How California utility Wildfire Mitigation Plans work under AB 1054

AB 1054, Chapter 79 of the Statutes of 2019, ties a California utility's wildfire liability protection to its wildfire mitigation plan. Energy Safety approves the plan; the CPUC approves the cost in a general rate case. A safety certificate requires the utility to be implementing the plan. Without one, the Wildfire Fund reimbursement cap does not apply.

PacifiCorp's approved wildfire mitigation plan for 2026 through 2028 raises its annual pole clearing target in Local Responsibility Areas from 3,126 poles to 3,192. The Office of Energy Infrastructure Safety approved that plan on April 15, 2026. The California Public Utilities Commission decides separately whether the utility may recover what the clearing costs.

The clearing itself goes out under contract. The records that contract produces are what the state reads the following year. AB 1054 is the statute that binds those five facts to each other. It is why a vegetation crew's paperwork now sits on the same chain as a utility's balance sheet.

What AB 1054 put at stake

AB 1054 was approved by the Governor and chaptered on July 12, 2019, as Chapter 79 of the Statutes of 2019. It was an urgency measure and took effect immediately. It created a Wildfire Fund that pays third-party damages arising from utility ignitions, but only above a floor. Public Utilities Code section 3280 sets that floor in its definition of eligible claims:

Claims for third-party damages against an electrical corporation resulting from covered wildfires exceeding the greater of (1) one billion dollars ($1,000,000,000) in the aggregate in any year, or (2) the amount of the insurance coverage required to be in place for the electrical corporation pursuant to Section 3293 or 3299.4, as appropriate, measured by the amount of that excess.

Below that line the utility pays. Above it the fund may.

The same section allocates the fund's burden between the three large investor-owned utilities by a Wildfire Fund allocation metric, built from each utility's share of high fire threat district land area and of high fire threat district line miles. Section 3280 then states what the Legislature expected those shares to be.

Electrical corporation	Expected Wildfire Fund allocation metric
Pacific Gas and Electric Company	64.2 percent
Southern California Edison Company	31.5 percent
San Diego Gas and Electric Company	4.3 percent

That metric decides how much of the fund a utility pays for. A different provision decides how much it pays back. Under section 3292, when the Commission disallows wildfire costs, the utility's obligation to reimburse the fund is capped at the lesser of the disallowed amount or 20 percent of its total transmission and distribution equity rate base, measured across three consecutive calendar years. Section 3292(h)(3) then names the two circumstances in which the cap disappears:

Paragraph (2) does not apply under either of the following circumstances: (A) If the administrator determines that the electrical corporation's actions or inactions that resulted in the covered wildfire constituted conscious or willful disregard of the rights and safety of others. (B) If the electrical corporation failed to maintain a valid safety certification on the date of the ignition.

One missing certificate on one ignition date removes a cap measured in a fifth of a utility's equity rate base. The same certificate moves the burden of proof. Section 451.1(c) reads:

An electrical corporation bears the burden to demonstrate, based on a preponderance of the evidence, that its conduct was reasonable pursuant to subdivision (b) unless it has a valid safety certification pursuant to Section 8389 for the time period in which the covered wildfire that is the subject of the application ignited. If the electrical corporation has received a valid safety certification for the time period in which the covered wildfire ignited, an electrical corporation's conduct shall be deemed to have been reasonable pursuant to subdivision (b) unless a party to the proceeding creates a serious doubt as to the reasonableness of the electrical corporation's conduct.

Without the certificate the utility proves its conduct was reasonable. With it, an opposing party has to raise serious doubt first. That is the whole commercial weight of AB 1054 resting on one annual document. The document itself rests on the wildfire mitigation plan. This is the structure SB 901 left unfinished a year earlier.

The certificate rewards implementation, not filing

Section 8389(a) lists seven things an electrical corporation must document to get a safety certificate from the Director of Energy Safety. The first is an approved wildfire mitigation plan under section 8386.3(a). The seventh is separate. It is the one that reaches a field crew:

The electrical corporation is implementing the mitigation strategies in its approved wildfire mitigation plan. The electrical corporation shall file a notification of implementation of its wildfire mitigation plan with the office and an information-only submittal with the commission on a quarterly basis that details the implementation of both its approved wildfire mitigation plan and recommendations of the most recent safety culture assessments by the commission and office, and a statement of the recommendations of the board of directors safety committee meetings that occurred during the quarter.

Having a plan and implementing a plan are two separate conditions in the same list. A utility that filed well and executed badly fails the seventh condition while satisfying the first.

The clock is annual. Section 8389(b) sets four points on it.

• A certificate is valid for the 12 consecutive months following issuance.

• The utility must request the next one before the current one expires.

• Energy Safety issues the new certificate within 90 days of the request, a period it may extend in writing for good cause.

