Existing law requires the Public Utilities Commission to determine appropriate targets, if any, for each load-serving entity, as defined, to procure viable and cost-effective energy storage systems to be achieved by December 31, 2020. Existing law requires the commission to direct the states 3 largest electrical corporations to file applications for programs and investments to accelerate widespread deployment of distributed energy storage systems.

This bill would require an electrical corporation, for any proposed distribution or transmission infrastructure investment above a threshold established by the commission, as part of the distribution planning process, to evaluate whether distributed energy storage systems or other nonwire alternatives can meet the identified reliability or capacity need, as provided. The bill would require an electrical corporation, if it determines that a nonwire third-party alternative may be feasible, to conduct a competitive solicitation or other transparent process to evaluate third-party solutions. The bill would prohibit the commission from approving rate recovery for a proposed infrastructure investment unless the electrical corporation demonstrates either that nonwire alternatives are not feasible within the required timeframe or that nonwire alternatives are not cost effective, as provided. The bill would authorize an electrical corporation to procure, own, or enter into a long-term contract for distributed energy storage systems interconnected at the distribution level to meet identified reliability or capacity needs, and would require the commission to authorize an electrical corporation to recover the reasonable costs of, and earn a return on, those distributed energy storage systems, as provided.

Under existing law, a violation of the Public Utilities Act or of any order, decision, rule, direction, demand, or requirement of the commission is a crime.

Because the provisions of this bill would be part of the act, and a violation of a commission action implementing the bills requirements would be a crime, this bill would impose a state-mandated local program.

The California Constitution requires the state to reimburse local agencies and school districts for certain costs mandated by the state. Statutory provisions establish procedures for making that reimbursement.

This bill would provide that no reimbursement is required by this act for a specified reason.

Existing law requires the Public Utilities Commission (PUC) to determine appropriate targets, if any, for each load-serving entity, as defined, to procure viable and cost-effective energy storage systems to be achieved by December 31, 2020. Existing law requires the PUC commission to direct the states 3 largest electrical corporations to file applications for programs and investments to accelerate widespread deployment of distributed energy storage systems.

Under existing law, a violation of the Public Utilities Act or of any order, decision, rule, direction, demand, or requirement of the PUC commission is a crime.

Because certain the provisions of this bill would be part of the act, and a violation of a PUC commission action implementing the bills requirements would be a crime, this bill would impose a state-mandated local program.

The California Constitution requires the state to reimburse local agencies and school districts for certain costs mandated by the state. Statutory provisions establish procedures for making that reimbursement.

This bill would provide that no reimbursement is required by this act for a specified reason.

Existing law requires the Public Utilities Commission (PUC) to determine appropriate targets, if any, for each load-serving entity, as defined, to procure viable and cost-effective energy storage systems to be achieved by December 31, 2020. Existing law requires the commission PUC to direct the states 3 largest electrical corporations to file applications for programs and investments to accelerate widespread deployment of distributed energy storage systems.

This bill would require the commission, PUC, in addition to the requirements described above, on or before January 1, 2030, to consider procurement strategies for the installation of a statewide total of up to 40,000 megawatts of energy storage systems. to support the installation of distributed energy storage systems, as provided. The bill would require the State Energy Resources Conservation and Development Commission, in consultation with the PUC and the Independent System Operator, on or before July 1, 2028, and biennially thereafter, to identify and evaluate constrained distribution areas, as defined, and local capacity areas, as defined, for those purposes, as provided. As part of the procurement strategies considered by the commission, PUC, the bill would require the commission to consider appropriate targets, if any, for PUC to require each load-serving entities to procure viable and cost-effective energy storage systems, to be achieved on or before December 31, 2040. entity to demonstrate that identified localized reliability vulnerability areas will be addressed within a reasonable planning horizon and using the least-cost portfolio of resources, including distributed energy storage systems and other nonwire alternatives, as specified. If the commission PUC imposes an energy storage system procurement target on load-serving entities, the bill would authorize each load-serving entity to meet up to 50% of its procurement target through energy storage systems that it owns, that are interconnected at the transmission or distribution level, or that are located on the customer side of the meter, as specified. The bill would require the commission PUC to reconsider procurement strategies and appropriate targets not less than once every 3 years. The bill would authorize the PUC to approve, or modify and approve, electrical corporation programs to deploy, and investments in, distributed energy storage systems that include appropriate energy storage management systems and reasonable mechanisms for cost recovery. The bill would require the PUC, on or before January 1, 2028, to amend its tariffs that govern the deployment of energy storage systems, as provided. The bill would require the PUC to authorize an electrical corporation to earn a return on investments in and operation of distributed energy storage systems and other nonwire alternatives deployed to address localized reliability vulnerability areas. The bill would require the commission to establish performance-based mechanisms that allow an electrical corporation to earn incentives for achieving measurable outcomes, including, but not limited to, integration of cost-effective distributed energy resources, as provided.

Under existing law, a violation of the Public Utilities Act or of any order, decision, rule, direction, demand, or requirement of the commission PUC is a crime.

Because certain provisions of this bill would be part of the act, and a violation of a commission PUC action implementing the bills requirements would be a crime, this bill would impose a state-mandated local program.

The California Constitution requires the state to reimburse local agencies and school districts for certain costs mandated by the state. Statutory provisions establish procedures for making that reimbursement.

This bill would provide that no reimbursement is required by this act for a specified reason.

Existing law requires the Public Utilities Commission to determine appropriate targets, if any, for each load-serving entity, as defined, to procure viable and cost-effective energy storage systems to be achieved by December 31, 2020. Existing law requires the commission to direct the states 3 largest electrical corporations to file applications for programs and investments to accelerate widespread deployment of distributed energy storage systems.

This bill would require the commission, in addition to the requirements described above, on or before January 1, 2030, to consider procurement strategies for the installation of a statewide total of up to 40,000 megawatts of energy storage systems. As part of the procurement strategies considered by the commission, the bill would require the commission to consider appropriate targets, if any, for load-serving entities to procure viable and cost-effective energy storage systems, to be achieved on or before December 31, 2040. If the commission imposes an energy storage system procurement target on load-serving entities, the bill would authorize each load-serving entity to meet up to 50% of its procurement target through energy storage systems that it owns, that are interconnected at the transmission or distribution level, or that are located on the customer side of the meter, as specified. The bill would require the commission to reconsider procurement strategies and appropriate targets not less than once every 3 years.

Under existing law, a violation of any order, decision, rule, direction, demand, or requirement of the commission is a crime.

Because a violation of a commission action implementing the bills requirements would be a crime, this bill would impose a state-mandated local program.

The California Constitution requires the state to reimburse local agencies and school districts for certain costs mandated by the state. Statutory provisions establish procedures for making that reimbursement.

This bill would provide that no reimbursement is required by this act for a specified reason.

Date of Hearing: August 5, 2026

ASSEMBLY COMMITTEE ON APPROPRIATIONS

Buffy Wicks, Chair

SBPCA Bill Id:SB 1295

Author:(Stern) – As Amended Ver:June 29, 2026

Urgency: No State Mandated Local Program: Yes Reimbursable: No

SUMMARY:

This bill directs each electrical corporation (also known as an investor-owned utility (IOU)), as part of the distribution planning process, to evaluate, as specified, whether distributed energy storage systems, such as batteries, can meet identified reliability or capacity need.

