Faced with the onset of another wildfire season, and seeking to avoid both the prospect of utility-caused wildfires and the impacts of utilities’ Public Safety Power Shutoffs (PSPS) to avoid them, the California Public Utilities Commission (CPUC) recently took wide-ranging actions to expand the penetration of microgrids in California and enhance reliability and resilience of electric service. The decision partially implements Senate Bill 1339 (SB 1339) and the CPUC’s related three part rulemaking (Rulemaking 19-09-009). The CPUC’s decision focuses on behind the meter applications and directs California’s large Investor Owned Utilities (IOUs) to, among other things, develop standardized pre-approved system designs for interconnections, create methodologies to simplify utility inspections of proposed projects, and remove electric energy storage size restrictions from IOUs’ net metering tariffs.
The CPUC’s decision promotes development and interconnection of microgrids with utility systems and encourages the development of behind the meter storage. It is the CPUC’s first step in a three track process implementing Senate Bill 1339 SB 1339 required the CPUC to, in concert with the California Energy Resources Conservation and Development Commission (CEC) and California Independent System Operator (CAISO), develop microgrid standards and generally reduce barriers to microgrid deployment. SB 1339 defined a “Microgrid” as an
interconnected system of loads and energy resources, including, but not limited to, distributed energy resources, energy storage, demand response tools, or other management, forecasting, and analytical tools, appropriately sized to meet customer needs, within a clearly defined electrical boundary that can act as a single, controllable entity, and can connect to, disconnect from, or run in parallel with, larger portions of the electrical grid, or can be managed and isolated to withstand larger disturbances and maintain electrical supply to connected critical infrastructure.
Consistent with the state’s focus on renewable development, the statute discourages the use of diesel back up generators in Microgrids.
The CPUC’s decision, part of a longer implementation process, requires public input, followed by conforming tariff changes and compliance reports to identify progress in implementation.
In the public meetings, SDG&E, PG&E, and SCE must propose and review pre-approved uniform single line microgrid interconnection diagrams, thus expediting interconnection of Microgrids. Further, the three utilities must develop templates for applications for interconnection of three types of Microgrids:
- Distribution level interconnection of storage equipment with < 10 kW of capacity that will not export to the grid;
- Storage systems that are incorporated into net metered systems of < 30 kW of solar and <10 kW of storage; and
- Net metered solar systems of <30 kW.
In addition, the CPUC required the three utilities to submit tariffs for approval concerning:
- Safety and reliability technical criteria for determining when Microgrid installations need field inspections ; and
- The process that utilities will use for accepting video or other photographic evidence in lieu (“virtual inspections”) of an in-person inspection.
The CPUC required the utilities to update their technical documents and handbooks to provide examples of project types for which utilities expect to allow virtual inspections.
To implement this process, the CPUC authorized the utilities to hire additional staff and information technology resources to their interconnection study and distribution upgrade teams.
In addition to the above process, the CPUC required SDG&E, PG&E, and SCE to file tariffs allowing customers with Microgrid systems to charge their battery systems from the grid in advance of a noticed PSPS event and to remove the size limit on battery systems charged by solar generators in their respective net metering tariffs. Previously, the discharge capacity of such net-metered storage was not permitted to exceed the net metered generator’s maximum capacity, and the maximum energy discharged by the storage device could not exceed 12.5 hours of storage per kW.
The CPUC ordered the utilities to meet with affected municipal and tribal governments to provide greater transparency on grid operations. The meetings are to include:
education about, at a minimum, how the electric transmission system and distribution system operates in the area, local grid topology and circuit configuration, electric transmission and distribution infrastructure investment and operational plans, weather and climatology analysis predictions for future PSPS events, predictive scenarios, and a reflection on local and tribal government input.
The utilities also must identify opportunities for greater governmental input and participation, such as an “access-restricted portal” to information on additional “in front of the meter microgrid development opportunities.”
Finally, the CPUC addressed several elements of the wildfire preparation plans prepared by PG&E. In particular, the CPUC approved several measures for preparedness, but limited its approval to the 2020 wildfire season. These plans allow “mobile, temporarily-sited distributed generation at substations, mid-feeder line segments serving commercial corridors and commercial facilities, and backup power support for societal continuity during PSPS events, including backup power for Community Resource Centers.” The CPUC temporarily allowed PG&E to use mobile, distributed, diesel generation, subject to reporting on PG&E’s need for, and usage of, diesel generation.
The timetable for implementation of each element of the CPUC’s decision varies between 30 and 60 days. The CPUC has not yet issued a schedule regarding Tracks 2 and 3 of the Rulemaking proceeding.