AB1975 directs the California Public Utilities Commission (CPUC) to create a “grid utilization metric” that measures electrical load as a percentage of rated distribution capacity, and to require large electrical corporations to report that metric quarterly. The bill requires the CPUC to set an annual minimum utilization value (which may rise over time), tie performance-based incentives or disincentives to meeting that minimum if there is a net customer benefit, and require utilities to file programs to meet the minimum.
Separately, AB1975 amends the criteria the CPUC must weigh when ordering the location of utility structures to add anticipated maintenance costs. The combined effect pushes utilities and regulators to prioritize using existing distribution capacity, incorporate maintenance cost considerations into siting orders, and align incentives and planning toward cost-effective electrification while preserving reliability.
At a Glance
What It Does
Requires the CPUC, by Dec. 31, 2027, to define a grid utilization metric (peak and average) calculable at circuit, substation, and territory levels; mandates quarterly public reporting from large electrical corporations; sets annually rising minimum targets and performance-based financial incentives or penalties tied to net customer benefit.
Who It Affects
Directly affects investor-owned large electrical corporations (as defined in Pub. Util. Code §2827), CPUC planners and ratemaking staff, demand flexibility and DER providers, and ratepayers who fund distribution investments through rates.
Why It Matters
The bill changes the regulatory objective from primarily building capacity toward maximizing existing asset use, potentially reducing distribution expansion spending, shifting utility investment decisions, and making CPUC metrics and incentive design central to how California accommodates electrification demand.
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What This Bill Actually Does
AB1975 puts measurement and targets at the center of distribution planning. The CPUC must create a metric that expresses electrical load as a percentage of rated capacity, and that metric must be measurable separately for peak and average conditions and at granular levels (individual circuits and substations) as well as aggregated across a utility’s territory.
Utilities must publish those calculations each quarter so regulators and the public can see how much of installed distribution capacity is actually in use.
The CPUC then has to set a minimum grid utilization value for each large utility’s distribution grid every year and may ratchet that minimum upward over time. The statute requires the commission to design the minimum so it encourages — and does not discourage — electrification, leaving room for segmentation of minimums by planning area.
The commission must also adopt financial performance incentives or penalties linked to meeting the minimum, but only if the commission finds the mechanism yields a net benefit to retail customers.Utilities are not left without responsibility: by July 31, 2028, each large electrical corporation must file proposed grid utilization programs showing how it will hit the minimums. The commission will gate those proposals on feasibility and cost-effectiveness and must weigh customer costs and benefits, reliability impacts, maximizing existing infrastructure, and the use of demand-flexibility technologies.
The bill also directs the CPUC to develop a way to quantify the ratepayer savings from increased utilization so incentive decisions can be tied to measurable customer benefits.Finally, AB1975 amends the statutory factors the CPUC must consider when ordering structure locations to add anticipated maintenance costs. That change forces maintenance-cost tradeoffs into siting decisions that the commission orders under existing authority.
The Five Things You Need to Know
The CPUC must adopt a grid utilization metric by December 31, 2027, that reports both peak and average load as a percentage of rated capacity and can be calculated at the circuit, substation, and territory levels.
Each "large electrical corporation" must file a publicly available quarterly report with its grid utilization calculations for individual circuits, substations, and its whole service territory.
The CPUC will set an annual minimum grid utilization value for each utility’s distribution grid, may increase that minimum year-to-year, and can segment increases by distribution planning area or other divisions.
Performance-based incentives or disincentives tied to meeting the minimum are permitted only if the CPUC determines they produce a net benefit for retail customers; the commission must also create a method to quantify ratepayer savings from increased utilization.
By July 31, 2028, each large electrical corporation must propose grid utilization programs; the CPUC will approve only programs that are feasible and cost-effective and that consider costs/benefits to customers, reliability, existing infrastructure use, and demand-flexibility technologies.
Section-by-Section Breakdown
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State rationale for prioritizing utilization
This section lists the legislature’s findings: expected load growth, low average utilization of distribution circuits, and a link between higher utilization and lower distribution costs. Practically, this frames the bill’s policy goal—reduce distribution expansion spending by timing or shaping load growth—so regulatory decisions must be read through an affordability-and-utilization lens going forward.
Define a measurable grid utilization metric
Subsection (a) requires the CPUC to adopt a metric that reports load as a percentage of rated capacity and explicitly requires both peak and average measurements and the ability to calculate at circuit, substation, and aggregated levels. That granularity matters for targeting interventions and for comparing utilization across heterogeneous parts of a utility system; it also creates technical requirements (data collection, telemetry, baselining) utilities must implement.