FISCAL EFFECT:

As the regulator of IOU rates and service, the California Public Utilities Commission (CPUC) will need to oversee the evaluation this bill requires of the IOUs. Costs will likely be significant.

The CPUC estimates it will face costs of $1.4 million annually ongoing (Public Utilities Commission Utilities Reimbursement Account) to fund two positions—a utilities engineer ($209,000 annually) and an analyst ($160,000 annually)—and $1 million annually for a contract with an external engineering consultant, as well as $45,000 annually in travel, equipment and other miscellaneous costs.

The CPUC describes the work to be done by the staff positions as undertaking a rulemaking and, following the rulemaking, ongoing review and validation of IOU filings, overseeing new reporting requirements, annual reviews of project deferrals and overseeing IOU solicitations of third-party distributed energy resources. In addition, the CPUC describes the outside engineering contract as establishing a new framework for IOU analysis and reporting to determine which capacity projects can be deferred through non-wires alternatives and supporting technical analysis and oversight.

Whatever CPUC’s costs, it seems reasonable to expect the CPUC’s initial costs of implementation to be greater than the CPUC’s ongoing costs. 

COMMENTS:

California has ambitious clean energy goals. Achievement of those goals will require significant investments in electricity infrastructure, including at both the transmission (higher voltage) and distribution (lower voltage) levels. Regarding distribution-level investment, the CPUC-commissioned study, produced by Kevala, Inc, and released in May of 2023, identified the potential for approximately $30 billion to $50 billion in investments in the electricity distribution system (also known as the “distribution grid,” though, in reality, there are many such distribution grids operated by several different IOUs) by 2035. Importantly, the study conditioned its estimate on measures “not taken to reduce costs and manage load,” and it explicitly assumed that all grid needs would be met with traditional distribution investments and did not consider alternative new time-variant rates, dynamic rates, flexible load management, or other potential mitigation strategies.

This bill seeks to ensure the electrical IOUs do consider at least one type of distributed energy resource—distributed energy storage systems—when identifying ways to meet demands on their electricity distribution grids in order to reduce the need, and cost, of investment in the electricity distribution system. As the author describes it, “Instead of defaulting to costly infrastructure upgrades, we refine how utilities plan to deploy smarter, faster, and more affordable distributed energy solutions right where the grid needs them most.”

Bill supporters agree. For example, the Corporate Energy Buyers Association Affordability describes traditional utility infrastructure projects as “often slow to implement and place a significant long-term burden on ratepayers” and lauds this bill as requiring IOUs to consider "non-wire alternatives—such as local battery storage and demand response – to solve capacity issues in constrained areas” before pursuing expensive traditional infrastructure investments.

The IOUs protest. For example, Pacific Gas and Electric and Southern California Edison together denounce the bill as moving “toward a highly prescriptive, threshold-triggered non wires evaluation framework that risks delaying essential capacity and reliability upgrades critical for the state’s energization goals and repeating the outcomes of past deferral constructs.” Similarly, San Diego Gas and Electric describes the bill as creating “significant potential for delayed reliability and safety-related infrastructure deployments through rigid, arbitrary, and in many cases, duplicative statutory requirements.”

Analysis Prepared by: Jay Dickenson / APPR. / (916) 319-2081

Date of Hearing: June 24, 2026

ASSEMBLY COMMITTEE ON UTILITIES AND ENERGY

Cottie Petrie-Norris, Chair

SBPCA Bill Id:SB 1295

Author:(Stern) – As Amended Ver:April 28, 2026

SENATE VOTE: 34-5

SUBJECT: Electrical corporations: distributed energy storage systems and nonwire alternatives

SUMMARY: Requires an electrical corporation, for any proposed distribution or transmission infrastructure investment above a threshold established by the California Public Utilities Commission (CPUC), to evaluate whether distributed energy storage systems (such as batteries) or other nonwire alternatives can meet identified reliability or capacity need. Specifically, this bill:

1. Provides that the evaluation must compare total system costs, including the following:
2. The cost of the proposed infrastructure investment.
3. The cost of procuring or deploying distributed energy storage systems or other nonwire alternatives.
4. Avoided or deferred infrastructure costs.
5. Reliability and operational benefits.
6. Prohibits CPUC from approving rate recovery for a proposed infrastructure investment unless the electrical corporation demonstrates that nonwire alternatives are either not feasible within the required timeframe or not cost effective.
7. Authorizes an electrical corporation to procure, own, or enter into long-term contracts for distribution-connected distributed energy storage systems to meet identified reliability or capacity needs.
8. Requires CPUC to authorize an electrical corporation to recover costs and earn a return on distributed energy storage systems and contracts determined to be cost effective.
9. Clarifies that the bill does not limit the ability of third-party providers to develop distributed energy storage systems or other nonwire alternatives to meet identified system needs.
10. Requires an electrical corporation to conduct a competitive solicitation or other transparent process to evaluate third-party solutions if it determines that a nonwire alternative may be feasible.

EXISTING LAW:

1. Authorizes the CPUC, among other things, to establish its own procedures, subject to statute and due process, and to fix rates and establish rules for all public utilities, subject to control by the Legislature. (California Constitution, Article XII, §§2,3, 5, and 6)
2. Defines load-serving entity (LSE), for that purpose, as an electrical corporation, electric service provider (ESP), or community choice aggregator (CCA). (Public Utilities Code §380)
3. Establishes it is the policy of the state that each electrical corporation continue to operate its electric distribution grid in its service territory and to do so in a safe, reliable, efficient, and cost-effective manner. (Public Utilities Code §399.2)
4. Authorizes the CPUC to fix the rates and charges for every public utility, including electrical and gas corporations, and requires that those rates and charges be just and reasonable. (Public Utilities Code §451)
5. Defines “distributed resources” to mean distributed renewable generation resources, energy efficiency, energy storage, electric vehicles, and demand response technologies. (Public Utilities Code §769)
6. Requires the CPUC, on or before February 1, 2023, and biennially thereafter, to report to the Legislature and the Governor on the progress toward modernizing the state's distribution and transmission grid and the impacts of distributed energy resources. (Public Utilities Code §913.6(a)
7. Requires the CPUC to determine appropriate targets, if any, for each LSE to procure viable and cost-effective energy storage systems to be achieved by December 31, 2020. (Public Utilities Code §2836)
8. Requires the CPUC to direct the state's three largest electrical corporations to file applications for programs and investments to accelerate the widespread deployment of distributed energy storage systems. (Public Utilities Code Section 2838.2)

FISCAL EFFECT: According to the Senate Appropriations Committee, this bill would result in unknown, but likely significant, one-time and ongoing costs to the CPUC, likely in the hundreds of thousands of dollars annually, funded by utility ratepayers. These costs are associated with establishing the investment threshold for required evaluations and reviewing proposed infrastructure investments and related rate recovery requests.

BACKGROUND:

Planning for Distributed Resources- California has established utility planning requirements to support the deployment of distributed energy resources (DERs) and identify opportunities to meet grid needs using alternatives to traditional infrastructure investments. SB 17 (Padilla, Chapter 327, Statutes of 2009) required investor-owned electrical corporations (IOUs) to develop smart grid deployment plans. Building on those efforts, AB 327 (Perea, Chapter 611, Statutes of 2013) required IOUs to submit Distribution Resources Plans to identify optimal locations for distributed resources and evaluate their costs, benefits, and ability to defer or avoid traditional distribution investments. The CPUC has also established the Distribution Investment Deferral Framework (DIDF) to evaluate DERs, including energy storage, and other nonwire alternatives that may defer utility distribution infrastructure investments. Through these planning processes, utilities assess opportunities to use DERs and other nonwire alternatives to meet grid needs.

