SB 618 requires every local publicly owned electric utility and electrical cooperative in California to prepare, update, and publicly present a wildfire mitigation plan that explicitly addresses when and how the utility will disable reclosers or deenergize distribution lines. The statute lists detailed plan content — from metrics and vegetation management to geographic risk identification — and obliges utilities to adopt procedures for notifying affected customers, first responders, health facilities, and telecom operators.
The bill also requires utilities to adopt “appropriate and feasible” procedures for compensating customers impacted by deenergization, and to contract with qualified independent evaluators to audit plan comprehensiveness. For compliance officers, emergency managers, and utility planners, SB 618 formalizes expectations about planning cadence, public reporting, risk mapping, and the narrow but important task of defining compensation and notification around power shutoffs.
At a Glance
What It Does
The bill requires municipal utilities and electrical cooperatives to submit wildfire mitigation plans annually (with a comprehensive revision at least every three years) to the California Wildfire Safety Advisory Board. Plans must include deenergization/recloser protocols, customer notification procedures, a risk inventory, performance metrics, restoration plans, and procedures for compensating customers affected by deenergization.
Who It Affects
Directly affects California’s local publicly owned electric utilities (municipal utilities) and electrical cooperatives, their contractors who perform infrastructure inspections and vegetation work, customers within deenergization footprints (including health-care and telecom facilities), and first responders and public safety offices that must be notified of outages.
Why It Matters
SB 618 converts previously ad hoc deenergization practices into documented, auditable obligations and forces utilities to confront compensation and notification logistics up front. That shifts implementation risk onto utilities and creates new compliance and budgeting demands, while giving communities clearer expectations about shutdowns and recourse.
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What This Bill Actually Does
SB 618 formalizes wildfire-risk management for California’s locally owned utilities by turning a set of planning elements into annual obligations. Each utility must prepare and update a wildfire mitigation plan and submit it to the California Wildfire Safety Advisory Board by July 1 each year; at least once every three years the utility must deliver a comprehensive revision.
The statute preserves an initial-plan requirement for pre-2020 plans but primarily establishes a recurring cadence for planning, public presentation, and comment.
The bill prescribes the plan’s contents in detail. Utilities must assign responsibilities, state clear objectives, and describe preventive strategies that account for changing climate risks.
Plans must identify and justify the metrics utilities will use to measure effectiveness and explain how prior performance informed current measures. Utilities must map and prioritize wildfire risks across their territories, flag areas they consider higher threat than existing commission maps, and explain where expansions of high fire-threat districts may be warranted.SB 618 zeroes in on deenergization as an operational tool: utilities must set protocols for disabling reclosers and deenergizing parts of the distribution system, and those protocols must consider impacts on public safety, first responders, health-care facilities, and telecommunications.
The statute requires feasible procedures for notifying customers and critical infrastructure operators and requires utilities to include practical procedures for compensating customers affected by outages caused by deenergization. Finally, utilities must hire a qualified independent evaluator to assess the plan’s comprehensiveness, publish the evaluator’s report online, and present it at a public governing-board meeting — creating a public audit trail and an external check on plan quality.
The Five Things You Need to Know
Utilities must submit their wildfire mitigation plan to the California Wildfire Safety Advisory Board on or before July 1 each year, with a comprehensive revision required at least once every three years.
The statute requires plans to include protocols for disabling reclosers and deenergizing distribution segments that explicitly consider impacts on first responders, health-care facilities, and telecommunications infrastructure.
Plans must identify geographic areas the utility considers a higher wildfire threat than current commission fire-threat maps and indicate where the commission should expand high fire-threat districts.
Utilities must adopt and document appropriate and feasible procedures for compensating customers who may be impacted by deenergization events, though the bill does not prescribe a specific compensation formula.
Each utility must contract with a qualified independent evaluator experienced in assessing electrical infrastructure safety; the evaluator’s report must be posted online and presented at a public meeting of the utility’s governing board.
Section-by-Section Breakdown
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General duty to minimize wildfire risk
This opening clause places an affirmative duty on local publicly owned electric utilities and electrical cooperatives to construct, maintain, and operate lines and equipment to minimize wildfire risk. Practically, that frames every subsequent requirement: plan elements, inspections, vegetation management, and deenergization protocols must be directed toward that statutory objective, which can be cited in enforcement or oversight contexts.
