SB 905 directs the California Energy Commission (CEC), working with the Public Utilities Commission (PUC), to create the Policy-Oriented and Wildfire Electric Reimbursement (POWER) Program and an associated state fund to reimburse electrical corporations and local publicly owned electric utilities for specified public-policy-driven expenditures. Reimbursements must be used to reduce ratepayer costs, are excluded from an electrical corporation’s rate base, and any asset portion funded by reimbursement will carry no return on equity for that proportion.
The bill also directs the PUC to cut the authorized return on equity for particular capital costs (for example, items recovered in balancing accounts, costs exempted from reasonableness review, and undergrounding), launch a performance-metrics process for large utilities, require executive incentive pay tied to limits on average electricity cost, conduct a rulemaking on alternative financing, and force large utilities to publish distribution utilization and off-peak capacity data. Together, these changes reallocate who pays for policy-driven investments and reshape investor incentives and transparency around grid capacity and planning.
At a Glance
What It Does
Creates the POWER Program and Fund at the CEC to reimburse utilities for qualifying public-policy expenditures; requires reimbursements to reduce ratepayer costs and to be excluded from rate base with no ROE on reimbursed asset shares. Separately, the PUC must adopt performance metrics, reduce ROE for specified capital categories, require incentive pay linked to average cost limits, hold a financing rulemaking, and mandate public distribution-utilization data.
Who It Affects
Large electrical corporations and local publicly owned electric utilities, their shareholders and creditors, distributed energy resource developers and interconnection applicants, and residential and commercial ratepayers (with emphasis on low-income affordability programs). State budget and legislative appropriations are implicated because reimbursements come from an appropriated state fund.
Why It Matters
The bill uses state appropriations to cover some non-safety, public-policy electricity spending and changes regulatory accounting and compensation rules to reduce ratepayer bills. That shifts financial risk from ratepayers to the state and investors, changes incentives for capital deployment (including wildfire mitigation and undergrounding), and increases transparency around grid hosting capacity — all of which affect utility finance, procurement, and third-party project development.
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What This Bill Actually Does
SB 905 establishes the Policy-Oriented and Wildfire Electric Reimbursement (POWER) Program at the California Energy Commission and creates a dedicated state fund. The program reimburses electric utilities — both investor-owned electrical corporations and local publicly owned utilities — for defined expenditures driven by public policy rather than by safe and reliable delivery obligations.
Eligible categories include transportation and building electrification, public-purpose programs, equity and affordability programs, distributed energy resource incentives, and wildfire mitigation. For investor-owned utilities the bill requires PUC approval of the underlying expenditures; for public utilities, governing-board approval suffices.
A central accounting rule in the bill is that any portion of a utility’s expenditures reimbursed from the POWER Fund is excluded from that electrical corporation’s rate base, and assets funded by those reimbursements carry no return on equity for the reimbursed share for the lifetime of that share. The CEC must adopt annual spending plans, publish them, report annually to the Legislature on actual utility bill impacts, and is limited to administrative costs equal to the lesser of 3% of appropriated funds or $5 million per year.On the regulatory side, the PUC must begin a proceeding (by January 1, 2028) to build a performance-metrics framework for large electrical corporations covering reliability, utilization, interconnection timeliness, spending by function (distribution, transmission, generation, wildfire mitigation), greenhouse-gas intensity, and average cost to customer classes.
Utilities must, where feasible, provide ten years of historical data and the PUC must post a public dashboard. The PUC may set targets but cannot make financial incentives contingent on achieving those targets.
The bill also mandates that certain senior executives whose pay is rate-funded have at least 20% of compensation contingent on keeping average electricity cost growth within the federal Social Security COLA over a three-year window.SB 905 instructs the PUC to evaluate alternative financing methods that could substitute for shareholder equity and potentially lower the cost of capital recovered in rates; it requires utilities to file annual reports identifying financing opportunities and requires a PUC report to the Legislature by December 31, 2028. Finally, the bill obligates large electrical corporations to publish distribution-segment data that quantify capacity utilization, off-peak load-hosting capacity, and the locations of constrained distribution areas to help third parties target distributed-resource projects and inform distribution planning.