Distribution Investment Deferral Framework- In 2018, the CPUC established the Distribution Investment Deferral Framework (DIDF) to identify opportunities for DERs and other nonwire alternatives to defer or avoid traditional distribution infrastructure investments.^[1] The framework is part of the CPUC's broader distribution planning process and focuses on identifying locations where nonwire alternatives may be able to address projected distribution system needs in lieu of conventional grid upgrades. As part of the DIDF process, IOUs prepare annual Grid Needs Assessments (GNAs) that specify projected distribution system needs and Distribution Deferral Opportunity Reports (DDORs) that identify locations where nonwire alternatives could address those needs. The CPUC's Distribution Planning Advisory Group reviews the reports, which inform utility procurement of DER solutions through a transparent process for selected deferral opportunities.^[2]

Despite this structure, DIDF deferral projects have faced persistent implementation challenges, including interconnection delays, contracting difficulties, changes in identified grid needs, and developer performance issues. The CPUC has revised the DIDF several times since its adoption through utility filings and stakeholder input. In Decision 24-10-030, issued in October 2024, the CPUC directed IOUs to eliminate distribution investment deferral solicitations and focus on improving transparency in the distribution planning process. The decision also retained other planning and reporting components, including the Distribution Planning Advisory Group and Grid Needs Assessment.

COMMENTS:

1. Author’s Statement. “California is leading the way in building a cleaner, more reliable electric grid—but in this era of affordability and protecting ratepayers—more refinement to ensure lower-cost resources are deployed is still critical. This bill takes the next step of refining the process of deploying more distributed energy resources in the distribution grid system as opposed to traditional poles and wires. Instead of defaulting to costly infrastructure upgrades, we refine how utilities plan to deploy smarter, faster, and more affordable distributed energy solutions right where the grid needs them most.”
2. This Bill. California may face significant distribution grid investment needs as electricity demand grows. A CPUC study estimated that approximately $50 billion in distribution grid investments could be required by 2035 under high electrification scenarios if new loads are not managed to reduce peak demand.^[3] The California Public Advocates Office, however, estimated that those costs could be reduced to approximately $15 billion to $20 billion through more effective demand management.^[4] According to the author, distributed energy storage systems offer another tool to reduce or defer costly distribution infrastructure investments while maintaining grid reliability. According to the author, DERs may provide a lower-cost means of meeting certain reliability and capacity needs. To achieve that goal, SB 1295 would require utilities to evaluate these resources before pursuing certain traditional distribution infrastructure investments.
3. Rate Recovery Conditioned on Nonwire Alternatives. SB 1295 would prohibit the CPUC from approving rate recovery for certain distribution or transmission infrastructure investments unless an electrical corporation demonstrates that nonwire alternatives are either not feasible or not cost effective. The bill would make that demonstration a prerequisite to rate recovery but does not specify how the requirement would interact with existing CPUC planning processes used to evaluate nonwire alternatives. For example, it is unclear whether evaluations conducted through existing distribution planning processes would satisfy the requirement or whether utilities would be required to conduct an additional review before obtaining rate recovery for a proposed investment. This could then create uncertainty regarding when infrastructure investments are eligible for recovery and also potentially delay projects intended to address identified reliability and capacity needs. As such, the committee recommends deleting the provisions prohibiting the CPUC from approving rate recovery unless an electrical corporation demonstrates that nonwire alternatives are not feasible or not cost effective.
4. A Competitor with a Guaranteed Return. This measure would authorize utility ownership of distributed energy storage systems and require the CPUC to authorize cost recovery and a return on investment for cost-effective projects. The bill also requires a competitive solicitation or other transparent process to evaluate third-party solutions when a nonwire alternative may be feasible. However, the CPUC already reviews utility investments in energy storage and determines whether utility ownership is appropriate and whether the associated costs are eligible for recovery from ratepayers. It is therefore unclear how the provisions authorizing utility ownership and cost recovery would interact with the CPUC's existing review and approval processes. Therefore, the committee recommends deleting the provisions authorizing utility ownership of distributed energy storage systems and the related authorization for cost recovery.
5. Distribution Planning Process. As written, the bill would require an electrical corporation to evaluate distributed energy storage systems and other nonwire alternatives whenever it proposes a distribution or transmission infrastructure investment above a specified threshold. Utility planning is the process through which grid needs are identified, and potential solutions are evaluated. Requiring that evaluation only after a specific infrastructure project has been identified could require utilities to repeat the analysis of potential solutions that was already conducted during the planning process, adding delay and cost. Given that alternatives are most appropriately considered when evaluating options to address a grid need, the committee recommends revising the bill to require consideration of distributed energy storage systems as part of the distribution planning process.
6. Customer Energization Timelines. This bill is intended to ensure that IOUs consider whether distributed energy storage systems can meet identified reliability or capacity needs before investing in traditional infrastructure. However, the Joint Utilities (PG&E and SCE) contend that, absent clarification, the bill's requirement to evaluate distributed energy storage systems as an alternative could be applied after a project has already been selected for development, potentially delaying project implementation and the energization of customers awaiting service. To address this concern, the committee recommends a provision to clarify that the evaluation required by the bill is not intended to impede timely customer energization.
7. Legislative findings and declarations. This measure includes findings and declarations regarding the benefits of distributed energy storage systems and their role in grid planning and infrastructure deferral. Consistent with the committee's recommendation to narrow the bill's scope, the committee further recommends deleting the legislative findings and declarations.
8. Related Legislation.

SB 913 (Becker) of 2026 proposes several policy changes to authorize and expand the use of aggregated DERs to satisfy RA requirements. Status: Pending hearing in the Assembly Committee on Utilities and Energy

1. Prior Legislation.

AB 740 (Harabedian) of 2025 would have required the CEC, in the next update to the biennial integrated energy policy report after January 1, 2027, and subject to available funding, to adopt a virtual power plant deployment plan. Status: Vetoed by the Governor.

AB 44 (Schultz) of 2025, would have required the CEC, on or before December 1, 2026, and in consultation with LSEs and resource aggregators, to define and publicize methodologies for load modification protocols by which a LSE may reduce or modify its electrical demand forecast upon aggregated system operation of behind-the-meter load modifying technologies and programmatic measures deemed to reliably reduce or modify the LSE’s electrical demand. Status: Vetoed by the Governor.

SB 541 (Becker) of 2025 would have required the CEC, in consultation with specified entities, to analyze the cost-effectiveness of specific load flexibility programs and other types of load-shifting interventions and identify both the approximate amount of load shifting and the cost-effectiveness of each type of load-shifting intervention in the next update to the biennial integrated energy policy report after January 1, 2027, as provided. The bill would have required the CEC, as part of each integrated energy policy report, to estimate each retail supplier’s load-shifting potential, giving consideration to certain factors, as specified. The bill would have required the CEC, on or before July 1, 2028, and biennially thereafter, to analyze and publish the amount of load shifting that each retail supplier achieved in the prior calendar year. Status: Vetoed by the Governor.

