California tees up 7.5GW procurement to replace Diablo Canyon. Is it enough?

California’s plan to replace the Diablo Canyon nuclear plant and retiring natural-gas plants could be a major boost to the state’s clean energy ambitions, adding 5.5 gigawatts of battery-backed solar and wind power, as well as 1 gigawatt each of geothermal power and long-duration energy storage, by mid-decade.

Or the plan might be a penny-pinching attempt to lowball California’s future clean-energy needs that could end up costing more in catch-up procurements in the long run, while leaving the state with higher greenhouse gas emissions after its last nuclear plant closes than it had before.

These are two opposing views of the California Public Utilities Commission’s new midterm procurement proceeding, which was unveiled for public comment in March. And with so much uncertainty involved in trying to optimize the state’s future energy mix — and so many undetermined details of how the first-of-its-kind procurement will be handled — it’s hard to say which may end up becoming reality.

“There’s a lot riding on this, in terms of our climate targets and the economics of the clean energy industry, and ultimately, in jobs,” said V. John White, executive director of the nonprofit Center for Energy Efficiency and Renewable Technologies.

That’s because the 7.5 gigawatts of procurement are likely to make up the vast majority of new carbon-free resources to be built over the next half-decade, according to White. The total will be split among utilities Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric, as well as the state’s growing roster of community choice aggregators and its relatively small share of independent electric service providers.

And while clean energy groups say the proposal is a good start toward bringing the power sector into compliance with state law SB 100, passed in 2018, ​“we do wonder if that’s enough,” said Luis Amezcua, a senior campaign representative with the Sierra Club. The law calls for 60 percent renewable energy by 2030 and 100 percent carbon-free energy by 2045.

A new analysis from California agencies finds the state will need to build 6 GW of renewables and energy storage every year, on average, to meet SB 100’s targets. Some stakeholders worry that 7.5 GW through 2026 isn’t a sufficiently aggressive target given the much larger annual additions the analysis indicates are necessary.

Then there’s the question of whether 7.5 GW to replace the Diablo Canyon nuclear plant will be enough to ensure grid reliability in years to come — or whether it may lead to decisions to keep old gas-fired plants operating longer. That’s a real concern, given that the California Public Utilities Commission’s 2019 order to procure 3.3 GW of new resources through 2023 hasn’t yet delivered enough reliable capacity to allow for the on-time closure of coastal natural-gas-fired power plants, which saw their retirement dates extended after last summer’s grid emergencies.

“The most fundamental question is [whether] we over-ensure or under-ensure…reliability in the face of closing down Diablo Canyon,” said Ed Smeloff, director of grid integration at advocacy organization Vote Solar.

Conflicting imperatives: Costs vs. carbon reductions

The CPUC insists that its plan, which is set for a vote from the full commission in the coming months, is its best effort to balance the imperatives to reduce carbon emissions, maintain grid reliability and keep electricity costs in check.

Long-term planning like this ​“comes with an element of uncertainty,” Nathan Barcic, the CPUC’s director of integrated resource planning, said during a March 10 workshop on the proposal. ​“Either way you cut it, we do not take this analysis lightly.”

But California’s welter of regulatory proceedings aiming at reaching its carbon-reduction goals, while also ensuring grid reliability at a reasonable cost, have led to disputes over whether the CPUC is taking on the challenge in the right way.

The first thing to understand is that the current midterm procurement proposal is part of the integrated resource plan (IRP) process set in place by 2015 state law SB 350. As part of that IRP process, the CPUC last year enacted a greenhouse gas target of 46 million metric tons (MMTs) by 2030, but it also ordered the state’s investor-owned utilities, community choice aggregators and retail electricity providers to make plans to hit a lower 38 MMT target.

Clean energy and environmental groups had sought an even lower 30 MMT target, and utility Southern California Edison and state grid operator CAISO pressed for the 38 MMT target, with an eye on making sure the state’s electricity sector invests early and heavily enough in decarbonization to avoid missing its 2030 goals.

SB 350 also mandates that the CPUC minimizes unnecessary cost increases in setting its long-range plans, however. A CPUC analysis indicates that picking the lower 38 MMT target will slightly increase already rising utility customer bills, since it would require building more new resources whose costs are passed on to customer rates.

“They’re concerned about rates and bill impacts,” said Mohit Chhabra, a senior scientist with the Natural Resources Defense Council’s science and clean energy program. ​“That’s one of their main rationales for not going higher.”

But Chhabra highlighted that California’s rising utility rates are mostly being driven by multibillion-dollar grid investments to reduce wildfire risks and by rising transmission costs, not the costs of building new resources like battery-backed solar and wind farms.

What’s more, ​“if you don’t buy enough renewables that provide capacity, you keep gas going longer than you otherwise would have, and you’re paying more to keep that gas around with capacity contracts and reliability contracts,” he said. The CPUC’s emergency response to August’s rolling blackouts has already drawn fire from clean energy groups for allowing utilities to expand their reliance on natural-gas-fired power plants.

A disconnect between low-carbon capacity and low-carbon energy

There’s another catch to the carbon calculations going into the CPUC’s plan to replace Diablo Canyon: the difference between resources that can replace its capacity and resources to replace the energy it produces.

That’s the critique that Mark Specht, energy analyst for the Union of Concerned Scientists’ climate and energy program, laid out in a recent paper. In simple terms, the CPUC’s midterm procurement is ​“focusing more intently on replacing Diablo’s capacity and less intently on replacing the clean energy,” he said.

