Last week, the California Public Utilities Commission unanimously approved a major decision in its integrated resource plan proceeding. Launched in 2015, the IRP is the state’s first effort to guide the procurement of a long-term generation mix that will cost-effectively hit the state’s greenhouse gas and renewable energy goals while maintaining grid reliability.
As befits the complexity of this task, Friday’s decision (PDF) addresses many different parts of this process. At the high level, the California Public Utilities Commission (CPUC) approved a model “Preferred System Portfolio” for 2030, consisting of about 12 gigawatts of new generation that will allow the state to meet its needs — mostly solar PV, but also lots of wind power and battery energy storage, as well as geothermal power.
This carbon-free portfolio is the output of a convoluted modeling process, meant more as a guide to future iterations of the IRP than an attempt to forecast California’s generation mix by the end of next decade. And while it doesn’t add any new natural-gas-fired power plants, it also doesn’t call for closing those that remain in the state — at least not before their “essential reliability services” can be replaced with “reliable, low-carbon resources,” CPUC Commissioner Liane Randolph wrote in a Friday blog post.
Even so, environmental and clean energy groups praised the CPUC decision as an important next step in integrating its long-range plans with the state’s greenhouse-gas reduction commitments. Those include 2015 state law SB 350, which created the IRP, and last year’s SB 100, which calls for 60 percent renewable energy by 2030 and 100 percent carbon-free energy by 2045 — a hard cutoff date for natural-gas-fired power in the state.
But the most notable part of the CPUC’s decision may be just how much of the state’s future generation will come from entities that barely existed 10 years ago: community-choice aggregators, or CCAs.
According to the CPUC, by 2030, investor-owned utilities, along with a presumably minor contribution from electric service providers serving the state’s commercial-industrial customer Direct Access market, “propose to invest in approximately 1,000 megawatts of new resources by 2030.”
Meanwhile, “CCAs in aggregate propose more than 10,000 megawatts.”
The California Community Choice Association (CalCCA) highlighted this 10-gigawatt figure in its press release on the IRP decision this week, calling it “a major vote of confidence in the critical role CCAs are playing in California’s rapidly evolving energy system.”
But it’s also an unprecedented situation for California. And in reading last week’s filing, it’s clear this has made the CPUC anything but confident in the outsize role CCAs look set to play in the state’s future grid reliability.
In simple terms, the CPUC's decision:
- Casts doubt on the feasibility of CCAs’ collective ability to procure the 10 gigawatts of resources the IRP process suggests will be needed by 2030. CCAs say their fast-growing project portfolios and pipelines show they’re on track to meet the need.
- Singles out the role of the state’s remaining natural-gas-fired power plants in maintaining grid stability, and suggests that CCAs’ plans don’t adequately support them. CCAs counter that they’re providing support for legacy generation through other means.
- Sets up a "procurement track" to jump-start an eventual process to turn IRP procurement plans into real-world projects. CCAs and other parties have argued the CPUC needs to improve its current analysis and fix known problems before leaping into this task.
- Lays out a path that could lead to it gaining additional authority over CCAs’ activities. This is a troublesome development for CCAs, which value their independence to serve their constituents’ needs, but a step the CPUC appears to feel is needed to align CCAs activities with the state’s overarching needs.
Let's dig into the details.
What happens when CCAs become the state's biggest grid resource providers
Traditionally, the CPUC has relied on the state’s big three investor owned utilities, or IOUs — Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric — to procure long-term generation and grid resources, under the long-term procurement proceeding that predates the IRP. But with CCAs taking over an increasing share of IOU customers, responsibility for keeping those customers supplied with reliable and clean energy is shifting.
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. In fact, CCAs asked the CPUC in March to consider a restructuring of PG&E to become a “wires-only” utility.
SDG&E, facing the impending departure of the city of San Diego and about 40 percent of its load to a CCA, has been reportedly exploring a path to exit the energy procurement business.
Meanwhile, CCAs, which were formed with the express purpose of creating a public entity that could exceed IOUs in renewables procurement, have been able to offer their customers lower prices than the IOUs they’re departing from, and supply them with an energy mix with greater shares of renewable energy.
With the advantage of signing contracts in today’s climate of ever-falling prices for renewable energy projects, CCAs have been able to rack up more than 2,000 megawatts of long-term renewables contracts as of November, according to CalCCA. In an April CPUC filing, CalCCA stated that CCAs have 410 megawatts of large-scale renewable resource procurement under long-term contracts in operation, with another 1,263 megawatts of generation and 95 megawatts of storage resources contracted to come online from 2019 to 2021.
Open requests for offers from CCAs such as San Francisco-area East Bay Community Energy and Los Angeles-area Clean Power Alliance, along with a subset of eight CCAs, are in the process of procuring as much as 2.5 gigawatts of renewables to come online by 2022.
