How Small Utilities Can Adapt Big Wildfire Strategies

Wildfire seasons are growing longer and more intense, placing even small electric utilities under pressure to protect their communities. Investor-owned utilities (IOUs) in high-risk areas, especially in the western U.S., have poured resources into wildfire mitigation measures like insulated power lines, aggressive equipment upgrades, and Public Safety Power Shutoffs. Rural electric cooperatives and municipal utilities face the same rising wildfire risks but often with a fraction of the budget and workforce of a large utility.

The good news is that smaller utilities can adapt “big utility” wildfire strategies in scaled-down, cost-effective ways to significantly reduce ignition hazards. This post explores practical measures––from prioritizing covered conductors on critical lines to leveraging pole inspection data ––that community-owned utilities can implement.

Prioritize covered conductors on high-risk lines

Line workers install covered (insulated) conductors on distribution lines in forested areas as a wildfire hardening measure. Covered conductors (as illustrated in Figure 1, below) greatly reduce arcs and sparks if contact occurs with trees or debris. Southern California Edison (SCE), for example, installed thousands of miles of covered conductor in wildfire zones as part of its grid-hardening program. Studies by utilities indicate this measure can cut wildfire ignition drivers by approximately 60–90%.

Figure 1: Utility pole with covered conductor in a ‘tree wire’ configuration.

Even if smaller utilities, such as a small cooperative or municipal utility, do not have the resources to blanket all their lines with covered wire, they can target the most critical spans in high fire-risk zones.  This strategic installation on high-risk segments can yield big safety gains. The key is to prioritize the worst danger zones: sections of line that run through dense vegetation, areas with frequent high winds, or near communities at the wildland-urban interface.

Major utilities found that wildfire risk is not uniform––95% of PG&E’s wildfire risk was traced to just 22% of its distribution lines. A smaller utility can perform a similar analysis (even if informal) to identify the top-risk 10–20% of its lines and focus hardening efforts there. Replacing a few miles of bare wire with covered conductor in those key areas can dramatically reduce the chance of an ignition from a downed line or vegetation contact.

Cost-effective tactics

Smaller utilities can:

• Start with pilot projects––for example, installing a few thousand feet of covered conductor on a particularly vulnerable feeder and monitoring the results. This was the approach taken by Bear Valley Electric Service, a small California IOU that first piloted 10,000 feet of covered conductor in 2019 and, after seeing its effectiveness, proceeded to install 120,000 feet along a critical mountain highway. By phasing in upgrades over several budget cycles, cooperatives and municipals can incrementally harden their highest-risk lines without breaking the bank.
• Seek group discounts by coordinating bulk purchases of covered conductors through joint action agencies or state associations, further stretching each dollar. While covered conductor is not cheap, it is generally far less expensive than undergrounding lines––and it offers significant wildfire safety benefits without the need for extensive trenching or new rights-of-way.

Leverage inspection data for targeted upgrades

Smaller utilities typically conduct regular pole and line inspections for maintenance––this existing data can be a goldmine for wildfire mitigation planning. Rather than treating wildfire hardening as random “spot fixes,” examine past inspection records, outage reports, and even patrol notes to flag equipment and locations that might pose a fire hazard. The key things to look for include aging or damaged hardware (e.g., worn clamps, splices, or insulators that could fail and throw sparks), expulsion fuses that eject hot metal when they blow, and areas with recurring vegetation infringement. These are weak links where a fault could ignite a blaze.

By overlaying inspection data with wildfire hazard maps (fuel loads, historical fire weather), utilities can pinpoint the “hot spots” in their system. A comprehensive study highlighted that long-term wildfire risk reduction requires detailed asset inspections and data analysis, since risk is highly concentrated in specific grid sections. In practice, this means if a cooperative’s records show a certain circuit has had multiple wire-down incidents or equipment issues, and it runs through dry brush, that circuit should move to the top of their mitigation list.