AB 50 (Wood) required the CPUC, by July 1, 2025, to determine the criteria for customers to receive timely electricity service when requesting new service connections or upgraded service, known as “energization.” The bill proposed several policies to address delays in connecting customers to the electrical grid, including improved information sharing with local governments, reporting by electric IOUs, and other measures. Status: Chapter 317, Statutes of 2023

SB 410 (Becker) required the CPUC to establish by September 30, 2024, reasonable average and maximum target energization time periods in order to connect new customers and upgrade the service of existing customers to the electrical grid. The bill also requires reporting by electrical corporations and authorizes specified annual cost-recovery, subject to a cap. Status: Chapter 394, Statutes of 2023.

SB 1347 (Stern) of 2017 would have required the CPUC, by January 1, 2020, to consider procurement strategies for the installation of up to 2,000 megawatts of energy storage systems and, as part of that consideration, consider appropriate storage procurement targets and other strategies applicable to the state’s LSEs, meaning IOUs, CCAs, and ESPs. The bill directs the CPUC to reconsider procurement strategies every three years. Status: Died in the Assembly.

AB 2514 (Skinner) required the CPUC to determine appropriate targets, if any, for LSEs to procure energy storage systems. The bill required LSEs to meet any targets adopted by the CPUC by 2015 and 2020. The bill required POUs to set their own targets for the procurement of energy storage and then meet those targets by 2016 and 2021. Status: Chapter 469, Statutes of 2010

AB 1373 (E. Garcia) made numerous changes to electricity policy, most notably, authorized the Department of Water Resources (DWR) to serve as a central procurement entity to procure energy resources in order to help the state meet its renewable and zero-carbon energy resources and reliability goals. The bill also included numerous related and additional provisions. Status: Chapter Statutes of 2023

AB 205 (Committee on Budget), among other things, authorized the DWR to contract for, purchase, finance, or otherwise secure electrical generation to create additional capacity during extreme energy grid events, and established the Strategic Reliability Reserve to fund these actions, including the Demand Side Grid Support program at the CEC. Status: Chapter 61, Statutes of 2022

SB 1158 (Becker), among its provisions, required the CPUC, as part of the RA program, to require every LSE to annually report information regarding the sources of electricity and the emissions of greenhouse gases associated with those sources of electricity for RA requirements. Status: Chapter 367, Statutes of 2022

SB 1136 (Hertzberg) revised existing statute that required the CPUC, in consultation with the CAISO, to establish RA requirements for the state’s LSEs. Status: Chapter 851, Statutes of 2018

SB 618 (Bradford) required, explicitly, the IRPs of all LSEs to contribute to a diverse and balanced portfolio of resources needed to ensure a reliable electricity supply, meet certain environmental goals, and prevent cost shifting among LSEs. Status: Chapter 431, Statutes of 2017

SB 350 (De León ), among other things, increased the renewable portfolio standards and directed the CPUC to develop a process by which LSEs submit IRPs to the CPUC for review or for certification. Status: Chapter 737, Statutes of 2015

SB 1414 (Wolk) required utilities and regulators to include demand response in RA plans. Status: Chapter 627, Statutes of 2014

AB 380 (Nuñez) codified the CPUC’s authority to establish RA standards for electric utilities and other LSEs. Chapter 367, Statutes of 2005

REGISTERED SUPPORT / OPPOSITION:

Support

Clean Energy Buyers Association
Climate Action California (UNREG)

Support If Amended

San Diego Community Power

Oppose

Pacific Gas and Electric Company
San Diego Gas and Electric Company
Southern California Edison

Analysis Prepared by: Lina V. Malova / U. & E. / (916) 319-2083

1. CPUC Decision 18-02-004 ↑

2. CPUC: Distribution Planning; https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/infrastructure/distribution-planning ↑

3. Kevala, “Electrification Impacts Study Part 1: Bottom-Up Load Forecasting and System-Level Electrification Impacts Cost Estimates,” prepared for the California Public Utilities Commission, May 2023; https://www.kevala.com/resources/electrification-impacts-study-part-1 ↑

4. California Public Advocates Office, “The Costs of Upgrading the Distribution Grid for Electrification, June 14, 2023, https://www.publicadvocates.cpuc.ca.gov/-/media/cal-advocates-website/files/press-room/reports-and-analyses/230614-cal-advocates-distribution-grid-impacts-study-fact-sheet.pdf ↑

 THIRD READING  

Bill No: SB 1295

Author: Stern (D), et al.

Amended: 4/28/26

Vote: 21

SENATE ENERGY, U. & C. COMMITTEE: 15-2, 4/21/26

AYES: Allen, Ochoa Bogh, Archuleta, Arreguín, Becker, Caballero, Gonzalez, Grove, Hurtado, McNerney, Reyes, Richardson, Rubio, Stern, Wahab

NOES: Dahle, Strickland

SENATE APPROPRIATIONS COMMITTEE: 6-1, 5/14/26

AYES: Cervantes, Seyarto, Cabaldon, Grayson, Richardson, Wahab

NOES: Dahle

SUBJECT: Electrical corporations: distributed energy storage systems and nonwire alternatives

SOURCE: Deploy Action

DIGEST:

1. This bill requires an electrical corporation, for any proposed distribution or transmission infrastructure investment above a threshold established by the California Public Utilities Commission (CPUC), to evaluate whether distributed energy storage systems or other nonwire alternatives can meet the identified reliability or capacity need, as provided.

ANALYSIS:

Existing law:

1. Establishes and vests the CPUC with regulatory authority over public utilities, including electrical corporations. (Article XII of the California Constitution)
2. Requires the California Independent System Operator (CAISO), as a nonprofit, public benefit corporation, to conduct its operations consistent with applicable state and federal laws and consistent with the interests of the people of the state. (Public Utilities Code §345.5)
3. Requires the CPUC, in consultation with the CAISO, to establish resource adequacy (RA) requirements for all load-serving entities (LSEs) and requires the CPUC in establishing those requirements to ensure the reliability of electrical service in California. Requires the RA program to facilitate the development of new generating, nongenerating, hybrid capacity and retention of existing generating, nongenerating, and hybrid capacity that is economical and needed for reliability. Defines LSE, for that purpose, as an electrical corporation, electric service provider (ESP), or community choice aggregator (CCA). (Public Utilities Code §380)
4. Defines “distributed resources” to mean distributed renewable generation resources, energy efficiency, energy storage, electric vehicles, and demand response technologies. (Public Utilities Code §769)
5. Creates the Demand Side Grid Support Program and requires CEC to implement and administer the program to incentivize dispatchable customer load reduction and backup generation operation as on-call emergency supply and load reduction for the state’s electrical grid during extreme events. (Public Resources Code §25792)

This bill:

1. Requires an electrical corporation, for any proposed distribution or transmission infrastructure investment above a threshold established by the CPUC, to evaluate whether distributed energy storage systems or other nonwire alternatives can meet the identified reliability or capacity need, as provided.
2. Requires an electrical corporation, if it determines that a nonwire alternative may be feasible, to conduct a competitive solicitation or other transparent process to evaluate third-party solutions.
3. Prohibits the CPUC from approving rate recovery for a proposed infrastructure investment unless the electrical corporation demonstrates either that nonwire alternatives are not feasible within the required timeframe or that nonwire alternatives are not cost effective, as provided.
4. Authorizes an electrical corporation to procure, own, or enter into a long-term contract for distributed energy storage systems interconnected at the distribution level to meet identified reliability or capacity needs, and requires the CPUC to authorize an electrical corporation to recover the reasonable costs of, and earn a return on, those distributed energy storage systems, as provided.