CCA growth has been so rapid that, of the 19 that filed integrated resource plans with the CPUC, only 10 of them existed as of August 2018.
The CPUC stated flatly in last week’s IRP decision that “it is not yet clear to us if it is feasible to rely on the CCAs for this level of procurement to achieve the 2030 portfolio.” To justify this stance, the CPUC noted that the median project being reported by CCAs is about 1.75 megawatts in size, meaning that “it would take almost 6,000 individual contracts to reach the 2030 new resource goals to achieve the optimal portfolio. This seems to be a serious challenge.” CalCCA countered that using the average of the contracts -- about 35 megawatts -- is more meaningful. Given that average, the 19 aggregators would need to sign about 285 contracts to reach 10 gigawatts.
The CPUC has been expressing concern about CCAs supplanting IOUs for years. Back in 2017, CPUC President Michael Picker launched a proceeding to investigate the shift of customers from IOUs to CCAs, which found that IOUs were set to lose about 85 percent of their retail electric load to CCAs, electric service providers and the share of energy sales lost to customer-sited solar PV.
Since then, Picker has raised concerns about CCAs’ ability to secure the creditworthiness to raise the financing needed to build the amount of new generation their growing customer base will need. This notion has been hotly disputed by CCAs, which have pointed to their growing renewables portfolios as proof of their ability to meet the challenge.
CalCCA fought back against this view in an April filing with the CPUC. “Not only have CCAs proven this false through...large-scale procurement ...but as public agencies CCAs have a variety of funding mechanisms available,” it wrote.
Marin Clean Energy has an investment-grade credit rating from Moody’s. Peninsula Clean Energy, Silicon Valley Clean Energy and Monterey Bay Community Power have procured more than 400 megawatts of capacity under long-term contracts. And newly formed Clean Power Associates has financed and is in the process of procuring 400 to 600 megawatts of new renewable resources, CalCCA said.
The natural gas debate
The CPUC's decision last week also delved into the role of CCAs in managing the state’s eventually doomed, yet still vital, natural gas fleet.
In simple terms, “eliminating natural-gas-fueled resources altogether by 2030, while maintaining reliability, would require technological solutions well beyond any of those that have been surfaced or analyzed in this proceeding to date," it said.
Yet despite this need, “the IOUs have made it clear in their IRPs that they do not plan to contract for natural gas resources beyond the short term,” while “CCA IRPs do not indicate that they intend to pick up such resources,” it noted.
The CPUC allowed SCE and SDG&E to build new gas-fired plants, as well as some of the state’s first distributed energy resources at scale, to help replace the San Onofre nuclear power plant in 2013 and 2014. But more recent proposals to build new gas-fired power plants in California have foundered in the face of grassroots opposition, and have increasingly been replaced by solar, energy storage, demand response, energy efficiency, and other alternatives to fossil fuels.
CalCCA and other parties have argued that the IRP should be focused on procuring new resources, not managing existing natural-gas plants for grid reliability. In fact, along with parties such as the Sierra Club and California Environmental Justice Alliance, CalCCA prefers to focus the IRP’s efforts on “identifying the optimal new renewable resources to enable the phasing out of natural gas generators,” not their retention.
Many parties to the IRP said the CPUC’s Resource Adequacy (RA) program should be the home for discussions about managing the state’s natural gas fleet. We’ve covered some of the latest developments for the RA program, which has traditionally relied on IOUs to procure the year-ahead resources — largely gas-fired peaker plants — to meet peaks and ramps in statewide and regional grid demand. The first key reform, shifting from one-year to three-year procurements, is set to start next year.
The CPUC’s decision noted, however, that it needs to look to the IRP to manage natural-gas issues further out than the three-year RA process. “Natural-gas plant owners understandably want to plan for the future of their assets, and without any assurances from buyers, they face even greater uncertainty. This adds up to a need to focus three to four years out for the retention of necessary reliability and renewable integration resources to support the system for the planning horizon.”
The CPUC also leveled criticism at CCAs on this matter, writing, “It will not be sufficient or appropriate for new CCAs to lean on these resources procured by IOUs, and provide the public with messages about their cleaner resource mix, while focusing their resource procurement efforts only on renewable and storage resources."
But as Beth Vaughan, CalCCA’s executive director, noted in a Wednesday interview, CCAs are already paying a portion of the costs of these legacy resources through the Power Charge Indifference Adjustment, or “exit fee” that CCAs pay utilities when they take over their customers.
Utilities have long sparred with CCAs over this exit fee, and in October the CPUC unanimously approved a plan that will expand the range of legacy resources to be covered by the charge — a move CCAs say will lead to tens to hundreds of millions of dollars of additional costs.
But as Vaughan pointed out, all that additional funding will be going to support the same existing generation infrastructure that the CPUC is concerned will be unable to stay open through the 2030 timeframe — and that constitutes a significant source of CCA support outside of the IRP process.
