Before the 2027 fire season, make your wildfire plan provable.

A wildfire mitigation plan is a promise. It says the utility will inspect certain lines, clear vegetation in certain areas, change how the system operates when fire weather arrives, and de-energize when the risk is too high. Through 2026, regulators, legislatures and federal reliability bodies have made it clearer that writing the plan is only half the job. The other half is being able to show that the work was done as written.

For many co-ops and municipal systems, the 2027 fire season is the practical deadline. This article looks at where the rules stand in 2026, what evidence a plan has to stand on, and what operations and compliance teams can set up now.

Where wildfire planning stands in 2026

Several states moved this year, and more filings are scheduled:

• Texas. Under Public Utility Commission of Texas rule §25.60, each electric utility, including municipally owned utilities and electric cooperatives, must submit a wildfire mitigation plan. The plan must address areas of elevated wildfire risk, inspection of poles, lines and other equipment, vegetation management in risk areas, operating plans during high-risk weather, and emergency coordination and communication ¹.
• California. In March 2026 the Wildfire Safety Advisory Board adopted a revised 2026–2029 submission schedule for publicly owned utilities and electrical cooperatives, which must submit plans at least once every four years. Utilities are grouped, with final deadlines falling in 2026, 2027, 2028 and 2029, and the board expects each plan to build on the previous one and show growing maturity ².
• Oregon. The Oregon PUC's April 2026 report notes that investor-owned utilities filed 2026–2028 multi-year plans, and that co-ops, people's utility districts and municipal utilities are also required to have plans, with any updated filing due to the PUC within thirty days of board adoption ³.

Federal work is moving in parallel. NERC published a report in May 2026 on reducing wildfire ignition risk from the bulk power system ⁴, updated its Wildfire Mitigation Reference Guide with errata in July 2026 ⁵, and in July 2026 filed a wildfire action plan with FERC that includes a wildfire reliability guideline expected in 2027 and a review of one or more Reliability Standards beginning in 2028 ⁶. Those documents focus on the bulk power system, but distribution utilities should expect their practices to shape what boards and state regulators ask about.

Why evidence now carries legal and financial weight

The link between a plan and liability tightened further in 2026. An April 2026 review of state wildfire liability limits lists laws in California, Utah, Idaho, Montana, New Mexico, North Dakota, South Dakota, Wyoming, Arizona, Texas and Kansas, and notes that South Dakota's SB 36 was signed into law on March 12, 2026 ⁷. Laws in several of these states use rebuttable presumptions or "deemer" standards under which conduct in conformity with an approved plan is not negligent. In Texas, protection depends on showing a court that the utility complied with its plan "with respect to the specific equipment found to have ignited or propagated the wildfire." In Utah, it depends on the utility having "in fact completed the fire mitigation work" ⁷.

That is a high bar for records. A utility may need to show that a specific device on a specific line was inspected, and that the resulting work was done.

Insurance points the same way. A May 2026 memo from Pacific Northwest National Laboratory to the Oregon Department of Energy describes insurers raising premiums, limiting wildfire coverage or leaving some markets, notes that consumer-owned utilities face similar or greater insurance and financial challenges than investor-owned utilities, and observes that access to California's wildfire fund requires an approved plan ⁸. We cannot say what a particular underwriter will ask for. We expect, though, that a utility able to show both its plan and the record of carrying it out will have a clearer conversation at renewal.

What a plan needs to be able to show

Requirements differ by state, but the evidence behind most plans falls into the same groups:

• Inspections and patrols. Which lines and devices were inspected, when and by whom, what was found, and how each finding was closed. NERC's May 2026 report recommends asset management systems that track equipment down to individual components, including last inspection date, last maintenance date and open work orders ⁴.
• Vegetation work. Work completed against the plan's cycle and clearances, hazard trees removed, and anything deferred, with the reason.
• Operations during fire weather. When protection settings were changed or reclosing was disabled, on which devices, who authorized it, and when normal settings returned. The NERC report recommends protection settings that can be adjusted to changing fire risk, operating with reclosing disabled during periods of high fire risk in high fire risk areas, and not re-energizing after a trip in those areas until line patrols are complete and authorization is received ⁴.
• De-energization decisions. The conditions considered, who made the call, which members were notified and when, the patrol before re-energizing, and the restoration time. NERC describes intentionally turning off power as a last resort ⁴, which makes the decision record especially important.
• Metrics and data governance. NERC's reference guide includes data governance as one of ten plan categories ⁵. The plan's metrics should be traceable back to the underlying records.

Why the evidence ends up scattered

Each of those records usually exists, but in several places at once. Inspection findings sit in a mobile app or spreadsheet. Vegetation work arrives from a contractor as a monthly report. Setting changes live in SCADA event logs or an engineer's notes. De-energization decisions are made on calls and written up afterwards. Member notifications come from another platform. Each source has its own clock and its own name for the same line.

When a board, regulator or court asks for proof, someone has to pull exports, line them up and fill gaps from memory.

What to set up before the 2027 fire season

Over the next 12 to 24 months, we suggest planning for the following, whatever tools you use:

1. Map every plan commitment to a record. For each commitment, decide what record proves it, where it is created and who creates it. Close the gaps before fire season, not during a review.
2. Capture at the time of the action. A finding logged on site with a timestamp and photo is stronger than one typed up at the end of the week.
3. Use one identifier per asset and event. Inspections, vegetation work, setting changes and outages should point to the same feeder, device and incident, so evidence can be assembled for a specific piece of equipment.
4. Record decisions, not just outcomes. For setting changes and de-energization, note who decided, on what information, and who confirmed. Keep approvals with the record.
5. Rehearse the evidence pull. Before the 2027 season, pick a device at random and see how long it takes to produce its inspection, work and operating history. Then fix what slows you down.

Where GridSteward fits

Amplyra GridSteward was built so that evidence is produced while the work happens. Crew briefings carry sign-off and clearance, switching orders keep each step with its readback and second-person check, and field logs hold timestamped notes, readings and photos, all attached to the same incident record with its approvals and audit history. GridSteward does not write your wildfire mitigation plan and does not make protection or de-energization decisions: it advises, and qualified people decide. What it can do is keep the operational record of field work and switching in one place, so less of it has to be reassembled later.

If you would like to see how that record is built, Book a guided tour.

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