Rethinking Utility Vegetation Management

California’s worst wildfire season is challenging regulators and utilities to come up with new mitigation approaches

The 2017 California wildfire season raged as the most destructive on record, with more than 9,000 fires claiming 43 lives and burning more than 1.2 million acres. It also includes the largest fire, as well as the 20 most destructive fires in the state’s history. The investigations into these fires’ causes are ongoing, but these events have sharpened the focus on wildfire prevention strategies and the role of electric utilities.

Electric infrastructure is one of the top sources of wildfire ignition and has contributed to several of the most destructive fires in California’s history, including the 2007 Witch and 2015 Butte fires that together burned more than 260,000 acres, destroyed 2,571 structures and caused four deaths.

Rethinking  Utility Vegetation  Management California's worst wildfire season is challenging regulators and utilities to come up with new mitigation approaches By Elizaveta Malashenko, California Public Utilities Commission

The California Public Utilities Commission (CPUC) collects data on all instances of fire ignitions from electric infrastructure operated by the investor-owned utilities (IOUs) in California. More than 2,000 ignitions have been reported since 2014 and most of them resulted in fires of less than a quarter acre. Contact between electric equipment and vegetation is the leading cause, representing roughly a quarter of all fire ignitions. This finding makes it clear that vegetation management is critical for fire hazard reduction.

California has advanced efforts to prevent wildfires with some of the most stringent vegetation management regulations in the U.S. The aftermath of the 2017 wildfire season is pushing the state even further to examine approaches that unite safety and environmental goals, while also focusing on costs.

California addresses growing threat of destructive wildfires

California state agencies, counties and stakeholders along with the U.S. Forest Service collectively work to understand and address threats to 33 million acres of forests state-wide. The strategy is to identify the highest fire threat areas and introduce management practices into forests to render them more resilient to fire and preserve the multiple benefits that forests provide—water retention, erosion control, wildlife habitat and recreational opportunities.

In late 2017 and early 2018, the CPUC adopted a series of regulations to further enhance the fire safety of overhead electric power lines and communication lines located in high fire-threat areas. Working with the California Department of Forestry and Fire Protection, the U.S. Forest Service and stakeholders from across the state, the CPUC developed and adopted state-wide fire-threat maps that consider historical fire data, tree mortality, and likelihood and potential impacts on people and property. The new regulations require utilities to maintain strict vegetation clearances and mandate that they prioritize safety hazard corrections based, in part, on whether the safety hazard is in a high fire threat district. To assist in these timely mitigation activities, electric utilities may now disconnect service to customers who refuse to provide access to their property for pruning or removal of trees that pose an immediate threat.

To further bolster these efforts, in January 2018, California Governor Edmund G. Brown Jr. called for a task force of scientists and forest management experts to find ways to reduce the wildfire threat to California. Likewise, utilities are being challenged to rethink current approaches to vegetation management.


Utility vegetation management practices have typically focused on maintaining clearances and eliminating obvious safety hazards, which have proven insufficient in preventing wildfires and other incidents. The current paradigm has misaligned incentives for planting, pruning and tree removal. The result is that risks continue to increase and costs grow.

The traditional approach to vegetation management is based on maintaining a required clearance level. The North American Electric Reliability Corp. (NERC) sets vegetation clearance requirements for transmission, while California and Oregon are two of the few states that have strict clearance requirements for electric distribution systems. Vegetation clearance requirements by themselves, however, are not sufficient to prevent wildfires or ensure that vegetation does not cause safety and reliability incidents, principally because wind causes trees to fail unexpectedly. Arborists cannot predict which trees will fail under wind conditions exceeding 55 miles per hour, but even tree failure (structural failure or breakage of a tree trunk, branch or root) with winds of 25 miles per hour are hard to predict. Consequently, any tree that is theoretically tall enough to contact an electric facility if it fails constitutes a fire hazard.

Without standards and rigorous methodology for identifying vegetation hazards “outside” of required clearances, utilities typically rely on vegetation management contractors to decide how vegetation should be maintained. During an inspection cycle, a forester or utility arborist typically identifies any vegetation that needs pruning or removal and then a qualified tree contractor does the work. It’s not unusual for this process to be paper-based with utility management taking a hands-off approach and making few decisions beyond where and when to order the work. Vegetation management contractors benefit from conducting inspections and frequent pruning, while utilities typically pass this operational cost to ratepayers. For most utilities, vegetation management tends to be one of the largest expense items associated with maintaining the grid. California’s IOUs spend more than $250 million a year on vegetation management on distribution lines alone.

As urban regions in the state expand and development strains the wildland-urban interface, vegetation management costs continue to grow. It seems that little effort is dedicated to ensuring that vegetation that might grow or fall into power lines at maturity is not planted. Land owners do not directly bear the ongoing maintenance cost associated with vegetation planted in proximity to electric lines. Local ordinances, where they exist, typically apply only to trees in public space and rarely address interaction of vegetation with power lines.