Background

About nonwire alternatives. Nonwire alternatives are utility-led strategies to defer or avoid traditional distribution or transmission system upgrades needed to resolve network constraints. These can be delivered by distributed energy resources (DERs) or by other non-traditional solutions – such as advanced grid software or controls.

Distribution Investment Deferral Framework (DIDF). In 2018, the CPUC established the DIDF, via CPUC decision (D.18-02-004), and modified subsequently in 2024 (D.24-10-030), which required the electric IOUs to identify opportunities for nonwire alternatives (namely DERs) to defer or avoid traditional grid upgrades as part of the distribution resource planning (DRP) process. The DIDF is one of the first U.S. initiatives to systematically consider DER-provided distribution services as part of the distribution planning process, in the context of California’s rapidly growing DER penetration. The electric investor-owned utilities (IOUs) were required to provide direction on matching growth scenarios to utility “grid needs assessments” (GNA) to guide distribution investment requests to accommodate DER placement on the electric system. Another important element of the decision was to adopt the long-discussed DIDF – basically the process for identifying opportunities for DERs to defer or avoid traditional distribution infrastructure investments. The Decision ordered the electric IOUs to file two new annual reports, the GNA report by June 1 each year, and the Distribution Deferral Opportunity Report (DDOR) by September 1. These reports were subsequently rescheduled to coincide in a combined annual GNA/DDOR report.

CPUC decision provides guidance regarding grid modernization investments. CPUC decision (D. 18-03-023, March 22, 2018) provided guidance for utility “grid modernization” investment requests in their general rate cases (or separate applications). Utilities were directed to provide a 10-year vision for their grid modernization plans (GMP) that not only justified the proposed investments based on lowest cost and highest benefits but also described whether any of the GMP investments could be met instead by DERs. Importantly, the Grid Modernization decision defined and broadened the scope of technologies that could be components of a utility GMP – adopting a staff proposed categorization of technologies that ranges from system analysis software and grid management systems, to sensors and controllers essential to maintain circuit stability and system reliability.

Comments

Need for this bill. The author expresses frustration that the CPUC pivoted from the DIDF requirements. They note that the DRP proceeding, and its successor High DER proceeding pieced together fundamental components and adopted frameworks to allow for initial attempts to put “nonwires alternatives” to a market test via solicitation pilots. This bill attempts to require the DIDF approach.

DIDF struggled to procure DERs. The DIDF struggled to procure DER-pro­vided distribution services as viable alternatives to tradi­tional grid upgrades. These challenges prompted a series of incremental DIDF reforms in subsequent years. In 2024, the CPUC effectively suspended the requirement for electric IOUs to identify distribution service alternatives and conduct annual competitive procurements from third-party providers. According to a 2025 White Paper by Electric Power Research Institute (EPRI), across 112 distribution service opportunities considered over seven annual cycles, only 9% resulted in a successful distribution service contract. Although solicitations were technology-neutral, every project that reached either the operational or development stage was a standalone battery storage system.

Not seeing eye-to-eye. The author of the bill notes that further changes to the DIDF process were likely beneficial, they are frustrated that the current processes continue to require multiple long-term studies that may not focus enough on the immediate need for identifying cost-effective locations for DER solutions. The utilities opposed to the bill raise concerns that California learned through the DIDF experience that a deferral-first construct can consume significant time and resources without delivering meaningful affordability benefits. They support the state’s efforts to pivot towards a “customer-centric planning model” that integrates demand flexibility upfront and accelerates customer energizations, rather than deferring necessary infrastructure.

Related/Prior Legislation

SB 913 (Becker) of 2026, proposes several policy changes to authorize and expand the use of aggregated DERs to satisfy RA requirements. The bill is pending in Senate.

AB 740 (Harabedian) of 2025, would have required the CEC, in the next update to the biennial integrated energy policy report after January 1, 2027, and subject to available funding, to adopt a virtual power plant deployment plan. The bill was vetoed.

AB 44 (Schultz) of 2025, would have required the CEC, on or before December 1, 2026, and in consultation with LSEs and resource aggregators, to define and publicize methodologies for load modification protocols by which a LSE may reduce or modify its electrical demand forecast upon aggregated system operation of behind-the-meter load modifying technologies and programmatic measures deemed to reliably reduce or modify the LSE’s electrical demand. The bill was vetoed.

SB 541 (Becker) of 2025, would have required the CEC, in consultation with specified entities, to analyze the cost-effectiveness of specific load flexibility programs and other types of load-shifting interventions and identify both the approximate amount of load shifting and the cost-effectiveness of each type of load-shifting intervention in the next update to the biennial integrated energy policy report after January 1, 2027, as provided. The bill was vetoed.

FISCAL EFFECT: Appropriation: No Fiscal Com.: Yes Local: Yes

According to the Senate Appropriations Committee, unknown, likely significant one-time and ongoing annual costs, both likely in the hundreds of thousands of dollars (ratepayer funds), for the CPUC to establish the investment threshold that will trigger the requirement for an evaluation, as well as review investments and approve rate recovery for the proposed infrastructure investments as needed.

SUPPORT: (Verified 5/14/26)

Deploy Action (Source)

OPPOSITION: (Verified 5/14/26)

Pacific Gas and Electric Company

San Diego Gas and Electric Company

Southern California Edison

ARGUMENTS IN SUPPORT: According to Deploy Action:

SB 1295 improves the ability for the California Public Utilities Commission (CPUC) to consider cost-effective distributed storage technologies in load-serving entities’ distribution planning processes. By identifying where distributed storage might provide cost-effective non-wires alternatives to new distribution or transmission infrastructure, or where it can provide other flexibility benefits, SB 1295 provides new tools to ensure Californians have access to affordable energy in a timely and reliable manner.

ARGUMENTS IN OPPOSITION: According to San Diego Gas & Electric:

San Diego Gas & Electric (SDG&E) respectfully opposes Senate Bill (SB) 1295 (Stern), as it creates significant potential for delayed reliability and safety-related infrastructure deployments through rigid, arbitrary and in many cases duplicative statutory requirements. While the bill is intended to address grid constraints and promote the deployment of distributed energy resources (DER), its approach is misaligned with established planning and investment processes and does not strengthen the frameworks necessary to deliver infrastructure in a timely, safe, and reliable manner, nor does it promote disciplined management of customer costs.

Prepared by: Nidia Bautista / E., U. & C. / (916) 651-4107

5/16/26 12:13:43

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SENATE COMMITTEE ON

Senator Sabrina Cervantes, Chair

2025 - 2026 Regular Session

SB 1295 (Stern) - Electrical corporations: distributed energy storage systems and nonwire alternatives

Bill Summary:

This bill would require an electrical corporation, for any proposed distribution or transmission infrastructure investment above a threshold established by the California Public Utilities Commission (CPUC), to evaluate whether distributed energy storage systems or other nonwire alternatives such as batteries can meet the identified reliability or capacity need, as provided.

Fiscal Impact:

• Unknown, likely significant one-time and ongoing annual costs, both likely in the hundreds of thousands of dollars (ratepayer funds), for the CPUC to establish the investment threshold that will trigger the requirement for an evaluation, as well as review investments and approve rate recovery for the proposed infrastructure investments as needed.

