While it was first celebrated as a high water mark for energy storage, Soutnern California Edison's (SCE) most recent capacity planning proposal has attracted opposition from some renewables and efficiency advocates for another resource it plans to procure — natural gas generation. 

Last winter, SCE situated itself as one of the most bullish utilities in the nation when it comes to storage, procuring more than 260 MW of it in one swoop. State laws mandating storage adoption from the utility sector compelled it to purchase 50 MW at the time, but the utility said the storage resources compared favorably with other generation in the company’s cost estimates.

That move earned the utility praise from many in the sector and encouraged clean energy advocates that storage could be closer than expected to competing with traditional generation resources, like natural gas peakers. But in the months since, as it became clear that SCE also planned to buy 1,382 MW of natural gas generation as a part of its plan, some parties have criticized the utility, arguing its desire for new fossil fuels undercuts its stated commitment to clean energy.

In fact, Edison and other stakeholders say, the matter goes deeper than that – to the core of how utilities in California calculate their needs for the purposes of long-term planning.

SCE’s capacity planning

SCE’s plans to procure both gas-fired generation and energy storage stem from the same process, the local capacity requirement request for offers (LCR-RFO) through which California utilities procure the capacity to meet the expected needs of their electricity customers.

In this case, the utility was seeking to put in place as much as 2,790 MW of resources in the western Los Angeles and Moorpark areas of the Los Angeles basin by 2021.

The LCR-RFO was looking to fill expected needs and to fill the gap left by the retirement of the 2,160 MW San Onofre Nuclear Generating Station (SONGS) and the expected retirement of several thousand megawatts of coastal power plants affected by new water-use rules regulating once through cooling.

The RFO was novel in that it aimed to compare a diverse set of resources – including storage, demand side management, and natural gas peakers – on a level playing field. It was, SCE President Pedro Pizarro told Utility Dive in September, the first time to the utility’s knowledge planning had been done in such a holistic way.

“This LCR-RFO picked up some solar, picked up some storage from batteries, picked up some ice storage, it picked up some demand response resources and some natural gas-fired resources,” Pizarro said. “So, it was an umbrella that allowed us to compare and contrast and make decisions across all technologies.”

SCE spokesman Robert Villegas noted that SONGS capacity is not being replaced on a megawatt-for-megawatt basis because some of that need has been reduced by energy efficiency measures.

He also noted that while storage beat generation in head-to-head cost comparisons in some instances in the LCR-RFO, it did not prevail in others. Storage’s success was largely attributable to location. It won in high population density areas where generation would face expensive siting challenges.

Through the LCR-RFO process – authorized in two separate Public Utilities Commission proposed decisions, D.13-02-015 and D.14-03-004 – SCE agreed to procure 2,220 MW by 2021, comprised of 261 MW of storage, 1,698 MW of gas-fired generation, 50 MW of renewables, 136 MW of energy efficiency, and 75 MW of demand response resources.

The contracts require PUC approval, but the commission has proposed an alternate decision and has deferred a vote on both items until later this month.

PUC decisions and stakeholder unrest

Both the alternate and original proposed decisions would exclude seven contracts with NRG Energy for a total of 75 MW of resources classified as a demand response (DR). But the alternate proposed decision goes a step further. In it, Commissioner Mike Florio seeks to exclude the NRG contracts because they rely on gas-fired generation to reduce energy served by the grid and, therefore, he says, should not constitute demand response.

In addition, unlike the proposed decision, the alternate proposed decision would authorize SCE to replace the NRG contracts with preferred, i.e., renewable resources.

It is here that the numbers start to get interesting.

In a filing protesting the results of the LCR-RFO, demand response provider EnerNOC argues that SCE shortchanged DR in the solicitation.

EnerNOC adds back the 75 MW of resources awarded to NRG and adds another 99-MW deficit – one that EnerNOC says SCE concedes should have been in the original LCR-RFO – to arrive at 174 MW that should be preferred resources in the LCR-RFO.

EnerNOC then looks at the energy storage contracts awarded by SCE. The minimum storage requirement in the LCR-RFO was 50 MW, and EnerNOC says SCE exceeded that by 214 MW. But that extra storage, it argues, should not be counted toward the utility’s obligations to purchase preferred resources like renewables and DR, since storage has its own mandate from regulators.

Adding that sum to the 174 MW, EnerNOC comes up with a preferred resource shortfall of 388 MW, compared to a 600 MW for preferred resources mandated by regulators in the proceeding to replace San Onofre capacity.

EnerNOC says the fact that neither the proposed nor alternative decisions view the shortfall as a “significant failure,” is a situation to which the company “strongly disagrees as a matter of fact and law.”

In a filing countering EnerNOC’s claims, SCE says that EnerNOC’s arguments are “the equivalent of procurement for the sake of procurement,” without regard for the costs that would be imposed on its customers.

Buying storage: Now or later?

In a separate filing, Bill Powers of Powers Engineering focused in on the same issue, but from a different angle. In an interview, Powers acknowledged that EnerNOC “was completely shut out of this proceeding,” but also noted that SCE is obliged under California law to procure 580 MW of storage by 2020.

Powers says SCE should have allocated the full complement of 580 MW, instead of just the 260 MW.

By leaving out the remaining 320 MW that will be required by 2020, Powers says SCE is, in essence, conceding that capacity to other resources, such as the award of nearly 1,700 MW of gas-fired generation.

If the allocation for storage is held for a later LCR-RFO, Powers argues the need for the storage may no longer be extant, in part because the need will have been filled by the new generation resources.

Underlying all these issues is what Powers calls the use of “obsolete demand forecasts” in the LCR-RFO process. He claims that the California Independent System Operator (CAISO) has been given de facto control over the process and that the PUC has let it advocacy role atrophy.

Powers stresses that electricity demand in California is flat because of the success of advances in energy efficiency and demand response, but the utilities, the ISO, and the PUC have not caught up with that fact. “Even in the middle of August we have 40% reserve margins,” he says.

SCE, for its part, maintains that its procurements in the LCR-RFO are the most cost effective way to meet customer needs given the constraints of its generation and storage mandates.

The CPUC is slated to vote on the proposed and alternative decisions on Nov. 19.