Dive Brief:
- California utility regulators late last month ordered the state’s three major investor-owned utilities to jointly propose a common framework for orchestrating distributed energy resources like customer-sited batteries and electric vehicles.
- The proposed framework is due in October 2027. It should allow coordinated measurement, forecasting and scheduling of DER load and dispatch to meet location- and time-specific distribution-level needs across the state, the California Public Utilities Commission said on Oct. 29.
- The CPUC’s order came shortly after California enacted a law, SB 913, to significantly expand DERs’ role in wholesale energy markets and resource adequacy planning. Advocates and industry leaders say the law could help address California’s utility“ affordability crisis,” depending on how it is implemented by the CPUC and the California Independent System Operator.
Dive Insight:
The order aims to harness DERs to meet local electricity needs, support grid reliability, reduce or defer infrastructure upgrades, and advance California’s electrification and decarbonization goals, the CPUC said.
“Our decision moves the state toward a common framework for the utilities to manage and forecast DERs on our system, and create visibility for the California Independent System Operator,” CPUC Commissioner Darcie Houck said in a statement.
The order gives Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric one year to develop a joint DER orchestration proposal that meets dozens of CPUC requirements, including “open and interoperable” communication; data sharing; cybersecurity; ratepayer protections; clear customer participation pathways; recognizing locational and temporal value; and avoiding double compensation for DER owners.
The framework will be developed in a working group process that considers input from stakeholders representing ratepayers, energy service providers, community choice aggregators and others. The process will establish “a common set of rules and policies across California” that the utilities would implement over time based on technological readiness, the CPUC said.
The working group must consider a range of technical, market and customer-facing issues related to DER orchestration, including methodologies for assessing cost-effectiveness and cost-benefit balance; DERs’ visibility to distribution system operators; DER aggregators’ role; technology ownership; flexible dispatch; “fair and non-discriminatory participation” for both utility and non-utility DER providers; and performance measurement, monitoring and accountability, according to the CPUC’s order.
Separately, the CPUC ordered utilities to evaluate how flexible electric loads can mitigate grid constraints and advance electrification as DERs become more common on California’s grid. Like standardized DER orchestration, planning scenarios that contemplate load flexibility may also help reduce burdens on ratepayers, the commission said.
Planning scenarios that “more explicitly” account for flexible demand will complement existing demand planning scenarios and focus on how dynamic changes in electric load — from shifting electric vehicle charging times or charging and discharging stationary batteries — could affect the timing, size and need for grid upgrades, the CPUC said.
In a statement, CPUC Commissioner Christine Harada said the order would help California utilities make “better use of the grid we already have,” reduce interconnection delays and avoid costly system upgrades. It would also make it easier for homes and businesses to electrify, she said.
“Our decision gives families and businesses more options to charge a car, electrify a home, or expand operations while reducing the need for costly upgrades. Those options need to be easy to understand and easy to use, people shouldn’t need an engineering degree to benefit,” Harada said.
