On Tuesday, the California Public Utilities Commission released a long-awaited proposal for mandating an unprecedented 1.3 gigawatts of energy storage to support the state’s power grid by decade’s end. Consider it a bold first step into the untested waters of combining new energy storage technologies, regulatory structures and economic models into a working whole.
The 81-page proposed decision [DOC] from CPUC Commissioner Carla J. Peterman breaks new ground in seeking to establish a regulatory regime in which utilities, third-party storage providers, and even customer-owned storage assets can play an integrated role. Those include rules that would limit utilities from owning more than 50 percent of the total amount of energy storage to be procured across the three “grid domains” of transmission, distribution, and customer-located storage.
That decision comes in spite of requests from the state’s three investor-owned utilities -- Southern California Edison, San Diego Gas & Electric and Pacific Gas & Electric -- that they be able to control a larger share of the storage they would be required to connect to their grids.
At the same time, the proposal also lays the groundwork for creating new ways for utilities and third-party storage owners to cooperate in paying for, and reaping the benefits of, these assets.
Specifically, the proposal calls for utilities to “consider all forms of resource ownership (utility-owned, third-party owned, customer-owned, joint ownership), including entering into contracts with customer-sited storage resources,” and further states that the utilities “may own storage assets in all three storage grid domains.”
“This is pretty significant, because they’re saying that utilities can even own assets behind the meter,” Janice Lin, executive director of the California Energy Storage Alliance (CESA), an industry group representing energy storage companies, said in a Tuesday interview. That’s largely unprecedented in today’s regulatory structures, but it’s of interest for utilities across the country seeking ways to incorporate customer-owned storage resources to help meet their grid needs.
And, while the CPUC proposal doesn’t shy away from the aggressive procurement goals it set in its preliminary proposal released in June [PDF], it would allow utilities to defer up to 80 percent of their required procurement targets to later periods -- if they can show they can’t procure enough “viable projects to meet the targets.”
Indeed, Peterman’s proposal makes it clear that the CPUC knows it’s asking the state’s utilities to do something that’s never been done before at such a scale. At the same time, the proposal specifically excludes pumped hydro storage projects of 50 megawatts or more -- the only storage technology with a proven track record of cost-effective, long term operation against natural gas-fired peaker plants -- from being considered for the mandate.
That leaves compressed-air energy storage (CAES), battery-based energy storage, thermal energy storage, fuel cells and other technologies to fill the gaps that remain. That’s in keeping with the spirit of the 2010 state law, Assembly Bill 2514, which originally called for the statewide energy storage mandate to enable a “market transformation” for these new technologies.
In broad terms, AB 2514 mandated energy storage to help reduce greenhouse gas emissions, integrate more intermittent solar and wind energy into the grid, manage peak power needs and defer expensive infrastructure upgrades. In more specific terms, meeting those goals requires energy storage that can fulfill a variety of functions, as this graph illustrates:
As for how utilities are to go about bidding for and procuring their required megawatts of energy storage, CPUC’s new proposal abandons the previous suggestion of a reverse auction mechanism (RAM) model based on how the state manages renewable energy procurements.
Instead, CPUC now calls for a “request for offer,” or RFO, process, which “enables the utilities to tailor a ‘targeted’ RFO to reflect their specific resource needs and criteria.” In simple terms, that’s because an auction model that works for procuring known quantities of energy from generation resources like wind and solar power doesn’t work for energy storage, which has “multiple attributes and functions that cross the spectrum of wholesale and retail markets and transmission & distribution grid services,” the proposal states.
As for how to evaluate the costs and benefits of various storage technologies, the new proposal lays out a two-fold process. First, it will build on cost-benefit calculations derived from energy storage evaluation software tools developed by the Electric Power Research Institute (EPRI) and by utility consultancy DNV Kema.
Second, it will ask the state’s big three utilities to work with the CPUC to create a “consistent evaluation protocol” that includes storage dispatch models that allow calculation of multiple benefits, as well as cross-comparisons to measure benefits like market services and avoided costs against project costs.Transforming the Existing Energy Storage Landscape
At the same time, CPUC’s proposal allows utilities to tap the energy storage projects they’ve already built, as long as they’ve been operating for at least a year, and meet the purposes of grid optimization, integration of renewable energy, or reduction of greenhouse gas emissions.
Those include Department of Energy smart grid stimulus grant-backed projects underway in the state, such as Southern California Edison’s 8-megawatt Tehachapi wind energy storage project and the Los Angeles Air Force Base’s electric vehicle-to-grid project, as well as PG&E’s megawatt-scale Vaca-Dixon Battery Project and Yerba Buena Battery Projects, which use sodium-sulfur batteries from Japan’s NGK and power electronics and controls systems from Chicago-based S&C Electric.
Other forms of energy storage can also be counted under the new proposal, as long as it meets those two key criteria. Some of these, such as the 35 megawatts or so of energy storage projects under the state’s self-generation incentive program (SGIP), have already been built, or are well on their way. Others, such as the 50 megawatts of storage-based capacity that CPUC ordered Southern California Edison to procure by 2020 in a ruling earlier this year, or the load-shifting resources called for in the CPUC’s new Permanent Load Shifting (PLS) Program [PDF], have yet to be installed.
AB 2514 doesn’t single out California’s investor-owned utilities, by the way. CPUC’s new proposal also lays out requirements for the state’s “electric service providers,” (ESPs) which supply energy to large commercial and industrial customers, as well as the “community choice aggregators,”(CCAs), or entities such as Marin County's Marin Energy Authority, that have formed their own distribution entities within the state’s existing infrastructure.
Each set of entities would need to procure energy storage equal to 1 percent of their annual peak load under the proposal, with a deadline of 2016 for ESPs and 2020 for CCAs. (Municipal utilities, which aren’t under the jurisdiction of the CPUC, are facing another set of AB 2514-mandated energy storage requirements under the auspices of the California Energy Commission.)
All of the uncertainties surrounding such an unprecedented buildup of energy storage will require the CPUC to remain flexible in how it implements its mandates. “We agree with parties that being overly prescriptive in a nascent market may have some unintended market consequences,” Tuesday’s proposal notes. “Consequently, we find that it is reasonable to adopt a broad framework initially and add additional details later, if necessary, as more experience is gained and lessons can be applied.”
As for the concern that California’s utilities are being asked to engage in what amounts to a grand experiment in energy storage, “The true test for cost-effectiveness will come once specific RFOs are issued, and bids come in, and utilities file an application,” CESA’s Lin noted.
At the same time, “AB 2514 is different from every other mandate California has issued -- it’s the only one that requires cost-effectiveness,” she added.