SB 541 directs the California Energy Commission (CEC) to adopt and update a statewide goal for load shifting aimed at reducing net peak electrical demand, in consultation with the California Public Utilities Commission (CPUC), the Independent System Operator (CAISO), and other balancing authorities. The bill requires the CEC to recommend policies that grow demand response and load flexibility without increasing greenhouse gas emissions or electricity rates, and to analyze the cost‑effectiveness of specific load‑shifting programs in a 2027 report update.
Beyond target setting, SB 541 requires the CEC to estimate each retail supplier’s load‑shifting potential in its integrated energy policy reports, to publicly publish biennial reports showing how much load shifting each retail supplier achieved beginning in 2028, and to establish standards for estimating load shifting. The statute is expressly nonbinding — it does not mandate procurement — and it preserves the authority of community choice aggregators and local publicly owned utilities to set their own rates and programs.
The text also defines “load shifting” and excludes backup fossil generation from qualifying measures, while exempting very small suppliers from the “retail supplier” definition.
At a Glance
What It Does
Requires the CEC to adopt a statewide load‑shifting goal, recommend policies that increase demand response without raising emissions or rates, estimate retail suppliers’ load‑shifting potential in each integrated energy policy report, and publish biennial public reports on actual load shifting achieved. The CEC must also analyze program‑level cost‑effectiveness in the next report update after January 1, 2027.
Who It Affects
Directly affects retail suppliers defined as electrical corporations, community choice aggregators (CCAs), electric service providers, and local publicly owned electric utilities, with statutory exclusions for very small electrical corporations (≤60,000 customer accounts) and suppliers with annual demand under 1,000 GWh. It also engages the CEC, CPUC, CAISO, and other balancing authorities in consultation and data sharing.
Why It Matters
Creates the first statutory requirement in California for standardized estimates and public accounting of load‑shifting potential and achievement, which can reshape resource planning, valuation of distributed energy resources (DERs) and demand response, and how utilities and CCAs justify investments in flexibility.
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What This Bill Actually Does
SB 541 asks the California Energy Commission to quantify how much electricity demand can be shifted away from peak periods and to set a statewide target for that load shifting. To develop the target the CEC must coordinate with the CPUC, CAISO, and other balancing authorities and draw on academic and industry research.
The commission must also propose policies to expand load flexibility, but those policies should not lead to higher greenhouse gas emissions or higher retail electricity rates.
The bill requires the CEC to estimate each retail supplier’s contribution to the statewide potential in every integrated energy policy report. When calculating those estimates, the CEC must consider each supplier’s share of statewide load, territory‑specific limitations on adopting load‑shifting strategies, and the cost‑effectiveness of different measures.
SB 541 excludes load reductions that are part of emergency programs (for example, the Demand Side Grid Support Program and the Emergency Load Reduction Program adopted in prior CPUC decisions) from those estimates.SB 541 sets out a public accountability framework: the CEC must publish a biennial analysis, starting July 1, 2028, showing how much load shifting each retail supplier actually achieved in the preceding calendar year and it must develop and periodically update standards for estimating load shifting by program type. The statute clarifies that these targets and reports are informational and nonbinding — the bill does not command any retail supplier to procure specific technologies — and it preserves the governing boards of CCAs and local public utilities to set their own rates and programs.
Finally, the law defines load shifting to include demand flexibility, time‑varying rates, distribution‑connected renewables and storage, and supply‑side flexibility resources, while expressly excluding backup fossil generators and other non‑zero‑carbon generation from qualifying as load shifting.
The Five Things You Need to Know
The CEC must have adopted a statewide load‑shifting goal by June 1, 2023 and must update that target in each biennial integrated energy policy report thereafter.
In the integrated energy policy report after January 1, 2027, the CEC must analyze the cost‑effectiveness of specific load‑flexibility programs and estimate each program’s contribution toward the 2030 load‑shift goal.
The CEC must publish, on or before July 1, 2028 and every two years after, a public analysis of the amount of load shifting each retail supplier achieved in the prior calendar year.
When estimating load‑shifting potential, the CEC must exclude reductions expected to be met by emergency programs, specifically naming the Demand Side Grid Support Program and the Emergency Load Reduction Program directed in CPUC Decision 21‑03‑056.
The statute excludes backup generators powered by fossil fuels from qualifying as load shifting and excludes very small suppliers from the definition of “retail supplier” (electrical corporations with ≤60,000 customer accounts or suppliers with annual demand <1,000 GWh).
Section-by-Section Breakdown
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Statewide load‑shifting goal and 2027 cost‑effectiveness analysis
Subsection (a) directs the CEC, in consultation with CPUC, CAISO, and other balancing authorities, to adopt a load‑shifting goal (the statute references an initial June 1, 2023 deadline) and to update that target in every biennial integrated energy policy report. The CEC must base the target on research (the bill cites the 2020 LBNL Shift Resource report) and recommend policies that increase demand response and load shifting without increasing greenhouse gas emissions or electricity rates. Paragraph (2) adds a concrete analytical requirement: in the report after January 1, 2027, the CEC must evaluate the cost‑effectiveness of specific load‑flexibility programs and estimate how much each program type contributes toward the 2030 goal — a level of program granularity that will require data sharing and clearly defined evaluation metrics.