Background:

Distribution Investment Deferral Framework (DIDF). In 2018, the CPUC established via CPUC decision (D.18-02-004), and modified subsequently in 2024 (D.24-10-030), the DIDF which required the electric IOUs to identify opportunities for nonwires alternatives (DERs) to defer or avoid traditional grid upgrades as part of the DRP process. The electric IOUs were required to provide direction on matching growth scenarios to utility “grid needs assessments” (GNA) to guide distribution investment requests to accommodate DER placement on the system. Another important element of the decision was to adopt the long-discussed DIDF – basically the process for identifying opportunities for DERs to defer or avoid traditional distribution infrastructure investments. The Decision ordered the electric IOUs to file two new annual reports, the GNA report by June 1 each year, and the Distribution Deferral Opportunity Report (DDOR) by September 1. These reports were subsequently rescheduled to coincide in a combined annual GNA/DDOR report.

CPUC decisions adds another puzzle piece. CPUC decision (D. 18-03-023, March 22, 2018) added another piece to the puzzle, in the form of commission guidance for utility “grid modernization” investment requests in their general rate cases (or separate Applications). This became another key to providing transparency into the distribution planning process, by requiring detailed explanations for “primary drivers” of grid upgrades, whether it was demand growth, DER market growth, equipment replacements, or other factors. Utilities were directed to provide a 10-year vision for their grid modernization plans (GMP), that not only justified the proposed investments based on lowest cost and highest benefits, but also would describe whether any of the GMP investments could be met instead by DER. Importantly, the Grid Modernization decision defined and broadened the scope of technologies that could be components of a utility GMP – adopting a staff proposed categorization of technologies that ranges from system analysis software and grid management systems, to sensors and controllers essential to maintain circuit stability and system reliability.

Proposed Law:

This bill would require an electrical corporation, for any proposed distribution or transmission infrastructure investment above a threshold established by the California Public Utilities Commission (CPUC), to evaluate whether distributed energy storage systems or other nonwire alternatives such as batteries can meet the identified reliability or capacity need, as provided.

• equire an electrical corporation, if it determines that a nonwire alternative may be feasible, to conduct a competitive solicitation or other transparent process to evaluate third-party solutions.
• Prohibit the CPUC from approving rate recovery for a proposed infrastructure investment unless the electrical corporation demonstrates either that nonwire alternatives are not feasible within the required timeframe or that nonwire alternatives are not cost effective, as provided.
• A an electrical corporation to procure, own, or enter into a long-term contract for distributed energy storage systems interconnected at the distribution level to meet identified reliability or capacity needs, and would require the commission to authorize an electrical corporation to recover the reasonable costs of, and earn a return on, those distributed energy storage systems, as provided.

Related Legislation:

SB 913 (Becker) of 2026, proposes several policy changes to authorize and expand the use of aggregated DERs to satisfy RA requirements.

AB 740 (Harabedian) of 2025, would have required the CEC, in the next update to the biennial integrated energy policy report after January 1, 2027, and subject to available funding, to adopt a virtual power plant deployment plan. The bill was vetoed by the Governor.

AB 44 (Schultz) of 2025, would have required the CEC, on or before December 1, 2026, and in consultation with LSEs and resource aggregators, to define and publicize methodologies for load modification protocols by which a LSE may reduce or modify its electrical demand forecast upon aggregated system operation of behind-the-meter load modifying technologies and programmatic measures deemed to reliably reduce or modify the LSE’s electrical demand. The bill was vetoed by the Governor.

SB 541 (Becker) of 2025, would have required the CEC, in consultation with specified entities, to analyze the cost-effectiveness of specific load flexibility programs and other types of load-shifting interventions and identify both the approximate amount of load shifting and the cost-effectiveness of each type of load-shifting intervention in the next update to the biennial integrated energy policy report after January 1, 2027, as provided. The bill would have required the CEC, as part of each integrated energy policy report, to estimate each retail supplier’s load-shifting potential, giving consideration to certain factors, as specified. The bill would have required the CEC, on or before July 1, 2028, and biennially thereafter, to analyze and publish the amount of load shifting that each retail supplier achieved in the prior calendar year. The bill was vetoed by the Governor.

AB 50 (Wood, Chapter 317, Statutes of 2023) required the CPUC, by July 1, 2025, to determine the criteria for customers to receive timely electricity service when requesting new service connections or upgraded service, known as “energization.” The bill proposed several policies to address delays in connecting customers to the electrical grid, including improved information sharing with local governments, reporting by electric IOUs, and other measures.

SB 410 (Becker, Chapter 394, Statutes of 2023) required the CPUC to establish by September 30, 2024, reasonable average and maximum target energization time periods in order to connect new customers and upgrade the service of existing customers to the electrical grid. The bill also requires reporting by electrical corporations and authorizes specified annual cost-recovery, subject to a cap.

SB 1347 (Stern) of 2017, would have required the CPUC, by January 1, 2020, to consider procurement strategies for the installation of up to 2,000 megawatts of energy storage systems and, as part of that consideration, consider appropriate storage procurement targets and other strategies applicable to the state’s LSEs, meaning IOUs, CCAs, and ESPs. The bill directs the CPUC to reconsider procurement strategies every three years. The bill died in the Assembly.

AB 2514 (Skinner, Chapter 469, Statutes of 2010) required the CPUC to determine appropriate targets, if any, for LSEs to procure energy storage systems. The bill required LSEs to meet any targets adopted by the CPUC by 2015 and 2020. The bill required POUs to set their own targets for the procurement of energy storage and then meet those targets by 2016 and 2021.

AB 1373 (E. Garcia, Chapter Statutes of 2023) made numerous changes to electricity policy, most notably, authorized the Department of Water Resources (DWR) to serve as a central procurement entity to procure energy resources in order to help the state meet its renewable and zero-carbon energy resources and reliability goals. The bill also included numerous related and additional provisions.

AB 205 (Committee on Budget, Chapter 61, Statutes of 2022), among other things, authorized the DWR to contract for, purchase, finance or otherwise secure electrical generation to create additional capacity during extreme energy grid events, and established the Strategic Reliability Reserve to fund these actions, including the Demand Side Grid Support program at the CEC.

SB 1158 (Becker, Chapter 367, Statutes of 2022) among its provisions, required the CPUC as part of the RA program to require every LSEs to annually report information regarding the sources of electricity and the emissions of greenhouse gases associated with those sources of electricity for RA requirements.

SB 1136 (Hertzberg, Chapter 851, Statutes of 2018) revised existing statute that required the CPUC, in consultation with the CAISO, to establish RA requirements for the state’s LSEs.

SB 618 (Bradford, Chapter 431, Statutes of 2017) required, explicitly, the IRPs of all LSEs to contribute to a diverse and balanced portfolio of resources needed to ensure a reliable electricity supply, meet certain environmental goals, and prevent cost shifting among LSEs.

SB 350 (De León, Chapter 737, Statutes of 2015), among other things, increased the renewable portfolio standards and directed the CPUC to develop a process by which LSEs submit IRPs to the CPUC for review or for certification.

SB 1414 (Wolk, Chapter 627, Statutes of 2014) required utilities and regulators to include demand response in RA plans.

AB 380 (Nuñez, Chapter 367, Statutes of 2005) codified the CPUC’s authority to establish RA standards for electric utilities and other LSEs.