Planning cadence and public presentation
The statute requires an annual plan cycle: utilities must prepare a wildfire mitigation plan and submit it to the California Wildfire Safety Advisory Board by July 1 each year, and present it in a noticed public meeting that accepts comments. At least once every three years a submission must be a comprehensive revision. For utility compliance teams this creates recurring deadlines, public-record obligations, and a routine stakeholder engagement process that utilities must staff and budget for.
Governance, metrics, performance auditing, and restoration planning
These subparts require utilities to specify who is responsible for plan execution, to state objectives, and to define the metrics used to measure performance — and to explain the assumptions behind those metrics. Utilities must show how past metric performance changed current plans, describe enterprise-wide risk methodologies, and provide a restoration plan for returning service after wildfires. The requirement to audit implementation and corrective action procedures raises the bar for recordkeeping and internal controls; utilities will need documented inspection programs and evidence of contractor oversight.
Deenergization protocols, notification, and customer compensation procedures
This cluster focuses on the operational and human impacts of power shutoffs. Utilities must adopt protocols for disabling reclosers and sectionalizing power that explicitly weigh public-safety trade-offs and identify mitigation measures for critical users. The plan must include feasible customer-notification procedures that extend to public safety offices, first responders, health-care facilities, and telecom operators within the potential deenergization footprint. Critically, the statute requires utilities to include procedures for compensating customers affected by deenergization, but leaves the mechanics of those procedures to the utilities.
Inspections, vegetation management, and localized risk mapping
These provisions require inspection plans, vegetation-management strategies, and a prioritized list of wildfire risks tied to equipment, maintenance, and geography. Utilities must identify where local topography or microclimates create higher threat levels than state commission maps show and recommend map expansions where appropriate. For operations teams that means more granular risk assessments and potentially different investment priorities across service territories.
Independent evaluator: contract, report, and public disclosure
SB 618 requires utilities to retain a qualified independent evaluator with experience in electrical-infrastructure safety to assess plan comprehensiveness. The evaluator must produce a report that the utility posts online and presents in a public governing-board meeting. That creates an external validation mechanism but also raises procurement, scope-of-work, and independence questions utilities must resolve when selecting evaluators.
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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 within deenergization footprints — they gain documented notification procedures and a promised process for compensation, which creates a clearer path for economic recourse and planning before outages.
- First responders and critical-infrastructure operators — mandatory notification protocols give emergency managers, hospitals, and telecom operators advance information to shift operations, deploy backups, or request exemptions.
- Regulators and advisory boards — the California Wildfire Safety Advisory Board and other oversight bodies receive annual, comparable plans and independent evaluator reports, improving transparency and enabling targeted oversight.
Who Bears the Cost
- Local publicly owned electric utilities and electrical cooperatives — they must pay for annual plan development, comprehensive triannual revisions, more granular risk mapping, expanded inspection and vegetation programs, notification systems, and independent evaluators.
- Utility ratepayers and municipal budgets — the compliance, contractor oversight, and compensation-procedure costs are likely to be reflected in utility budgets or municipal funding decisions, potentially raising rates or local expenditures.
- Smaller cooperatives and under-resourced utilities — these entities face disproportionate administrative and contracting burdens to deliver the same level of documentation, auditing, and notification infrastructure as larger utilities.
Key Issues
The Core Tension
The bill wrestles with a classic trade-off: reduce catastrophic wildfire risk by enabling and documenting preemptive deenergization, while avoiding the secondary harms that outages create for public safety, health-care delivery, and economic activity; requiring compensation and notification addresses those harms but shifts costs and decision-making burdens onto utilities, forcing them to choose between conservative shutoffs and maintaining essential services.
SB 618 leaves key implementation details undefined, producing both flexibility and uncertainty. The statute requires “appropriate and feasible” customer compensation procedures but does not define eligibility criteria, payment triggers, valuation methods, or timelines.
That gap lets utilities tailor compensation to local circumstances — which can be efficient — but also risks inconsistent outcomes across service territories and legal disputes about adequacy.
Operational tensions emerge between the statute’s safety-first duty and the new obligations to protect critical services and compensate customers. Protocols for disabling reclosers and deenergizing lines must weigh fire-risk reduction against the immediate harms of outages (medical-device failure, communications disruption, impeded emergency response).
Translating the statute’s notification and mitigation language into reliable on-the-ground processes will require investments in data, mapping, and real-time coordination with local agencies. Finally, the independent-evaluator requirement improves public scrutiny but raises procurement and independence questions: who qualifies, how independence is enforced, and whether evaluators will be able to assess subjective elements like “appropriate” compensation or the sufficiency of mitigation strategies.
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