California has just taken a big step forward in making grid-scale energy storage on a truly massive scale a reality. On Monday, the California Public Utilities Commission released a proposal (PDF) that would call for the state’s big three investor-owned utilities to procure 1.3 gigawatts of energy storage by decade’s end, along with market mechanisms to start the procurement process as early as next year.
The assigned commissioner ruling from CPUC Commissioner Carla J. Peterman is the result of a process that started in 2010 with the passage of California Assembly Bill 2514, the first state law calling for grid-scale energy storage. Last year, the CPUC took up the challenge of figuring out how much storage, in what forms, would meet the law’s goals, as well as how to incorporate it into the state’s existing energy and utility economic and regulatory structures.
Monday’s procurement targets go a long way toward defining those metrics, breaking down year-by-year targets for Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric across three categories -- transmission, distribution and customer-facing storage deployments -- meant to address a host of grid and energy management needs.
It also proposes a “reverse auction” market mechanism, similar to its Renewable Auction Mechanism (RAM) for wind, solar and other renewable power, to incorporate energy storage into the transmission and system-wide procurement and planning process, as well as new distribution system planning mechanisms and customer incentive programs. The first auction, to be held in June 2014, will ask the three IOUs to procure a collective 200 megawatts of storage, quite a bit more than what they’ve got today.
At the same time, it’s still a proposal, and the three utilities involved will be sure to be weighing in, as they have throughout the process. Let’s break down what’s at stake.
1) First, in terms of total megawatts, the CPUC’s proposal goes pretty far in establishing the state as a leader in energy storage for the grid -- and sets some pretty quick deadlines to meet as well. As the chart below indicates, the CPUC wants the state’s big three utilities to start procuring storage resources next year, and then keep increasing that amount by roughly one-third every two years, to meet its 2020 goals.
California Assembly Member Nancy Skinner (D-Berkeley), author of AB 2514, originally included a mandate that the state procure enough energy storage by 2020 to meet 5 percent of its average peak load. Measured against the state’s 2010 peak load of 47,350 megawatts (PDF), that would have added up to 2,367 megawatts of energy storage, or nearly twice the 2020 total of 1,325 megawatts that the CPUC’s proposal calls for.
Still, the state’s big three utilities have a lot of work to do to meet these goals. All three IOUs have but a fraction of the proposed amounts of energy storage they’ll need to procure in 2014, for example. Of course, because these mandates are for procurement of resources, that means that projects still on the drawing boards can count for biannual targets -- “Winning projects would be given a reasonable amount of time in which to be constructed and interconnected, but would not necessarily be complete before the next auction would take place,” Peterman wrote.
2) There are plenty of energy storage projects of every description that will count toward the CPUC’s proposed targets. Commissioner Peterman lists a series of statewide storage projects that could be included under the “various mechanisms and proceedings” that the CPUC has “authorized or is considering authorizing…for commercialized energy storage projects.”
Those include many of the 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; PG&E’s power purchase agreement with SolarReserve for a solar-thermal power project incorporating molten salt energy storage; and San Diego Gas & Electric’s Borrego Springs microgrid project’s community energy storage systems from S&C Electric (PDF) and parent company Sempra Energy’s general rate case proposal for 44.8 megawatts of energy storage for distribution system support.
It also includes various regulatory structures and mandates for energy storage in the state, including CPUC’s ruling earlier this year that asks SCE to procure 50 megawatts of storage-based capacity for the Los Angeles basin by 2020, or the up to 35 megawatts of energy storage projects under the existing self-generation incentive program (SGIP), which pays customers for on-site energy generation or storage.
Last week, the CPUC instituted a new program (PDF) that’s also included in Commissioner Peterman’s list. It’s called Permanent Load Shifting (PLS), and would provide $32 million in incentives of $875 per kilowatt, up to a maximum of $1.5 million per project, for storage systems that “permanently” move a building’s demand from hot afternoon peak times to other times. That could open up new revenue streams for thermal storage projects from the likes of CALMAC and Ice Energy, as well as other forms of storage. Under last week’s CPUC filing, the state’s big three utilities have 90 days to come up with plans to meet the new program requirements.