The Five Things You Need to Know
The CEC-run POWER Fund must reimburse only expenditures that serve public-policy goals and provide a public benefit beyond safe, reliable delivery (examples: transportation/building electrification, low-income programs, wildfire mitigation).
Any share of an electrical corporation’s expenditure reimbursed by POWER is excluded from its rate base and that reimbursed share of an asset carries no return on equity for the lifetime of that share.
The CEC may spend no more than the lesser of 3% of program appropriations or $5,000,000 per year on administrative and overhead costs.
The PUC must assign a reduced return on equity for capital costs that are recovered through balancing accounts, costs exempted from reasonableness reviews, and costs tied to undergrounding — with the reduced ROE set when the costs are first authorized.
Large electrical corporations must publish distribution-utilization data including a capacity utilization metric, off-peak load-hosting capacity estimates, and geolocated constrained-area information to enable third-party DER planning.
Section-by-Section Breakdown
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Definitions for POWER Program
This section sets the program’s terminology: who counts as an electric utility (investor-owned electrical corporations and local publicly owned electric utilities), what the Fund means, and what the Program is called. It narrows the Fund’s reach to distribution utilities and connects the statutory definitions to existing PUC code cross-references, which matters because later approval and reporting duties differ by utility type (PUC approval for investor-owned utilities; governing-board approval for public utilities).
POWER Program rules, eligibility, spending plan, and admin cap
These provisions direct the CEC, in consultation with the PUC, to design the reimbursement program and to adopt annual spending plans. Reimbursements must be for expenditures driven by public policy that benefit the general public and cannot replace costs required for safe, reliable service. For investor-owned utilities the PUC must have approved the expenditures; for public utilities the governing board must approve them. The Article also requires that reimbursements reduce ratepayer costs (not shareholder returns) and strictly limits program overhead to the lesser of 3% of appropriations or $5 million annually — a concrete constraint on administrative overhead that will influence program staffing and vendor use.
Establishment of the POWER Fund
Creates the Policy-Oriented and Wildfire Electric Reimbursement Fund in the State Treasury and makes reimbursements subject to legislative appropriation. Because payments depend on appropriation, program scale, timing, and predictability will be governed as much by the Legislature and the state budget process as by regulatory design — a structural point that affects utility planning and the program’s ability to guarantee reimbursements.
Performance metrics, public dashboard, and incentive-pay linkage
Requires the PUC to open a proceeding by January 1, 2028 to build a performance-metric framework covering distribution and transmission reliability and utilization, interconnection timeliness, capital/expense spending, wildfire mitigation, GHG intensity, and average customer cost. Utilities must provide up to 10 years of historical data and the PUC must publish a public dashboard. The PUC may set targets but the bill bars conditioning company financial incentives on meeting those targets. The section also mandates that certain vice presidents (and higher) with rate-funded pay structure have at least 20% of total compensation contingent on keeping average electricity cost growth below a narrow threshold tied to the federal Social Security COLA over a rolling three-year window — a novel regulatory lever linking executive pay to customer cost outcomes.
Reduced return on equity for specified capital costs
Directs the PUC to apply a reduced ROE (computed as a deduction from the authorized ROE) to capital costs included in the rate base that fall into three buckets: costs recovered through balancing accounts, costs exempted from reasonableness review, and undergrounding costs. The PUC must set the reduced ROE when the costs are first authorized and may base the reduction on lower investor risk from faster recovery, exemption from reasonableness review, or risk reductions due to wildfire mitigation — concretely linking regulatory compensation to perceived changes in shareholder risk.
Rulemaking on alternative financing and annual reporting
Requires a PUC rulemaking to explore alternative financing structures that could substitute for shareholder equity in distribution, generation, and transmission investments, and directs utilities to file annual opportunity reports. The PUC must report findings and recommendations to the Legislature by December 31, 2028. Practically, this starts a process to test mechanisms (e.g., low-cost state loans, infrastructure banks, or ratepayer-backed bonds) that might lower the weighted-average cost of capital used in retail rates.