• A certificate stays valid until the office acts on a pending request.

The remaining conditions, including the board safety committee and the executive compensation structure, are set out in what a safety certification requires.

The quarterly notification is assembled from completion data. Miles completed, poles cleared, findings remediated. A contractor's closed work orders are the raw material for a filing that keeps a liability cap in place.

Two approvals, two agencies, two dockets

The plan is approved by the Office of Energy Infrastructure Safety. Government Code section 15473 places it "in state government, within the Natural Resources Agency." Section 15475 describes it as the "successor entity to the former Wildfire Safety Division," the unit that reviewed these plans from inside the CPUC.

Section 8386.3(a) gives the office nine months from submission to approve or deny, with power to extend that deadline in writing. The same subdivision requires the office to consult the Office of the State Fire Marshal on every review. PacifiCorp submitted its 2026-2028 base plan on July 11, 2025, and received its decision on April 15, 2026. What happened between those two dates belongs to the three-year WMP cycle.

Approval of the plan settles nothing about its cost. Energy Safety puts that in a footnote, on the page where it summarizes a utility's projected expenditures:

Energy Safety's WMP evaluation and decision on a WMP is not an approval of, or agreement with, costs listed in the WMP.

The money is the Commission's. Section 8386.4(a)(1) requires the CPUC to consider the cost of implementing each plan in the general rate case and to approve the costs for wildfire risk mitigation programs and activities it determines are just and reasonable. Section 8386.4(a)(2) lets the Commission authorize a memorandum account for unforeseen incremental wildfire work, subject to later disallowance.

From January 1, 2027, the two approvals are wired together. Section 8386(c)(1) requires each electrical corporation to file a preliminary plan covering the same period as its general rate case, at the earliest of one year before the rate case application or concurrent with its Risk Assessment Mitigation Phase application. Section 8386.4(b) then sets the sequence for rate case applications filed after that date:

Within 45 days of the commission's decision rendered pursuant to paragraph (1) of subdivision (a) or any commission order modifying that decision, the electrical corporation shall submit a revised wildfire mitigation plan to the office that conforms to the commission's revenue authorization. The office shall review and either approve or request modifications to the revised wildfire mitigation plan submitted in accordance with the revenue authorized pursuant to paragraph (1) of subdivision (a). The office shall approve the revised wildfire mitigation plan within two months of submission.

For a bidder, the practical consequence is a restatement risk with a known trigger date. A plan's volumes are written against a forecast. If the Commission authorizes less revenue than the forecast assumed, the utility has 45 days to file a plan that fits the smaller number. Program volumes move with it. A rate case decision is therefore a scope event. How a master services agreement handles volume that moves is the contractual half of that problem.

What the plan obliges, in the words of one decision

Section 8386(d) lists what a plan must contain. Paragraph (9) requires "plans for vegetation management" and paragraph (10) requires "plans for inspections of the electrical corporation's electrical infrastructure." The full contents list runs far longer. One paragraph names contractors directly. It is paragraph (22)(C):

Monitor and audit the effectiveness of electrical line and equipment inspections, including inspections performed by contractors, carried out under the plan and other applicable statutes and commission rules.

The obligation is the utility's. The evidence is the contractor's. A QA program that samples completed work, grades it and generates corrective actions exists because this paragraph requires the utility to show one.

What that looks like in a real decision is specific. In the PacifiCorp decision, Energy Safety compared three utilities' vegetation priority timelines and printed the comparison as a table.

Priority condition	Bear Valley	Liberty	PacifiCorp
Level 1 remediation	4 hours	24 hours	24 hours
Level 2 remediation	30 days	30 days	90 days
Level 3 remediation	normal cycle	9 months	180 days

Energy Safety concluded that PacifiCorp's 90-day Level 2 timeline was longer than its peers' 30 days. It issued an area for continued improvement, PC-26B-17, requiring PacifiCorp in its next base plan to:

Align its remediation timeline for Priority Level 2 condition vegetation with its peers, or justify why it has not aligned its remediation timeline for Priority Level 2 condition vegetation with its peers.

A second requirement in the same item obliges PacifiCorp to produce an updated version of its Transmission and Distribution Vegetation Management Program Standard Operating Procedure. A remediation interval and a standard operating procedure are both things a contract prices and a crew works to. Both were changed here by a state decision rather than by a negotiation.

Two footnotes in that comparison are worth a procurement reader's attention. Energy Safety sourced Bear Valley's timelines partly from "Bear Valley RFP VM Services, page 5." A utility's own request for proposal was read as evidence of what the utility does.

Energy Safety also recorded that PacifiCorp's standard operating procedure was not consistent with its plan as of the R2 submission. What a contractor is told to do in the field and what the utility told the state it does are separately visible. The gap between them is auditable. What Energy Safety's audits actually examine is its own subject.

