By Marc Campopiano, Neeraj Arora, Jared Johnson and Benjamin Gibson
The California Public Utilities Commission (CPUC) will require the state’s three large investor-owned utilities (IOUs) to invest in a combined 1,325 MW of energy storage by the end of 2020, the first-such mandate in the United States. The CPUC views increased deployment of energy storage as an important step towards a greater reliance on renewable energy to meet California’s electricity needs. Energy storage allows electricity generated during off peak periods to be used during peak periods. This is particularly useful in the context of intermittent renewables that may not be available during peak demand periods.
AB 2514 directed the CPUC to evaluate establishing a procurement program for energy storage. On October 17, 2013, the CPUC issued a decision requiring procurement targets for the years 2014-2020. Specifically, each investor-owned utility must meet the following increasingly stringent targets:
The first procurement cycle, including the first competitive solicitation, will occur on December 1, 2014. Additional procurement cycles will be held in 2016, 2018, and 2020. The CPUC decision directs each IOU, on or before March 1, 2014, and biennially thereafter in 2016, 2018 and 2020, to file a procurement application containing proposals for energy storage procurement. The procurement applications are to contain, among other things, updated procurement capacity targets and detailed descriptions of how each IOU intends to procure resources, e.g., specifying the structure of any Request for Offers (RFO) or related processes.
The capacity targets refer to storage pending contract, under contract, or installed after the end of each cycle. Southern California Edison (SCE) has included an energy storage component of at least 50 MW in its 2013 Local Capacity Requirements RFO, which was authorized pursuant to CPUC Decision 13-02-015.
For each procurement cycle, the investor-owned utilities must meet targets in each of three grid domains based on where the storage is connected to the grid: transmission-connected, distribution-connected, and customer-side. Examples of energy storage technologies for each of these domains includes but is not limited to:
- Transmission storage – hydroelectric pumped storage, compressed air energy storage, flywheels, and batteries either co-located with generation, sited alone to provide ancillary services or load following, or used to enhance reliability through voltage support.
- Distribution storage – batteries and flywheels deployed at substations or near distributed generation sources, such as solar photovoltaic systems.
- Customer storage – most commonly, batteries and thermal energy storage. Thermal energy storage can include making ice during off-peak hours for later use in cooling during time of peak electrical use. In the future, plug-in electric vehicles may be able to return electricity to the grid when not in use.
- Energy storage, as defined in California law, encompasses a variety of technologies, including batteries, flywheels, thermal energy storage, and hydroelectric pumped storage. Storage systems can be co-located with generation or placed locally on the distribution grid.
- Eligible projects are those that conform with Cal. Pub. Util. Code § 2835(a), including mechanical, chemical, or thermal systems that will: (1) reduce greenhouse gas emissions; (2) reduce demand for peak electrical generation; (3) defer or substitute an investment in generation, transmission or distribution assets; or (4) improve the reliable operation of the electrical grid.
- Hydroelectric pumped-storage projects of greater than 50 MW will not count toward the target.
- Storage projects currently planned will count toward targets, provided the project: (1) assists in grid optimization, integration of renewable energy, or reduction of greenhouse gas emissions; (2) is under contract or installed after January 1, 2010; and (3) is operational no later than the end of 2024.
- Existing CPUC programs such as the Self-Generation Incentive Program and Permanent Load Shifting program will count toward the customer storage target.
- Up to 80 percent of the MWs of a target may be shifted between the transmission and distribution (T&D) domains. No shifting is allowed between T&D and the customer-side domain.
- A utility may defer up to 80 percent of its target to later procurement periods if the utility shows that it cannot procure enough operationally or economically viable projects to meet the target. As a result, the utilities may postpone a large portion of their procurement obligations to later procurement periods as the relevant technology matures and becomes cheaper.
- If a utility exceeds its target in one cycle, the utility may reduce the next cycle’s target by the excess amount.
- A utility may not own more than 50% of the storage projects proposed to count toward the MW target.
- Utility-owned storage systems must go through a competitive solicitation process.
Procurement Mechanism for Transmission & Distribution Projects
- Solicitations are recommended, but not required, to be in the form of an RFO.
- There is no requirement for a standard contract; each Power Purchase Agreement can be negotiated individually.
- All contracts are contingent on CPUC approval.
- Electric Service Providers (ESPs) and Community Choice Aggregators (CCAs) must also procure energy storage. An ESP is a non-utility entity that offers service to customers within the service territory of an electric utility; a CCA is a local government or group of governments that separately procures electricity for its residents but uses utility infrastructure (e.g., CleanPower SF, Marin Energy Authority, San Joaquin Valley Power Authority).
- ESPs and CCAs must meet 1 percent of the 2020 annual peak load with a requirement for project installation by the end of 2024.
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