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SENATE COMMITTEE ON ENERGY, UTILITIES AND COMMUNICATIONS

Senator Benjamin Allen, Chair

2025 - 2026 Regular

Bill No: Hearing Date: 4/21/2026

SUBJECT:

DIGEST: This bill proposes to increase procurement of distributed energy storage systems. This bill requires the California Public Utilities Commission (CPUC), on or before January 1, 2030, to consider procurement strategies to support the installation of distributed energy storage systems. Requires the California Energy Commission (CEC), by July 1, 2028, and biennially thereafter, to identify and evaluate constrained distribution areas.

ANALYSIS:

Existing law:

1. Establishes and vests the CPUC with regulatory authority over public utilities, including electrical corporations. (Article XII of the California Constitution)
2. Requires the California Independent System Operator (CAISO), as a nonprofit, public benefit corporation, to conduct its operations consistent with applicable state and federal laws and consistent with the interests of the people of the state. (Public Utilities Code §345.5)
3. Requires the CAISO to ensure the efficient use and reliable operation of the transmission grid, as provided. (Public Utilities Code §345)
4. Requires the CAISO to perform a review following a major outage that affects at least 10% of customers of the entity providing the local distribution service, as provided. (Public Utilities Code §349)
5. Requires the CPUC, in consultation with the CAISO, to establish resource adequacy (RA) requirements for all load-serving entities (LSEs) and requires the CPUC in establishing those requirements to ensure the reliability of electrical service in California. Requires the RA program to facilitate the development of new generating, nongenerating, hybrid capacity and retention of existing generating, nongenerating, and hybrid capacity that is economical and needed for reliability. (Public Utilities Code §380)
6. Requires that the RA program achieve specified objectives, including that it establishes new or maintains existing demand response products and tariffs, as specified. (Public Utilities Code §380)
7. Defines LSE, for that purpose, as an electrical corporation, electric service provider (ESP), or community choice aggregator (CCA). (Public Utilities Code §380)
8. Defines “distributed resources” to mean distributed renewable generation resources, energy efficiency, energy storage, electric vehicles, and demand response technologies. (Public Utilities Code §769)
9. Creates the Demand Side Grid Support Program and requires CEC to implement and administer the program to incentivize dispatchable customer load reduction and backup generation operation as on-call emergency supply and load reduction for the state’s electrical grid during extreme events. (Public Resources Code §25792)

This bill:

1. Requires the CPUC, on or before January 1, 2030, to consider procurement strategies to support the installation of distributed energy storage systems, as provided.
2. Requires the CEC, in consultation with the CPUC and the CAISO, on or before July 1, 2028, and biennially thereafter, to identify and evaluate constrained distribution areas, as defined, and local capacity areas, as defined, for those purposes, as provided. As part of the procurement strategies considered by the CPUC, this bill requires the CPUC to require each LSE to demonstrate that identified localized reliability vulnerability areas will be addressed within a reasonable planning horizon and using the least-cost portfolio of resources, including distributed energy storage systems and other nonwire alternatives, as specified. 
3. Authorizes, if the CPUC imposes an energy storage system procurement target on LSEs, each LSE to meet up to 50% of its procurement target through energy storage systems that it owns, that are interconnected at the transmission or distribution level, or that are located on the customer side of the meter, as specified.
4. Requires the CPUC to reconsider procurement strategies and appropriate targets not less than once every three years. 
5. Authorizes the CPUC to approve, or modify and approve, electrical corporation programs to deploy, and investments in, distributed energy storage systems that include appropriate energy storage management systems and reasonable mechanisms for cost recovery.
6. Requires the CPUC, on or before January 1, 2028, to amend its tariffs that govern the deployment of energy storage systems, as provided.
7. Requires the CPUC to authorize an electrical corporation to earn a return on investments in and operation of distributed energy storage systems and other nonwire alternatives deployed to address localized reliability vulnerability areas.
8. Requires the CPUC to establish performance-based mechanisms that allow an electrical corporation to earn incentives for achieving measurable outcomes, including, but not limited to, integration of cost-effective distributed energy resources (DERs), as provided.

Background

According to the author:

The current framework for utilities to make distribution grid upgrade decisions is still leaving too many opportunities for the utilities to choose costly solutions that are not enhancing reliability or helping to achieve clean energy targets. The front-of-the-meter battery deployment within CAISO is rapidly expanding, with batteries comprising roughly 46 percent of total capacity in the interconnection queue as of mid-2025. From 2018 through mid-2025, battery storage capacity in California increased from 500 megawatts to more than 16,900 megawatts, with state projections envisioning 52,000 megawatts of battery storage needed by 2045. Energy storage is increasingly an affordable and attractive resource option for load-servicing entities and regulators to consider, in part due to its declining costs, its modularity, and its fast average development timelines. Distributed storage systems of not more than 10 megawatts in capacity are well-suited to meet near-term priority grid zones and high-risk grid soft spots, and can help defer new poles and wires or other upgrade investments in the near-term. However, the current framework where the CPUC oversees utilities Distribution Resource Planning (DRP) and Integrated Resource Planning (IRP) decisions fails to properly consider full grid services and resilience for Public Safety Power Shutoff (PSPS) events; capacity constrained feeders; critical facilities; reliability and voltage regulation support; and feeders and other grid infrastructure serving primarily low-income customers.

Distribution Investment Deferral Framework (DIDF). In 2018, the CPUC established via CPUC decision (D.18-02-004), and modified subsequently in 2024 (D.24-10-030), the DIDF which required the electric IOUs to identify opportunities for nonwires alternatives (DERs) to defer or avoid traditional grid upgrades as part of the DRP process. The electric IOUs were required to provide direction on matching growth scenarios to utility “grid needs assessments” (GNA) to guide distribution investment requests to accommodate DER placement on the system. Another important element of the decision was to adopt the long-discussed DIDF – basically the process for identifying opportunities for DERs to defer or avoid traditional distribution infrastructure investments. The Decision ordered the electric IOUs to file two new annual reports, the GNA report by June 1 each year, and the Distribution Deferral Opportunity Report (DDOR) by September 1. These reports were subsequently rescheduled to coincide in a combined annual GNA/DDOR report.

CPUC decisions adds another puzzle piece. CPUC decision (D. 18-03-023, March 22, 2018) added another piece to the puzzle, in the form of commission guidance for utility “grid modernization” investment requests in their general rate cases (or separate Applications). This became another key to providing transparency into the distribution planning process, by requiring detailed explanations for “primary drivers” of grid upgrades, whether it was demand growth, DER market growth, equipment replacements, or other factors. Utilities were directed to provide a 10-year vision for their grid modernization plans (GMP), that not only justified the proposed investments based on lowest cost and highest benefits, but also would describe whether any of the GMP investments could be met instead by DER. Importantly, the Grid Modernization decision defined and broadened the scope of technologies that could be components of a utility GMP – adopting a staff proposed categorization of technologies that ranges from system analysis software and grid management systems, to sensors and controllers essential to maintain circuit stability and system reliability.

Comments

Author expresses frustration that CPUC pivoted from the DIDF requirements. Although the DER puzzle was by no means solved, the DRP proceeding and its successor High DER proceeding pieced together fundamental components and adopted frameworks to allow for initial attempts to put “nonwires alternatives” to a market test via solicitation pilots. However, the DIDF process stalled with a 2024 Ruling that paused DIDF requirements, along with D.24-10-030, which called for further changes to the DIDF process. These process changes, while likely beneficial, still continue to require multiple long-term studies that do not focus enough on the immediate need for identifying cost-effective locations for DER solutions.