Quarterly, public reporting by large electrical corporations
Subsection (b) obliges large electrical corporations to file quarterly, publicly available reports containing their utilization calculations for circuits, substations, and territory. The requirement increases transparency and creates a recurring compliance task—data validation, public dashboards or filings, and potential CPUC audits or data standardization work.
Annual minimums and incentives tied to net customer benefit
Subsection (c) directs the CPUC to set annual minimum utilization values, with the option to raise them and to segment targets by planning area. It also requires the CPUC to ensure minimums do not discourage electrification. Subsection (d) authorizes performance-based incentives or disincentives tied to meeting those minimums, but only if the CPUC finds a net benefit to retail customers—linking incentive design to quantifiable customer savings and opening a technical rulemaking on how to measure net benefit.
Utility program filings and quantifying ratepayer savings
Subsection (e) compels each large electrical corporation to propose programs by July 31, 2028, aimed at meeting minimums; the CPUC can approve only feasible, cost-effective programs and must consider customer costs, reliability, infrastructure maximization, and demand-flexibility measures. Subsection (f) mandates the CPUC create a method to quantify ratepayer savings from increased utilization, which will be central to incentive calculations and cost–benefit reviews.
Add anticipated maintenance costs to siting considerations
The bill amends Section 762.5 to require the CPUC, when ordering locations of utility structures, to include findings on anticipated maintenance costs in addition to community, recreational, historical/aesthetic, and environmental factors. That insertion shifts siting decisions to account for longer-term operating expenses, not just upfront or nonfinancial considerations.
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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
- Residential and small commercial ratepayers — if the CPUC’s metric and incentives successfully raise utilization without costly tradeoffs, fewer distribution expansions should be needed, which can lower the distribution component of rates over time.
- Demand-flexibility and distributed energy resource (DER) providers — the bill explicitly elevates demand-flexibility technologies in program evaluation, creating market opportunities for providers whose services increase local utilization (e.g., managed charging, demand response, behind-the-meter storage).
- Regulators and planners — CPUC gains standardized, granular utilization data and a statutory mandate to align incentives with utilization objectives, improving the information base for distribution planning and for evaluating electrification impacts.
Who Bears the Cost
- Large electrical corporations (investor-owned utilities) — they must build or upgrade measurement, telemetry, data management, and reporting systems, design and implement grid-utilization programs, and potentially accept financial penalties if performance targets aren’t met.
- Ratepayers in the short term — some grid-utilization programs (pilot deployments, demand-flexibility incentives, or software platforms) will require up-front spending that may be recovered through rates; the statute requires net customer benefit but allows near-term costs to be incurred to achieve long-term utilization gains.
- Third-party developers and local planners — they may face new interconnection or operational expectations if utilities push load-shaping solutions onto customers' sites; smaller DER vendors may need to meet utility data and interoperability requirements to participate.
Key Issues
The Core Tension
The bill forces a classic trade-off: squeeze more use from existing distribution assets to lower long-run distribution costs, versus preserving spare capacity and redundancy to accommodate rapid electrification and ensure reliability. Achieving both requires precise measurement, calibrated incentives, and transparent cost-allocation—areas the bill mandates but leaves technically complex and politically fraught decisions to the CPUC.
The bill prioritizes utilization as a policy objective but leaves crucial technical design choices to the CPUC. How the commission measures peak and average load, how it aggregates or segments circuits, and what baseline constitutes “rated capacity” will determine whether targets drive efficient outcomes or produce perverse incentives (for example, shifting load timing without reducing net system costs).
Tying incentives to a finding of "net benefit for retail customers" creates a necessary guardrail but also a high evidentiary bar: the CPUC must develop credible methods to quantify ratepayer savings and to attribute savings to utility actions versus broader system changes. That measurement challenge interacts with timing: utilities will need clear guidance on allowable cost recovery for program investments made to achieve future utilization targets, or they will underinvest to avoid penalties.
The statute also asks the CPUC to ensure minimums do not inhibit electrification, but it provides no formula for resolving cases where higher utilization targets conflict with short-term electrification needs in specific localities.
Finally, adding anticipated maintenance costs into siting orders tightens the economic lens on location choices, but it risks elevating cost calculations over community, historical, or environmental values without specifying how to weigh them. Implementation will require new data collection, inter-agency coordination on environmental reviews, and careful rulemaking to prevent gaming of utilization metrics or unintended reductions in local reliability margins.
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