrast, with the resource adequacy premium, “we can justify investing in the project, which may cost more in Alameda County than, say, in Kern County” in California’s Central Valley, where land and labor costs are lower. But without it, “you may say, maybe I won’t do solar-plus-storage — maybe I’ll just do the solar, or maybe I’ll just build it in Kern County.”

That decision would deprive the CCA’s customers of the local energy, resiliency and other benefits of a project that no longer pencils out, however. It would also deprive California’s grid system at large of a clean local capacity resource that, all other things being equal, would otherwise be filled by a gas-fired power plant.

The California Community Choice Association (CalCCA) trade group makes similar points in comments filed with the CPUC this week. “The local RA premium, while varying in time and location, can be significant and carries the potential to be the determining factor in a project decision,” it wrote.

The CPUC’s proposal “places this value at risk by leaving uncertainty about whether the [central procurement entity] will select the [CCA's] local resource in its solicitation.” 

The long and contentious road to CPUC’s attempted solution

CCAs have been required to procure their own RA since 2018, the same year that the CPUC decided that it should work on centralizing procurement to improve “cost efficiency, market certainty, reliability, administrative efficiency, and customer protection,” and to forestall the increasing amount of “backstop” procurement that state grid operator CAISO has been forced to make to cover shortfalls. 

But as we covered in a GTM Squared post last year, there’s been little agreement between utilities, CCAs, CAISO, power plant owners, consumer advocates and clean energy groups about the best way to do this, even as they have been able to agree on other changes, such as extending RA procurements from one year to three years. 

While many parties agree centralization will help achieve the CPUC’s goals, few can agree on which entity should take over that role. In fact, those that have been suggested as natural candidates, including CAISO and the utilities, are wary of taking it on themselves, with CAISO citing regulatory and legal barriers to procuring resources in a market it runs, and utilities worried about the operational and financial risks involved.  

CCAs and other parties have also suggested creating an independent agency to take on the task. But a legislative effort last year to do just that failed to advance, in part because it would have gone even further than the limited consensus reached by parties in the CPUC debate. And most parties agree that, at least in the short term, the utilities are the only entities positioned to manage the task.  

The CPUC opened a new round of workshops and stakeholder groups last year, focused on two key different ways to go about centralizing local RA. The first is a “full procurement” model, where utilities take over local RA procurement. That’s the form that the CPUC’s proposal has largely adopted, but with the additional options for CCAs to “show” their resources to reduce their procurement obligations — a proposal first put forward by Southern California Edison called a “hybrid” model. 

But CalCCA argues that this hybrid model “is in effect a full procurement model with [investor-owned utilities] in the central role” and that its concessions to giving CCAs more autonomy in local decisions represent “a distinction without a difference, since there is virtually no economic incentive or rational reason for [a load-serving entity] to make such a showing.”

What CCAs want instead — and what they’re willing to settle for 

Instead, CalCCA has argued for years that the CPUC should pursue a “residual model,” in which CCAs procure as much local RA as they see fit and then turn to the central procurement entities to procure whatever residual obligations they haven’t met.

Over the past year, CalCCA was able to win over a subset of CPUC parties, including San Diego Gas & Electric and independent power producers Calpine and NRG, to join in a settlement to bring it to the table. 

The CPUC rejected that proposal, both because it hadn’t won over a majority of participants, and because of concerns from PG&E and SCE that it may lead to shortfalls in procuring the required local capacity.

Part of that argument rests on the concern that CCAs may rely on “low-effectiveness resources” — a term CAISO uses to describe power plants or other capacity resources that have proven less reliable in providing the grid support they’re contracted to deliver — and thus force the central buyer into “costly over-procurement” to cover the gaps. 

But CalCCA questions that claim, noting that the CPUC hasn’t provided evidence to support it and that CAISO’s own definition of effectiveness is based on a multitude of factors — “specific unit availability, transmission outages, impact on congestion to other paths, and relative costs” — that can change from hour to hour and year to year. 

While CalCCA’s filing asks the CPUC to reconsider using the residual model it and its “settlement parties” agreed to, it also lays out some key changes that could make the proposed hybrid model less damaging to their local RA plans. 

The first could allow CCAs to procure their own “preferred,” carbon-free resources first, and only then step in as a central buyer of the remaining natural-gas-fired capacity needed to make up the difference – an approach also favored by the environmental groups. The second would provide financial credits to each CCA for the local RA they’ve already contracted, rather than forcing them to bid them against competing resources.  

In the meantime, CCAs are still seeking a central procurement entity that isn’t a utility to manage the state’s longer-range needs, EBCE’s Brandt said. That’s a more complicated task and will require legislation to enact. 

Even so, it’s preferable than the alternative, which could open the opportunity for PG&E and SCE to expand their roles in ways that the CPUC’s proposal doesn’t clearly limit, CalCCA warned. The group is “particularly concerned about placing PG&E in this role,” given its significant financial challenges as it seeks to emerge from bankruptcy, and its criminal convictions for the deadly 2010 San Bruno gas pipeline explosion and the 2018 Camp Fire.