As for the host of other statewide grid energy storage projects funded by the California Energy Commission’s previous Public Interest Energy Research (PIER) program, as well as new projects under CEC’s EPIC program, “The primary purpose of both programs is technology development or demonstration, not commercial deployment,” Peterman write. “At this stage, I propose that any PIER- or EPIC-funded projects shall only count toward the procurement targets set in this proceeding if a load-serving entity subject to AB 2514 is a financial partner in the project, and the project reaches actual operations and can be shown to meet one of the three purposes set out here."
3) Market mechanisms will be a key part of what’s to come. “This ACR suggests procurement targets for energy storage with the goal of market transformation,” Commissioner Peterman wrote in Monday’s ruling. “The hoped-for result is that when the energy storage market becomes sustainable, procurement targets for storage will no longer be needed and it will compete to provide services alongside other types of resources.”
To get there, the CPUC is proposing different mechanisms across three broad categories of transmission-grid support, distribution system support, and customer-side storage deployments, as well as a list of 21 end uses for storage within different components of the grid, ranging from “black start” support and ancillary services for state grid operator Cal-ISO to outage mitigation and backup power for end users.
Each of those categories will also include different market mechanisms to incorporate energy storage’s capabilities into the state’s energy system. For transmission-scale storage, “I propose that the utilities hold a reverse auction, similar to the Commission’s Renewables Auction Mechanism (RAM),” Peterman writes. Under that plan, projects are able to bid their costs and be paid over the life of the contract, while future winning bid prices “adjust over time as the IOUs learn more about the projects, the storage market develops, and the Commission and the CAISO continue to assess the storage needs for the state.”
Monday’s proposal provides much less detail on mechanisms aimed specifically at distribution grid and customer energy storage, though it does mention “a requirement to include energy storage alternatives in distribution system planning” as part of its list of potential methods. California has set a 33 percent renewable energy target for 2020, and is looking to storage to help manage and mitigate the intermittent nature of that power, whether from massive wind farms or thousands of rooftop solar panels.
Praveen Kathpal, vice president of market and regulatory affairs for AES Energy Storage, the storage subsidiary of U.S. energy giant AES, said that Monday’s ruling leaves much yet to be worked out in how the program will run. “Whatever the right mechanism is will shake out in the stakeholder process,” he said in a Monday interview.
“At the end,” however, “one of those barriers that has inadvertently been erected over the years will be addressed,” he said. “There are established ways for utilities to procure power resources, and we’re just introducing storage into that equation.” AES serves California with both traditional (natural gas-fired) and renewable energy, and is watching developments on the energy storage front as well, Kathpal said.
Janice Lin, executive director of the California Energy Storage Alliance trade group, noted that Monday’s ruling also emphasizes that storage technologies must be cost-effective and commercially feasible. Of course, in the absence of rules and markets that can incorporate energy storage’s unique capabilities into the flow of energy and money across the state on a day-by-day, year-by-year basis, it’s been hard to prove whether or not that’s the case, she added. That’s something that the CPUC process is meant to help resolve, she said.
Meanwhile, there’s a whole universe of California energy storage projects that will want to be added to the mix. PG&E is building a DOE grant-backed, 300-megawatt, 10-hour compressed air energy storage (CAES) system in the Central Valley, and has several megawatt-scale storage projects using sodium-sulfur batteries from Japan’s NGK and power electronics and controls systems from Chicago-based S&C Electric Company. We’re also seeing distributed energy storage emerge in the state, with everything from backyard or garage batteries to backup solar installations (Tesla and SolarCity, Silent Power and Hanwha) to substation-scale grid balancing units in the 1-2 megawatt range (Greensmith and SDG&E), to name a few examples.