Where the schedule is unsettled right now

The WMP framework is in the middle of a rewrite. SB 254, 2025 California Legislative Service Chapter 119, became law on September 19, 2025, and amended Public Utilities Code sections 8386, 8386.3 and 8389 among others. Energy Safety stated its own position in the PacifiCorp decision:

The schedule for upcoming WMP submissions is pending development due to ongoing implementation of 2025 California Legislative Service Chapter 119 (Senate Bill 254, Becker) ("SB 254"). SB 254, which became law on September 19, 2025, impacts WMP cycles, submission schedules, and technical requirements, and imposes new and amended statutory requirements on the existing WMP process.

So the timing of the next base plan is genuinely open. The agency that will close it is Energy Safety, through a published submission schedule and revised WMP Guidelines. The Commission decides the revenue. The Legislature decides the statute. Until that schedule is published, crew capacity planned on a fixed next filing date is planned on a guess. A bid that assumes a three-year cadence should say so as an assumption.

Where the plan meets the purchase order

A wildfire mitigation plan is a public commitment to volumes. PacifiCorp's 3,192 poles a year is a number the utility has already told the state it will clear, in a document the state approved. Work at that scale is bought under contract. The terms it is bought on carry the plan's structure forward.

Three consequences follow for anyone bidding into this work.

• The volumes in a solicitation trace to an approved plan, so a bidder can read the commitment before the scope of work is drafted. Approved plans and decisions sit in Energy Safety's WMP docket.

• The plan's audit obligation under section 8386(d)(22)(C) arrives in the contract as recordkeeping and quality requirements. Flow-down clauses are how a statutory duty on the utility becomes a contractual duty on the crew.

• Volumes stated per unit in a plan are usually bought per unit. Unit price mechanics and contractor scorecards are where the plan's targets and the plan's quality obligations respectively land on an invoice.

All of that is AB 1054's chain, one link further down than the statute reads: an ignition at one end, a signed completion record at the other.

Further reading

• What a utility safety certification requires: The seven conditions behind the certificate that keeps the reimbursement cap in place.

• PUC 8386 and the obligations it places on a utility: The statutory contents list a wildfire mitigation plan has to satisfy.

• The three-year WMP cycle and what changes between filings: Pre-submission, revision notice, errata, decision, and what moves in between.

Frequently asked questions

What did AB 1054 actually change for California utilities?

It created the Wildfire Fund, which pays third-party damages from utility ignitions above a floor set in Public Utilities Code section 3280, and it created a safety certificate that a utility must hold on the date of an ignition. Section 3292(h)(2) caps what a certified utility repays the fund after a disallowance at 20 percent of its transmission and distribution equity rate base over a three-year measurement period. Section 3292(h)(3)(B) removes that cap entirely if the utility failed to maintain a valid safety certification on the ignition date.

Who approves a Wildfire Mitigation Plan, and who approves what it costs?

Two different bodies. The Office of Energy Infrastructure Safety, which sits in the Natural Resources Agency under Government Code section 15473 and is the successor to the CPUC's Wildfire Safety Division, approves or denies the plan under Public Utilities Code section 8386.3(a). Energy Safety states in its own decisions that its approval is not an approval of the costs listed in the plan. The California Public Utilities Commission approves the cost of implementing the plan in the general rate case under section 8386.4(a)(1).

Does filing a Wildfire Mitigation Plan satisfy AB 1054?

No. Public Utilities Code section 8389(a)(1) requires an approved plan, and section 8389(a)(7) separately requires that the electrical corporation is implementing the mitigation strategies in it, with a quarterly notification of implementation filed with Energy Safety and an information-only submittal to the CPUC. A certificate is valid for 12 consecutive months under section 8389(b)(1), so the implementation showing is made again every year.

How do WMP targets reach a contractor?

As numbers a utility has already committed to in a public document. PacifiCorp's approved 2026-2028 Base WMP raised its annual pole clearing target in Local Responsibility Areas from 3,126 poles to 3,192. Energy Safety's April 15, 2026 decision on that plan cited Bear Valley's request for proposal for vegetation management services as evidence of Bear Valley's remediation timelines, so procurement documents are part of the record the state reads.

Is the WMP submission schedule settled?

Not as of Energy Safety's April 15, 2026 decision on the PacifiCorp 2026-2028 Base WMP, which states that the schedule for upcoming WMP submissions is pending development because of ongoing implementation of SB 254. Separately, Public Utilities Code section 8386(c)(1) requires each electrical corporation beginning January 1, 2027, to submit a preliminary plan covering the same period as its general rate case. Energy Safety decides the submission schedule and revises its WMP Guidelines.