Bill’s provisions could benefit from streamlined recasting. The author acknowledges the desire to recast this bill’s requirements to provide clearer understanding of the intended goals. Given the myriad of requirements currently in this bill, a streamlined recasting of this bill’s language would be welcome to ensure greater clarity. Specifically, the author and committee may wish to amend this bill as follows:

• Delete all provisions in this bill, except the findings and declarations.
• Require for proposed distribution or transmission infrastructure investment above a threshold established by the CPUC.
• Require an electrical corporation to evaluate whether distributed energy storage systems or nonwire alternatives can meet the identified reliability or capacity need.
• Require the evaluation to require a comparison of total system costs, including avoided or deferred costs and distributed energy storage systems.
• Require the CPUC to not approve rate recovery for a proposed infrastructure investment unless the electrical corporation demonstrates nonwire alternatives are not feasible or cost-effective.
• Maintain Section Public Utilities Code §469.5(d).
• Require the CPUC to authorize electrical corporation to recover to recover reasonable costs of, and earn a return on, DER storage systems.
• Maintain Section Public Utilities Code §469.5(f).

Prior/Related Legislation

SB 913 (Becker) of 2026, proposes several policy changes to authorize and expand the use of aggregated DERs to satisfy RA requirements. The bill is pending in the Senate Privacy, Digital Technologies, and Consumer Protection Committee.

AB 740 (Harabedian) of 2025, would have required the CEC, in the next update to the biennial integrated energy policy report after January 1, 2027, and subject to available funding, to adopt a virtual power plant deployment plan. The bill was vetoed by the Governor.

AB 44 (Schultz) of 2025, would have required the CEC, on or before December 1, 2026, and in consultation with LSEs and resource aggregators, to define and publicize methodologies for load modification protocols by which a LSE may reduce or modify its electrical demand forecast upon aggregated system operation of behind-the-meter load modifying technologies and programmatic measures deemed to reliably reduce or modify the LSE’s electrical demand. The bill was vetoed by the Governor.

SB 541 (Becker) of 2025, would have required the CEC, in consultation with specified entities, to analyze the cost-effectiveness of specific load flexibility programs and other types of load-shifting interventions and identify both the approximate amount of load shifting and the cost-effectiveness of each type of load-shifting intervention in the next update to the biennial integrated energy policy report after January 1, 2027, as provided. The bill would have required the CEC, as part of each integrated energy policy report, to estimate each retail supplier’s load-shifting potential, giving consideration to certain factors, as specified. The bill would have required the CEC, on or before July 1, 2028, and biennially thereafter, to analyze and publish the amount of load shifting that each retail supplier achieved in the prior calendar year. The bill was vetoed by the Governor.

AB 50 (Wood, Chapter 317, Statutes of 2023) required the CPUC, by July 1, 2025, to determine the criteria for customers to receive timely electricity service when requesting new service connections or upgraded service, known as “energization.” The bill proposed several policies to address delays in connecting customers to the electrical grid, including improved information sharing with local governments, reporting by electric IOUs, and other measures.

SB 410 (Becker, Chapter 394, Statutes of 2023) required the CPUC to establish by September 30, 2024, reasonable average and maximum target energization time periods in order to connect new customers and upgrade the service of existing customers to the electrical grid. The bill also requires reporting by electrical corporations and authorizes specified annual cost-recovery, subject to a cap.

SB 1347 (Stern) of 2017, would have required the CPUC, by January 1, 2020, to consider procurement strategies for the installation of up to 2,000 megawatts of energy storage systems and, as part of that consideration, consider appropriate storage procurement targets and other strategies applicable to the state’s LSEs, meaning IOUs, CCAs, and ESPs. The bill directs the CPUC to reconsider procurement strategies every three years. The bill died in the Assembly.

AB 2514 (Skinner, Chapter 469, Statutes of 2010) required the CPUC to determine appropriate targets, if any, for LSEs to procure energy storage systems. The bill required LSEs to meet any targets adopted by the CPUC by 2015 and 2020. The bill required POUs to set their own targets for the procurement of energy storage and then meet those targets by 2016 and 2021.

AB 1373 (E. Garcia, Chapter Statutes of 2023) made numerous changes to electricity policy, most notably, authorized the Department of Water Resources (DWR) to serve as a central procurement entity to procure energy resources in order to help the state meet its renewable and zero-carbon energy resources and reliability goals. The bill also included numerous related and additional provisions.

AB 205 (Committee on Budget, Chapter 61, Statutes of 2022), among other things, authorized the DWR to contract for, purchase, finance or otherwise secure electrical generation to create additional capacity during extreme energy grid events, and established the Strategic Reliability Reserve to fund these actions, including the Demand Side Grid Support program at the CEC.

SB 1158 (Becker, Chapter 367, Statutes of 2022) among its provisions, required the CPUC as part of the RA program to require every LSEs to annually report information regarding the sources of electricity and the emissions of greenhouse gases associated with those sources of electricity for RA requirements.

SB 1136 (Hertzberg, Chapter 851, Statutes of 2018) revised existing statute that required the CPUC, in consultation with the CAISO, to establish RA requirements for the state’s LSEs.

SB 618 (Bradford, Chapter 431, Statutes of 2017) required, explicitly, the IRPs of all LSEs to contribute to a diverse and balanced portfolio of resources needed to ensure a reliable electricity supply, meet certain environmental goals, and prevent cost shifting among LSEs.

SB 350 (De León, Chapter 737, Statutes of 2015), among other things, increased the renewable portfolio standards and directed the CPUC to develop a process by which LSEs submit IRPs to the CPUC for review or for certification.

SB 1414 (Wolk, Chapter 627, Statutes of 2014) required utilities and regulators to include demand response in RA plans.

AB 380 (Nuñez, Chapter 367, Statutes of 2005) codified the CPUC’s authority to establish RA standards for electric utilities and other LSEs.

FISCAL EFFECT: Appropriation: Fiscal Com.: Local:

SUPPORT:

None received

OPPOSITION:

Pacific Gas and Electric Company

San Diego Gas and Electric Company

ARGUMENTS IN SUPPORT: According to the author:

California has always led the nation in building a cleaner, more reliable electric grid — and this bill takes the next critical step. Instead of defaulting to costly infrastructure upgrades, we are requiring utilities to deploy smarter, faster, and more affordable distributed energy solutions right where the grid needs them most. By strategically placing batteries and other clean resources in vulnerable areas, we can reduce outages, protect communities from power shutoffs, and save ratepayers money. This is about modernizing our grid to meet the challenges of climate change while keeping electricity affordable for Californians. With this legislation, California will continue to lead on innovation, resilience, and delivering real value to working families.

ARGUMENTS IN OPPOSITION: According to San Diego Gas & Electric:

San Diego Gas & Electric (SDG&E) respectfully opposes Senate Bill (SB) 1295 (Stern), as it creates significant potential for delayed reliability and safety-related infrastructure deployments through rigid, arbitrary and in many cases duplicative statutory requirements. While the bill is intended to address grid constraints and promote the deployment of distributed energy resources (DER), its approach is misaligned with established planning and investment processes and does not strengthen the frameworks necessary to deliver infrastructure in a timely, safe, and reliable manner, nor does it promote disciplined management of customer costs.

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