This bill directs each electrical corporation to prepare and file comprehensive wildfire mitigation plans on a recurring schedule that emphasizes risk reduction, public safety, and transparency. The plans must include preventive strategies, deenergization and recloser protocols that account for critical responders and medically dependent customers, metrics and audits, workforce readiness, and specific accounting for permanently abandoned transmission facilities (with removal and hazard-mitigation plans).
The measure forces utilities to quantify trade-offs (including cost-per-avoided ignition and cost-efficiency comparisons between mitigation alternatives), posts plans online for public comment, and ties preliminary filings to utility rate case and Risk Assessment Mitigation Phase schedules. Practically, the bill raises new compliance requirements, creates clearer public oversight, and embeds difficult cost-versus-risk decisions into utility planning and capital programs.
At a Glance
What It Does
The bill requires electrical corporations to submit wildfire mitigation plans at least once every four years and, beginning January 1, 2027, a preliminary plan timed to a utility’s general rate case or Risk Assessment Mitigation Phase filing (independent transmission owners excepted). Plans must include protocols for disabling reclosers and deenergization, circuit-by-circuit risk lists, workforce readiness, undergrounding analysis, metrics, audits, and accounting for permanently abandoned transmission facilities with removal plans.
Who It Affects
Investor-owned electrical corporations subject to the bill’s filing and planning obligations are the primary regulated entities; independent transmission owners are excluded from the preliminary submission requirement. Emergency managers, public safety agencies, telecommunications and health-care operators, contractors who inspect or maintain lines, and customers reliant on medical baseline allowances are directly implicated by notification, service-restoration, and backup-power provisions.
Why It Matters
The bill pushes wildfire risk decisions deeper into utility planning and rate proceedings by requiring quantified trade-offs (e.g., cost-per-avoided ignition) and public posting of plans for comment, which can influence capital allocation (undergrounding, hardening) and operations (use of deenergization). It also brings permanently abandoned transmission facilities into the mitigation frame, creating new removal obligations and potential cost and liability issues.
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What This Bill Actually Does
The bill builds a structured, recurring planning process around wildfire risk for each electrical corporation. At its core it requires a comprehensive mitigation plan at least every four years and, starting in 2027, a preliminary plan timed to the utility’s general rate case or concurrent with its Risk Assessment Mitigation Phase filings, so regulators and stakeholders can align review and funding discussions with rate proceedings.
Independent transmission owners are carved out of that preliminary-filing timing requirement.
What belongs in each plan is detailed and operational. Utilities must list who is responsible for plan execution, state clear objectives, and describe specific preventive strategies that account for changing climate conditions.
The bill requires metrics, documented assumptions, and retrospective discussion of how past metrics shaped current planning, which creates an audit trail connecting outcomes to management decisions and lays the groundwork for regulator evaluation.Operational realities get particular attention. Utilities must document deenergization and recloser-disable protocols that explicitly weigh public-safety impacts and set procedures for notifying public-safety offices, critical first responders, health-care facilities, and telecommunications operators.
The bill requires special consideration for customers on medical baseline allowances and allows utilities to deploy or assist with backup power only when customers meet strict criteria (life-support reliance, demonstrated financial need, and lack of alternate backup sources).The plans must also be granular about where mitigation will occur: they must identify and prioritize wildfire risks across territory, estimate cost-per-avoided ignition for identified risks (or explain why that cannot be done), present cost-efficiency comparisons for at least two mitigation alternatives for a given risk, and include workforce-readiness and disaster-response planning. For transmission infrastructure the bill adds a new bookkeeping obligation: utilities must list in-service, out-of-service, and permanently abandoned transmission facilities and provide removal plans and induction-mitigation measures for the abandoned items.
Finally, the bill requires the office to post plans online for public review for no less than two months and to accept comments before the office issues its approval decision.
The Five Things You Need to Know
The bill mandates wildfire mitigation plans at least once every four years and ties preliminary plan submissions (starting Jan 1, 2027) to a utility’s general rate case or Risk Assessment Mitigation Phase filing; independent transmission owners are excluded from that preliminary timing requirement.
Plans must include protocols for disabling reclosers and deenergizing lines that explicitly address impacts on critical first responders, health and communications infrastructure, and customers with medical baseline allowances.
Utilities must identify circuits frequently deenergized during past events and present measures and estimated annual declines in deenergization, including options such as hardening, replacing, or undergrounding.
Each plan must account for permanently abandoned transmission facilities: list them, provide schedules for removal, and describe wildfire-hazard mitigation (including induction risks) for those facilities.
The office must post submitted plans on its website for at least two months before its approval decision, accept public and agency comments, and verify plan compliance with applicable rules and standards.
Section-by-Section Breakdown
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Duty to minimize wildfire risk in design and operations
This subsection imposes a broad, continuing obligation on each electrical corporation to construct, maintain, and operate lines and equipment to minimize catastrophic-wildfire risk, requiring utilities to weigh implementation time, cost, and remaining risk when choosing mitigation measures. Practically, this creates a legal benchmark against which the adequacy of specific investments and operational decisions (e.g., vegetation management cadence, inspection intervals, equipment upgrades) can be judged by regulators and stakeholders.
Filing schedule and preliminary-plan timing
The office must set a schedule for comprehensive plan submission at least once every four years and may stagger plans across utilities to smooth evaluation loads. Beginning January 1, 2027, the bill requires a preliminary plan to be filed either one year before a utility’s general rate case or concurrently with its Risk Assessment Mitigation Phase application, aligning mitigation planning with funding and regulatory review—except for independent transmission owners, who are excluded from that preliminary-timing rule.