Public distribution-utilization and constrained-area data
Requires large electrical corporations to publish segment-level data quantifying capacity utilization, off-peak load-hosting capacity, and the locations of constrained distribution areas. The PUC may adopt targets and timelines for improving utilization. Utilities must include an assessment of utilization in distribution planning. Making this data public is intended to reduce informational barriers for DER developers and to let the PUC evaluate grid-hosting opportunities, but it raises questions on granularity, privacy, and data standardization for third-party use.
Clarifying nonbypassable local distribution rate component
Makes nonsubstantive edits to existing language that requires electrical corporations to identify a separate, nonbypassable rate component for local distribution service and to allocate those funds to in-state programs. The technical change preserves the long-standing mechanism for collecting nonbypassable charges while aligning it with the bill’s other programmatic changes.
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Every bill creates winners and losers. Here's who stands to gain and who bears the cost.
Who Benefits
- Residential and commercial ratepayers — especially low-income customers: POWER reimbursements must be used to lower bills or fund affordability programs, directly reducing the ratepayer share of public-policy costs.
- Local governments and agencies pursuing electrification and wildfire mitigation projects: the program creates a reimbursement path for associated utility expenditures, lessening the rate impact of public-policy projects.
- Distributed energy resource (DER) developers and third-party project sponsors: mandated publication of distribution utilization and off-peak hosting-capacity data reduces information asymmetries and helps site projects where the grid can accept them.
- Local publicly owned electric utilities (POUs): the statute allows POUs to access reimbursements subject to governing-board approval, providing an alternative funding source without the PUC approval step required for investor-owned utilities.
- State policymakers and planners: the CEC’s spending plan and legislative reporting create a mechanism to direct state appropriations toward public-policy priorities while tracking bill impacts.
Who Bears the Cost
- Shareholders of investor-owned electrical corporations: exclusion of reimbursed amounts from rate base and removal of ROE on reimbursed asset shares reduce the regulated return on a portion of utility investments.
- Utility investors and creditors: reduced ROE for certain capital categories and the prospect of alternative financing could raise perceived risk or push investors to demand higher returns elsewhere.
- Electrical corporations (operations and compliance teams): new reporting, data publication, and participation in the CEC/PUC processes will increase administrative and compliance burdens.
- The State General Fund and Legislature: reimbursements require appropriation, which creates a fiscal demand on state resources and competes with other budget priorities.
- The PUC and CEC (regulatory workload): the bill imposes new proceedings, dashboards, annual reports, and data-review responsibilities that will require staff time and potentially new funding or reallocation.
Key Issues
The Core Tension
The bill confronts a classic trade-off: lower electric bills for ratepayers today by substituting state funding and regulatory constraints for investor returns versus preserving clear investment incentives and cheap private capital for long‑term grid modernization — a choice between immediate consumer relief and potential longer-term impacts on utility financing, deployment speed, and the mix of future investments.
The bill pivots funding for public-policy electricity programs from ratepayers to state appropriations and regulatory constructs, but it leaves unresolved how sustainable and predictable that funding will be. Because reimbursements come only after appropriation, utilities and project sponsors face timing and certainty risk: a legislative appropriation shortfall or delay could leave projects stranded or shift costs back to ratepayers.
The statute’s test that reimbursed expenditures must “provide a benefit to the general public and not just to ratepayers” will require the CEC to draw fine lines between overlapping categories (for example, when a wildfire mitigation project both protects general public safety and directly reduces a utility’s future liabilities).
Excluding reimbursed amounts from rate base and denying ROE on reimbursed shares reduces the regulated return on those investments — that protects ratepayers but can increase the effective cost of attracting capital for the remaining rate-based investments. Utilities might respond by shifting investment toward projects that remain eligible for ROE, accelerating capital spend in some categories, or seeking higher returns via risk premiums.
The bill also creates potential for strategic behavior: utilities could structure programs to qualify for reimbursement rather than bearing costs in rate base, and regulators will need robust audit, clawback, and attribution rules to prevent gaming. Finally, increased public data on distribution constraints helps market actors but raises technical questions on data formats, confidentiality, and whether greater transparency will actually expedite interconnections at scale without parallel reforms to interconnection processes.
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