The 2018 law SB 1090 requires that carbon-free resources replace Diablo Canyon’s 2.2 gigawatts of round-the-clock energy when Pacific Gas & Electric completes its shutdown in 2025. But the CPUC has dealt with how to replace Diablo Canyon in its IRP proceeding, which focuses on assuring there’s enough capacity to keep the grid stable after the nuclear plant shuts down — and not on assuring that whatever mix of energy replaces it is equally carbon-free.

Unless some steps are taken to guarantee that there’s enough carbon-free energy to replace the 18,000 gigawatt-hours of energy per year that Diablo Canyon pumps out on average, ​“we could end up in a place where Diablo’s retirement increases greenhouse gas emissions,” Specht said. The graph below highlights that potential under the CPUC’s 46 MMT target, according to a Union of Concerned Scientists’ analysis.

This same capacity versus energy critique may apply more broadly to the CPUC’s proposed 5.5 GW of ​“all-source” procurement, Specht noted during the March 10 workshop. While the annual capacity additions will fall under the state’s loading Order, which requires that fossil-fueled generation be chosen only if no other carbon-free resources are available at a reasonable cost, that structure still ​“opens the door to gas procurement to meet the requirements as well,” he said.

CPUC’s Barcic replied that the CPUC’s proposed structure ​“should be sufficient to cover for a lot of generation that’s retiring, a lot of it that’s emitting, in ways that should reduce emissions, even though we’re not being specific about procurement.” Any fossil-fueled resources being chosen would face a steep regulatory hurdle to being allowed under the procurement, he added.

Barcic also pointed out that the CPUC lacks control over how resources are dispatched from day to day, which is largely a matter left to the markets and mechanisms managed by state grid operator CAISO. That limits the CPUC’s control over the emissions profile to come from whatever mix of resources power the grid, whether today or in years to come.

Specht and other clean energy groups concede that point. But they say this lends credence to arguments that the CPUC should target as low a carbon-emissions profile by 2030 as it can to make sure that emissions between now and then don’t end up increasing before they fall again.

There’s still an opportunity for the CPUC to order utilities, community choice aggregators and electric service providers to procure to the lower 38 MMT target, rather than the 46 MMT target once their individual IRPs are submitted later this year.

Geothermal, long-duration storage and transmission constraints

At the same time, the capacity value of adding more solar farms to the state’s resource mix is minimal, since grid demand peaks in the evenings after the sun goes down. Adding lithium-ion batteries with four to eight hours of storage capacity can shift solar power into those evening peak demand hours, making them the main choice for the 3.3 gigawatts of capacity being procured to meet the state’s needs through 2023.

But California regulators are looking for different types of carbon-free resources to cover the contingency of days or weeks when solar output is too low to supply batteries to carry the state through its evening peaks. That’s why the CPUC’s midterm procurement stakes out a first-ever mandate for two types of resources to supply long-term ​“baseload” power: geothermal power and long-duration storage.

California has about 2.5 gigawatts of geothermal power capacity today, most of it in the Geysers Geothermal Resource Area in Sonoma and Lake counties. Imperial County, in the state’s southeast corner, is a hotspot for new geothermal development, with an existing 325-megawatt fleet being targeted for major expansion, boosted by the promise of being able to extract lithium from the brine of the Salton Sea to supply battery production.

As for long-duration energy storage, last year the CPUC determined the need for at least 1 GW of it by 2026. While a multitude of in-development technologies could potentially meet that need, the most likely to be ready by mid-decade is pumped hydro storage. Pumping water uphill with cheap off-peak electricity, and then letting it fall to spin a turbine when power demand peaks, is a time-tested storage technology around the world, and it supplies about 1,600 megawatts in the state today.

There are two problems with new pumped hydro projects. First, they cost billions of dollars and take years to build, and can run afoul of environmental opposition, as is the case with the 2-gigawatt, $2.5 billion NextEra Energy-backed Eagle Mountain project. Another project proposed for the San Vicente reservoir in San Diego County hasn’t encountered the same environmental opposition, but it would still cost between $1 billion and $2 billion to complete.

The second challenge for pumped hydro projects is that they’re built to provide massive amounts of energy, but are very rarely constructed, largely as a last resort when other resources can’t be tapped. This requires multiple offtakers to sign power-purchase agreements that pledge to pay prices high enough to justify the upfront costs of building them in the first place. Bills that would have bolstered this business case via state mandates to purchase pumped storage power have failed to gain traction in the California legislature over the past few years.

The CPUC is proposing a joint procurement structure to guide these complex geothermal and long-duration storage procurements, CPUC energy regulatory analyst Neil Raffan noted during the March 10 workshop. It’s also setting 2025 as the target date for bringing them online, to give enough time for the complexities to be worked out.

Clean energy groups have largely praised the CPUC for including carve-outs for these resources in its plan. But they’re also worried about how to ensure they’re financed, built and interconnected to the grid in time.

“As we saw in Texas, we do need these weather-independent resources,” Vote Solar’s Smeloff said, referring to the Texas winter blackouts of February 2021. ​“I guess the question is at what cost, and can we do it by 2025?”

Beyond their cost and complexity, building the transmission grid capacity to bring these far-flung resources to where they’re needed may be another stumbling block, he noted. Transmission takes years to site, permit and build, and it is notoriously hard to move it from plan to reality.

Several participants in the March 10 workshop questioned whether the CPUC’s recent guidance to grid operator CAISO on how much transmission it should plan to build over the next five years was sufficient to ensure that the 7.5 GW of resources it’s calling for in this plan will be able to be interconnected to the grid by mid-decade.

“What’s scary is that if we’ve got solar, storage and maybe some wind that could otherwise participate in the procurement, but [which] can’t get interconnected because of these transmission backlogs, then we’re going to end up defaulting to gas,” CEERT’s White said.

(Article image courtesy of dirtsailor2003 via Flickr)