Core plan elements and deenergization protocols
These paragraphs list required core elements: responsibility accounting, objectives, preventive strategies that consider dynamic climate risks, and measurable metrics with underlying assumptions and a retrospective assessment of prior plan performance. They also require detailed protocols for disabling reclosers and deenergizing distribution sections, and mandate that those protocols consider public-safety consequences and specific subgroups—most notably critical first responders, healthcare and communications infrastructure, and customers with medical baseline allowances—while permitting targeted deployment or financial support for backup power when narrow eligibility criteria are met.
Notification, circuit prioritization, undergrounding, workforce, and customer supports
This block demands operational detail: procedures for notifying impacted customers and agencies (including multi-language outreach), an identification of circuits frequently subject to deenergization and plans to reduce that need, vegetation management and inspection programs, and a mandate to show the utility has an adequately sized, trained restoration workforce (including mutual-aid considerations). Plans must present cost-efficiency measures for at least two mitigation alternatives for a given risk, discuss undergrounding in high-risk areas mapped by the commission, and outline service-restoration and customer-support protocols (billing adjustments, payment plans, and suspension of fees during emergencies).
Monitoring, abandoned transmission accounting, and public posting
Utilities must describe monitoring and audit processes to evaluate plan implementation and contractor inspections, identify and correct deficiencies, and align enterprise-wide risk methodologies with peers unless the commission directs otherwise. Importantly, the bill requires a full accounting of transmission facilities—including permanently abandoned transmission facilities—and a plan for removing those abandoned assets plus mitigation for associated hazards such as induction. The office is required to post submitted plans online for a minimum 60-day public-review window prior to its approval decision and to accept comments and verify regulatory compliance.
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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
- Customers in high fire-threat areas — gain clearer, territory-specific mitigation plans and prioritized measures such as undergrounding or hardening that target circuits with repeated deenergization, potentially reducing outage frequency and fire risk in their neighborhoods.
- Public safety and emergency responders — receive mandated, pre-event notification protocols and must be considered in deenergization plans, improving coordination and reducing the chance that safety-critical services are cut off without contingency.
- Medically dependent customers who meet the bill’s narrow eligibility — get an explicit path to utility-provided or utility-funded backup electrical resources when they demonstrate life-support reliance, financial need, and lack of other backup options.
- The office and regulators — obtain standardized, auditable plans with metrics, retrospective analyses, and public comment records that improve oversight and make it easier to compare utilities’ risk-reduction choices.
- Communities and local governments — benefit from publicly posted plans and prioritization data to better align local emergency planning and land-use decisions with utility mitigation activities.
Who Bears the Cost
- Electrical corporations (regulated utilities) — must expend staff time and resources to produce detailed plans, acquire data for cost-per-avoided-ignition calculations, develop notification systems, buy or finance backup power for eligible customers, remove abandoned transmission facilities, and fund capital projects such as undergrounding.
- Ratepayers — may face higher rates over time if regulators allow recovery of substantial capital investments (undergrounding, pole replacement, abandoned-facility removal) and increased operations and maintenance tied to expanded mitigation programs.
- The office and commission staff — absorb administrative burdens from reviewing more-detailed plans, managing public comment windows, and enforcing compliance, potentially requiring additional staffing or resources.
- Contractors and inspection vendors — face more rigorous audit and documentation requirements of inspection results and repair timelines, increasing contract oversight and quality-assurance costs.
Key Issues
The Core Tension
The bill pits aggressive, measurable wildfire-risk reduction (undergrounding, preemptive deenergization, removal of abandoned facilities) against the real costs, reliability impacts, and equity concerns those measures create: reducing ignition risk often means expensive capital projects or service interruptions that burden ratepayers and vulnerable customers, and the statute leaves regulators wrestling with how to weigh safety gains against financial and operational trade-offs.
The bill forces hard measurement choices into utility planning—most notably by requiring cost-per-avoided-ignition estimates and cost-efficiency comparisons between mitigation alternatives. Those metrics are conceptually useful but technically fraught: assigning an avoided-ignition value requires probabilistic modeling, standardized exposure definitions, and choices about the value of avoided losses, all of which can be manipulated by assumptions or bedevil cross-utility comparability.
Regulators will need to prescribe methodologies or face apples-to-oranges submissions that limit the metric’s usefulness.
Operationally, the deenergization provisions create tension between immediate risk reduction and other public-safety priorities. Disabling reclosers and preemptive deenergization reduce ignition risk but increase risks for life-sustaining equipment, telemetry, and first-responder operations; the bill tries to mitigate that by requiring protocols and narrow eligibility for utility-supported backup power, but the criteria (financial need, lack of alternate resources) raise practical and equity questions—who documents need, who verifies eligibility quickly during an event, and who pays where eligibility is borderline.
The abandoned-transmission requirement likewise raises allocation questions: removing long-abandoned facilities can be expensive, technically challenging, and pose questions about who bears historical liability and removal costs, especially where ownership has changed or pensioned assets remain on private land.
Finally, transparency is double-edged. Posting detailed plans and circuit-level risk data improves public scrutiny and emergency coordination but creates security and operational risks if sensitive infrastructure details are exposed.
The office will have to balance disclosure with protections for critical infrastructure while ensuring the public and local entities have enough information to meaningfully comment and coordinate.
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