“Through 2045, we’re going to be paying those...charges,” she said. “Some of it is hydropower resources,” but “a lot of it is gas-fired.”
Looking at the IRP's "procurement track"
California’s CCAs also have a negative view of the CPUC’s decision to launch a “procurement track” of the IRP — essentially a jump-start on the eventual process of turning the IRP’s models and policies into real-world energy, capacity and reliability resources. That puts them somewhat at odds with groups such as the Solar Energy Industries Association that support the concept.
CPUC says it needs to start now on the process to prepare for resources that might be needed both in the three- to four-year timeframe, slightly outside the Resource Adequacy proceeding’s scope, as well as “by 2030 or slightly beyond,” depending on factors like whether the state’s buildings switch from gas to electric power more quickly than expected, or whether out-of-state renewables and transmission lines are built on schedule.
The new procurement track “will allow us to test our assumptions and begin the acquisition process for the types of resources that we need and want to support the transition to 2030," the CPUC said.
CPUC plans to focus first on mechanisms for “backstop” procurement, in case load-serving entities can’t meet their IRP procurement responsibilities — something it’s tackling in the Resource Adequacy proceeding as well.
“The second aspect of procurement that we will address is procurement that may require collective action,” or “procurement mechanisms to develop resources that one or a small number of load-serving entities may not be able to bring to fruition on their own.”
CPUC also mentioned that “some renewable resources and hybridized technologies (such as combined natural gas and storage or combined renewables and storage) can provide more reliability value than we have been assuming," a key issue for solar and energy storage developers.
This may logically lead to discussions about a central procurement mechanism for one or more of the state’s grid procurement programs, and the floating of state legislation aimed at giving backstop authority to a new state agency.. But as we’ve noted, there’s far less consensus among California’s energy policy stakeholders about what that central procurement mechanism should look like, or what aspects of procurement it should include.
CalCCA has taken a stance against the CPUC’s plan for a procurement track, saying it’s “neither reasonable nor prudent” to proceed until the program’s various modeling deficiencies and gaps in data are corrected.
“The IRP process should focus first on improving the modeling results to provide load-serving entities with more accurate and actionable information to inform their procurement of optimal resources,” CalCCA wrote, adding that SDG&E and CAISO also suggested that the CPUC do more analysis before opening a procurement phase.
A brewing jurisdictional challenge?
In its decision last week, the CPUC also expressed concern over how various CCAs view its jurisdiction over them. Several passages detail the CPUC’s dissatisfaction with how some CCAs responded to the IRP’s demands for information or validation of their data, from customer rates to long-term procurement plans.
For example, the CPUC wrote that some CCAs “cautioned against using their 2018 LSE plans in statewide planning in this IRP cycle,” while others “asserted the primacy of their voluntary plans approved by their local governing boards over the Commission’s IRP process, and argued that the Commission’s IRP processes do not fit with their individual resource procurement plans. Such statements are concerning, as the integrity of the IRP process...depends on the provision of accurate, up-to-date data and information by all load-serving entities.”
This tone of frustration extends to the CPUC’s discussion of the CCAs’ role in maintaining natural-gas resources for grid reliability, where it noted, “It will not be sufficient or appropriate for new CCAs to lean on these resources procured by IOUs, and provide the public with messages about their cleaner resource mix, while focusing their resource procurement efforts only on renewable and storage resources.”
The CPUC immediately follows this statement with an indication that it may be seeking a legal justification to extend its jurisdiction over more aspects of CCA resource procurement, saying:
We also note that Senate Bill 350 specifically gave the Commission the authority to require CCAs to procure, via long-term contracts, renewable integration resources. At this moment in time, every resource that requires procuring or retaining, including the renewables themselves, is being used for renewable integration, since renewables are becoming the dominant resources in the electric system. While it may be the case that every single individual generation plant on the system currently is not needed for renewable integration, it is still the case that every type of resource on the system is being utilized for this purpose. Thus, we anticipate the need to require more focus on renewable integration long-term commitments as time goes on to ensure that we are adequately implementing the Legislature’s direction to optimize among three coequal goals: environmental, reliability and cost.
CalCCA’s April filing objected to this tactic as having the “explicit purpose of expanding the Commission’s jurisdiction over CCA procurement,” and complained that it’s unsupported by the language of SB 350.
It also noted that the term “renewable integration” already refers to a “number of distinct strategies for incorporating variable-availability renewable resources into the grid, including changing usage patterns through price signaling, resource curtailment, and the procurement of renewable integration resources” — not a term to be applied to every resource a load-serving entity in California may procure.
It’s unclear how this percolating conflict over an as-yet-unasserted right by the CPUC may play out in future IRP decisions. But it’s worth noting that among the many energy-related bills coming from California lawmakers this legislative season is one, SB 155, that would set new rules for IRP compliance, including a list of reporting requirements specifically for CCAs.