Retail‑supplier load‑shifting potential: estimation and exclusions
Subsection (b) requires the CEC to estimate each retail supplier’s load‑shifting potential as part of every integrated energy policy report, taking into account each supplier’s share of statewide load, geographic and grid constraints in their service territory, and program cost‑effectiveness. The statute explicitly directs the CEC to exclude load expected to be delivered by emergency programs from these potential estimates, naming the Demand Side Grid Support Program and the Emergency Load Reduction Program from CPUC Decision 21‑03‑056. That exclusion avoids double‑counting emergency curtailment capacity as planned, regular load flexibility.
Biennial public reporting and standards for measurement
Subsection (c) creates a public reporting duty: on or before July 1, 2028 and every two years after, the CEC must publish the amount of load shifting each retail supplier achieved in the previous calendar year. To support those reports the CEC must establish and periodically update standards for estimating load shifting by program type. Practically, this will require the CEC to specify measurement methodologies, data inputs, attribution rules, and procedures to reconcile differing utility methodologies — all of which will shape which programs appear most effective and how suppliers are credited.
Nonbinding framework and preservation of local authority
Subsection (d) makes three policy choices explicit: the section does not create binding procurement obligations for retail suppliers; it does not supersede the authority of CCA or local publicly owned electric utility governing boards to set rates, programs, or goals; and it leaves discretion to local entities. The result is a statewide measurement and planning framework that uses public targets and accountability but stops short of directing procurement or overriding local decisions.
Definitions and statutory thresholds
Subsection (e) defines key terms: it aligns statutory terms with existing Public Utilities Code definitions for California balancing authority, CCA, electric service provider, electrical corporation, and local publicly owned electric utility. It provides a working definition of “load shifting,” enumerating eligible activities (time‑varying rates, demand flexibility resources, distribution‑connected renewables and storage, supply‑side flexibility) and expressly excludes backup fossil‑fuel generators and non‑zero‑carbon generation. The provision also narrows which utilities are covered by the term “retail supplier,” carving out very small electrical corporations (≤60,000 accounts) and suppliers with annual demand under 1,000 GWh, which affects who must be included in the CEC’s estimates and public reporting.
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Explore Energy in Codify Search →Who Benefits and Who Bears the Cost
Every bill creates winners and losers. Here's who stands to gain and who bears the cost.
Who Benefits
- California Energy Commission: Gains a statutory mandate and public platform to set targets, require standardized estimates, and shape statewide methodology for valuing load flexibility — strengthening its central planning role.
- Grid operators and balancing authorities (CAISO and others): Obtain clearer, commission‑backed estimates of potential non‑generation flexibility that can reduce peak stress and inform regional operational planning.
- Distributed energy resource and demand‑response providers: Benefit from clearer public valuation and program evaluations that can increase investment signals for storage, smart thermostats, time‑of‑use rates, and aggregation services.
- Ratepayers and future customers: Stand to benefit indirectly if load shifting reduces the need for costly peaker plants and transmission upgrades, lowering long‑term system costs provided programs are cost‑effective.
Who Bears the Cost
- Retail suppliers (IOUs, CCAs, ESPs, and POUs over the thresholds): Must support CEC estimates, collect and share program data, and potentially design or expand load‑shifting programs, incurring administrative and program costs.
- California Energy Commission (administrative burden): Must develop evaluation standards, run public reporting, and perform detailed cost‑effectiveness studies — a resource and expertise commitment that may require budget increases or interagency data agreements.
- Small or mid‑sized suppliers near exclusion thresholds: Face a compliance cliff where being just over the thresholds triggers new reporting and analysis obligations that could be disproportionately costly relative to their size.
- Program evaluators and consultants: Will bear demand for detailed impact evaluations, metering and verification work, and cost‑effectiveness modeling as the CEC seeks program‑level contributions to the 2030 goal.
Key Issues
The Core Tension
The central tension is between creating a consistent, statewide accounting and incentive environment for load flexibility and preserving local control and cost constraints: the state seeks to standardize measurement and set public targets to unlock system value, but doing so without mandates or funding risks producing only reputational pressure and methodological disputes — and may struggle to drive the investments needed to meet ambitious peak‑reduction goals while keeping rates and emissions from rising.
SB 541 builds a public, analytical framework rather than enforceable targets, and that design creates its own implementation frictions. The CEC must translate a high‑level load‑shifting goal into program‑level contributions and cost‑effectiveness scores; doing so requires defining common measurement units, baselines, attribution rules, and avoided‑cost assumptions.
Those methodological choices materially influence which measures look best on paper (for example, storage vs behavioral programs) and therefore which initiatives attract funding or political support. Because the statute requires periodic updates to the standards as the CEC “learns more,” early years will likely see evolving methodologies and revisions to past estimates, complicating trend interpretation.
Another unresolved issue is coordination among agencies and jurisdictions. The bill calls for consultation with CPUC, CAISO, and other balancing authorities, yet it preserves CCA and local public utility autonomy.
That balance can produce inconsistency: CCAs or POUs may adopt different evaluation approaches or program priorities, making statewide aggregation and fair comparison difficult. The statutory exclusion of emergency program reductions avoids double counting but raises practical questions about when an event or program qualifies as “emergency” versus routine flexibility.
Finally, the statute’s nonbinding nature means public reporting becomes the primary enforcement tool; reputational pressure can influence behavior, but without procurement mandates or funding levers the CEC and state policymakers may find it hard to close the gap between targets and achieved load shifting if suppliers choose not to act.
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