Actionable ideas

Smaller utilities can:

• Develop a simple risk score for each feeder or line segment using available data. For example, assign points for factors like age of line, tree density, wind exposure, past ignition incidents, etc. Then focus improvements where the score is highest. This data-driven prioritization ensures limited funds go to the most consequential fixes.
• Use inspection data to replace old fuse cutouts. Traditional fuse cutouts use explosive “expulsion” fuses that can emit sparks and hot debris when they operate. Many large utilities now swap these for non-expulsion (current-limiting) fuses in fire-prone areas to eliminate that ignition source. A consortium of eight rural electric co-ops in South Dakota recently made such an effort, installing nearly 3,000 non-expulsion fuses and other upgrades to reduce wildfire risk around the Black Hills. A small utility can similarly audit its system to identify and replace a handful of high-risk fuses and connectors as part of routine maintenance. These component-level fixes are relatively low cost but substantially lower the chance of sparks.
• Look into emerging tools that have become more affordable over the years. Drones, for instance, can conduct line inspections in rugged areas, providing high-resolution images of potential problems (cracked insulators, tree branches near lines) that can be acted on quickly. Likewise, inexpensive sensor devices or fault indicators can be placed on remote lines to capture electrical disturbances that might otherwise go unnoticed. When operational data is combined with local knowledge and inspection logs, smaller utilities can create a data-driven mitigation plan of targeted actions, such as: fortify this specific pole, that stretch of wire, and those few pieces of equipment which, if fixed or upgraded, can reduce wildfire ignition risk.

Use strategic recloser automation and settings

Automatic circuit reclosers are invaluable for maintaining reliability––they momentarily shut off power during a fault and then quickly restore it, preventing sustained outages from transient issues (like a branch brushing a line). But in wildfire conditions, the same device can create danger: multiple reclose attempts on a line fault can shower sparks onto dry ground. Big utilities have learned to adjust protection settings during fire season. For example, many now use “fast trip” or one-shot settings in high fire-risk periods, meaning the recloser (or breaker) will cut power instantaneously at the first sign of a fault and not attempt to re-energize until a crew checks the line. SCE began using such fast-trip settings in 2018 and saw a 54% reduction in wildfire ignitions on circuits with fast-trip enabled versus those without. In the same vein, utilities often disable automatic reclosing entirely on days of Red Flag Warnings or extreme weather. These measures sacrifice some reliability in favor of safety––a tradeoff that is justified when conditions could turn a broken line into a major wildfire.

Tighter-scale strategies

Smaller utilities can:

• Develop a recloser operating plan for wildfire season. Many co-ops already do this: for instance, Plumas-Sierra Rural Electric Cooperative (in California’s high-fire territory) has a policy to turn off all automatic reclosing during Red Flag Warning events, ensuring any fault results in an outage rather than repeated electrical arcing. A utility’s plan might include setting all reclosers to one-shot (no reclosing) on hot, dry, windy days, or even manually opening certain sectionalizing devices during the peak afternoon fire risk hours. Modern electronic reclosers and substation relays often allow seasonal setting profiles that can be activated easily; if a utility has these, they can take advantage of that feature. Even older hydraulic reclosers can usually be adjusted or locked out during critical periods (though it may require a crew visit to each device, so focus on the most at-risk circuits).
• Where the budget allows, consider upgrading key reclosers to newer models with remote control (SCADA integration). This enables utility operators to implement protective settings system-wide from the control center as fire weather develops, rather than driving into the field to toggle equipment. The investment can be quite cost-effective relative to its benefit. In fact, a group of small co-ops in South Dakota pooled resources to replace 381 old hydraulic reclosers with electronic reclosers that give them remote control over their grid during high wildfire risk periods. By sharing the costs through a regional grant, these co-ops gained some economy of scale. With remote-enabled reclosers, a cooperative can rapidly disable reclosing or adjust trip settings utility-wide on short notice or even implement “adaptive reclosing” schemes––for example, temporarily changing to more sensitive trips on a dry, windy day and reverting to normal the next week when weather improves.
• In addition to recloser operation, other protective devices can be leveraged. Many small utilities are exploring fault detection tech that larger companies use, like downed-line sensors or arc detectors, which can cut power in fractions of a second if a line breaks. While some of these advanced systems (e.g., distributed sensor networks) might be too costly to deploy everywhere, a targeted installation on a few highest-risk circuits could be feasible. The bottom line is that by smartly configuring the protection equipment you already have––and incrementally automating it––a smaller utility can dramatically reduce the chance that a line fault ignites a fire, all without massive infrastructure build-out. Reliability may take a slight hit on those worst fire days, but that is a small price to pay for potentially preventing a catastrophic blaze.

Conclusion: Building wildfire resilience with limited resources

The road to wildfire resilience is not without obstacles for small utilities, but those challenges can be overcome with ingenuity, collaboration, and determination. Every step–– no matter how incremental––counts. Replacing one old fuse, trimming one hazardous tree, or disabling one recloser on a dry, windy day might well prevent the next devastating fire. For the member-owners and communities served by co-ops and public power, these efforts are about more than protecting electrical assets; they are about protecting lives, property, and the very fabric of rural and small-town life from wildfire devastation.