In April 2026 the Public Utility Commission of Texas established guidelines requiring electric cooperatives and municipal utilities to file wildfire mitigation plans, not only investor-owned utilities. PNNL found that historically low-fire regions including the Northeast, Southeast, Southern Great Plains, and Midwest hit an inflection point in 2019–2020, with fire occurrence from 2020 to 2024 running 9 to over 70 times higher than the prior decade (PNNL, Current Best Practices on Wildfire Risk Reduction for Electric Transmission and Distribution Systems, November 2025).
For a growing number of co-ops, wildfire is a year-round condition rather than a season. That puts weight on monitoring, because before you decide what to do about wildfire risk you have to be able to see it.
There is no single wildfire feed. SEPA's Wildfire Technology Landscape report maps five vendor platforms across six stages of risk reduction, all at varying levels of depth.
Weather: days ahead
Temperature, humidity, wind speed and direction, and dead fuel moisture combine into the conditions that make ignition likely. Fire weather indices and red flag warnings package those conditions into something you can act on. Usually there's a lead time of about five days, but sometimes it's as short as a few hours.
Instead of one daily rating for a whole service territory, modeling can now map risk hour by hour and area by area, and commercial platforms run continuous five-day hourly forecasts at the circuit level.
SEPA's advisors describe fire weather monitoring at co-ops and public power utilities as a seasonal duty carried inside normal grid operations. Readiness comes from regional partnerships that can include a shared camera network and a working relationship with the state forestry agency.
Vegetation and fuels: seasonal
Weather tells a utility when to expect fire activity. Vegetation tells them where to expect it.
Live fuel moisture, drought conditions, and the proximity of trees and brush to conductors are all indicators for where a spark is most likely to becomes a fire. Remote sensing, satellite imagery, and field surveys build that picture.
Many cooperatives are contemplating a cycle-based versus risk-based vegetation management. Some co-ops in the southwest are shifting from cycle to risk across its wildland urban interface territory, while others in the midwest, a region with historically lower wildfire risk, use fuel data to prioritize and clear vegetation.
Your own grid: hours to months
We've learned over and over that the grid itself can start fires, and frequently, the grid gives plenty of signal as risk increases.
Query your reclosers and feeders: Recloser operation counts, feeder-level momentary interruption history, and outage cause codes already sit in your historian and your outage management system (OMS). Pull three to five years, sort by feeder, and cross-reference against your high fire risk area. Someone builds that report in an afternoon.
Monitor AMI last-gap messages: Advanced metering infrastructure (AMI) last-gasp messages, voltage sag events, and momentary flags give you a distribution-level view of where the system is misbehaving.
Deploy waveform analytics: Waveform analytics for arcing, partial discharge, and incipient faults need line sensors plus a platform to interpret them.
A feeder that throws repeated momentaries on windy afternoons might have a real problem, like a tree limb or loose hardware, but wind can also make a line blink so that fact alone means nothing. The best signal comes from comparison. If one feeder showed twelve momentaries while the surrounding feeders show two the line is worth a patrol.
Where is risk highest?
The question stops being whether today is dangerous, it becomes which of your assets are exposed today. One northeast utility assessed thousands of feeders and found that 1 percent of them account for roughly a third of total wildfire risk.
Data is the crucial foundation
All of this data exists, but it lives in four different places. Weather in one system, vegetation surveys in another, supervisory control and data acquisition (SCADA) and AMI in a third, the risk map in a fourth. Seeing any one of them is easy, and seeing them together is the hard part.
SEPA names connected data as a crucial foundation and specifies the minimum inputs: geographic information system (GIS) coordinate accuracy, current asset records, and multiple years of outage history. Utilities that bring their information technology (IT) and GIS teams in before deployment consistently outperform those that don't.
Across twenty major wildfire mitigation plans, roughly $21 billion is committed through 2027, with about 60 percent going to vegetation management and 35 percent to hardening. That leaves under 5 percent for the monitoring technology that tells you where to aim the other 95 percent.
The real risk is a wildfire dashboard nobody has open at 4 p.m. on a windy Tuesday while the operator watches the SCADA alarm list. If your alert does not show up where the operator is already looking, it does not exist.
The short version
| Layer | Question | Lead time | Where it comes from |
|---|---|---|---|
| Weather | When are conditions dangerous? | Days to hours | Fire weather indices, red flag warnings, hourly modeling |
| Vegetation and fuels | Where is fuel heavy? | Annual to seasonal | Satellite and aerial imagery, field surveys |
| Your own grid | Is my equipment the risk? | Hours to months | Historian, OMS, AMI, line sensors |
| Exposure | Which assets are affected? | Instant, once built | GIS connectivity model |
Monitoring narrows the field. It tells you where and when to look, and it does not tell you what to do. SEPA's six-stage framework and state policy maps show where each layer fits, and which states now require a plan.
