Early last year, California utility San Diego Gas & Electric launched a community microgrid project, meant not only to boost the state’s adoption of energy storage, but to serve as the next step in its wildfire prevention efforts — an increasingly important part of the utility mission in a state ravaged by wildfires.

But in recent months, SDG&E’s plan to build 100 megawatts of battery-backed microgrids across rural San Diego County hit a snag. State regulators proposed sending these energy storage opportunities back to the drawing board, so that they can be opened to competition from third parties. 

The conflict at the California Public Utilities Commission (CPUC) underscores the competing pressures facing utilities as they seek to implement the state’s energy storage mandates. The best-known of these is 2010 bill AB 2514, which created the 1.3-gigawatt energy storage mandate for the state’s three investor-owned utilities, SDG&E, Pacific Gas & Electric and Southern California Edison, and demanded that roughly half of the projects be built and owned by third parties, not the utilities themselves. 

But the SDG&E microgrid program was developed under 2016 state law AB 2868. That law called for the state’s investor-owned utilities to procure an additional 500 megawatts of energy storage, specifically distribution grid-connected or behind-the-meter batteries, with an initial round of proposals due last year. 

SDG&E’s proposal (PDF) was by far the largest to emerge, with plans for up to 100 megawatts of battery systems spread across seven different community microgrids. Its first three projects — a 30-megawatt/40-megawatt-hour system in San Diego, a 20-megawatt/20-megawatt-hour system in Vista, and a 10-megawatt/10-megawatt-hour system in Boulevard — have already been contracted out, and were set to start construction by early 2020. 

But in a February proposed decision, CPUC administrative law judge Brian Stevens rejected SDG&E’s project, along with most of the other AB 2868 projects proposed by the state’s other investor-owned utilities, on the grounds that they should have been open to third-party solicitations. Stevens cited testimony from The Utility Reform Network and the CPUC’s Public Advocates Office that noted that AB 2514’s third-party requirements should apply to the AB 2868 projects. 

It also cited complaints from LS Power, a generation and transmission developer and demand response provider that’s building a 40-megawatt transmission connected energy storage project near Vista, that SDG&E had failed to consider third-party-operated microgrids to perform the same resiliency tasks that it plans to take on itself.

“We are compelled by LS Power’s analysis that it would be unreasonable for SDG&E to restrict the RFO to only utility owned projects or to projects located on utility-owned property,” Stevens wrote. 

According to SDG&E, this decision is wrong on several levels.

First, the utility says it incorrectly applies AB 2514’s mandate for third-party competition to the separate mandates established by AB 2868. Second, it ignores the “community and industry support for, and wildfire protection benefits of, SDG&E’s projects.” 

Utilities vs. third parties

SDG&E has invested more than $1.5 billion in state-of-the-art fire prevention technology and programs, putting it ahead of the state’s other utilities in this regard. That includes its use of public safety power shutoffs, or de-energizing power lines to prevent them from sparking wildfires — a practice that will be dramatically expanded this year, in hopes of preventing another utility-caused wildfire. Last year’s Camp Fire, the state’s deadliest to date, drove PG&E into bankruptcy. 

“The reason we’re so far ahead right now is we’ve been building this meteorology and fire science discipline, and doing de-energization, since the 2007 fire season,” Michael Schneider, SDG&E vice president of clean transportation and asset management, said in an interview last week.

With the SB 2868 projects, “we want to do the same things with storage," Schneider said.

In fact, the seven microgrid projects were selected specifically because they represent “currently underserved markets with little potential for third parties to monetize,” SDG&E noted in its reply comments to the CPUC's proposed decision.

That’s a view supported by the California Energy Storage Association (CESA), which said during an early AB 2868 workshop that the bill’s key benefit compared to AB 2514 was to “explore storage-related solutions to grid problems that may not currently have monetizable benefit streams.”

SDG&E noted that both CESA and Fluence, the joint venture of Siemens and AES Energy Storage, have filed comments with the CPUC in support of continuing on with the three projects for which contracts have been executed, and that Tesla’s filing supports SDG&E’s proposal in its entirety.

Rather than limiting the third-party energy storage market, SDG&E's resiliency projects provide additional market opportunities that non-utility entities cannot monetize, the utility argued.

SDG&E’s microgrid projects, expected to cost about $285 million in total, will provide “emergency resiliency support” to public sector facilities including eight fire stations, the county’s Emergency Operations Center, state and county law enforcement offices, and “several other facilities critical to emergency wildfire response,” it notes.

Unlike typical backup systems that merely power an individual building, SDG&E’s microgrids will power the grid circuits serving several buildings — an important distinction, and one that requires utility-grade expertise to manage, Schneider said. In fact, “this particular use case is not a use case we believe third parties should be in,” he said. 

SDG&E’s experience with battling wildfires shows that “these events are very fluid. You have no idea where you’re going to have to de-energize next until things unfold” — a situation that’s difficult enough for SDG&E to manage, let alone to coordinate with third-party-operated microgrids.

SDG&E’s critics have suggested that its projects’ batteries were oversized compared to the loads they’re serving. But Schneider said that’s meant to offer the communities involved the option to power down all but essential systems, and use the extra capacity to keep the facility running for much longer, as might be necessary during a multiday emergency. 

The administrative law judge's proposed decision has yet to be voted on by the five-member CPUC commission, which has postponed taking up the issue during its last three meetings, and could take it up as early as next week.

Schneider said that SDG&E is “hoping the commission will have a change of heart” and lay out an alternative proposal that will allow the utility to build some, or all, of its existing microgrids according to plan. 

If, on the other hand, the CPUC approves the the administrative law judge's proposed decision, “it wouldn’t necessarily undermine these projects, but it would put them into a competitive bidding process” that could prevent them from being built and in place for the next fire season, he said.

“We had already negotiated very favorable terms with our suppliers on three of the projects. This proposed decision puts the brakes on everything.”  

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