Often, landscaping decisions are made with no consideration for electric infrastructure. Utilities have no control over vegetation planted outside of their rights of way and generally become aware of vegetation only after it has become a threat. The lack of incentives to plant the right vegetation in the right place has a major impact. A study done in Phoenix in 2006, for example, found that more than 70 percent of trees inspected were improperly planted such that they would ultimately need to be removed. In California, Pacific Gas and Electric Co. (PG&E) reported an incident in which a developer planted 300 redwood trees directly under power lines and declined to move them when it was pointed out that the trees must be pruned or removed.

The combination of misaligned incentives and inefficient practices result in excessive costs and unclear results. The ignition statistics alone indicate that not enough is being done to systematically reduce the risks associated with the interaction of electric infrastructure and vegetation.


To progress further, utilities must directly engage in the vegetation management decision-making process and use rigorous analytical methods to assess vegetation risks, identify mitigation activities and measure performance.

The first steps of any vegetation management program should be inspection, data collection and risk assessment. While traditional visual and invasive inspections are still essential, the results of those inspections must be adequately recorded and reported within an appropriate data platform that enables infrastructure conditions to be evaluated. In addition, to obtain better data, utilities should expand the use of light detection and ranging (LiDAR) and aerial imagery. If applied correctly, technologies such as LiDAR improve the efficiency and effectiveness of identifying dangerous trees and vegetation encroachments, aid in the predictive modeling of vegetation growth patterns, provide comprehensive geospatial geographic information system (GIS) right-of-way inventories and assist in identifying high fire risk areas. Utilities frequently use LiDAR and aerial patrols on the transmission system, but until recently LiDAR surveys were too expensive for utilities to use them as part of routine operations at the distribution level. Prices have now come down enough to make it feasible for utilities to perform LiDAR surveys annually as part of their comprehensive vegetation management programs. A high level of variation still exists, however, in the quality of LiDAR inspections and the type of data analytics performed. Utilities using LiDAR only to identify clearance issues are missing the main value of LiDAR surveys, which is to build a better understanding of all risks. The value of this investment is expected to expand. UC Davis Center for Spatial Technologies and Remote Sensing, for example, is working with the U.S. Forest Service and NASA Ames Research Center on ways to use the recently activated Geostationary Operational Environmental Satellite for systematic rapid first discovery and confirmation of wildfire ignitions over high fire danger regions.

The output of LiDAR and other surveys should result in a detailed vegetation risk analysis that is then used to prioritize further inspections. In California where wildfire threat is the top concern, utilities should use the combination of CPUC fire-threat map, LiDAR survey results and patrols to create schedules for detailed on-the-ground vegetation inspections by foresters. Ground inspections can then be used to develop tactical plans for pruning and vegetation removal. With this approach, the inspection and pruning cycles become risk-driven, not schedule-driven.

Beyond LiDAR, utility vegetation management can be improved by using big data and advanced analytics. Outage and fault detection data should be analyzed in conjunction with vegetation risk information to continuously improve a utility’s understanding of risks and to assess mitigation measures’ effectiveness. Utilities should be setting performance goals to drive down ignitions and outages due to vegetation contacts. As data collection and analysis matures, specific performance goals can be embedded into contracts between utilities and vegetation management contractors to assure proper incentives along the value chain.

The greatest long-term potential for improvements in vegetation management comes from the integration of utility infrastructure into urban and rural forest environments. One of the frequent barriers to utility vegetation management activities is that they are often seen as environmentally unfriendly and result in visually unappealing landscapes. This does not, however, need to be the case. It is possible to plant vegetation that does not require pruning while also increasing canopy cover. The key is to plant vegetation that is compatible with its environment and surrounding infrastructure, a concept that’s promoted by utilities through “Right Tree Right Place” programs. Local governments should look to promote or even mandate “Right Tree Right Place” practices as part of a cohesive community wildland fire management plan.

In addition, programs that promote drought tolerant landscaping and planting of species native to their environment can be combined with planting vegetation that’s compatible with utility infrastructure. At the transmission level, there has been a growing focus by utilities to adopt “integrated vegetation management” practices that reduce the need for pesticides, promote healthy ecosystems and provide measurable results. There are promising results from several research efforts that examine pollinator communities on actively managed transmission rights-of-ways, including a study being done by Sonoma State University and PG&E.

In sum, utility vegetation management is an area that’s ripe for cultural change, innovation and creative solutions. Wildfire threat is challenging California regulators and utilities to rethink vegetation management practices and priorities, but there is no need for any utility to wait for another disaster to strike to start making improvements.

Elizaveta Malashenko is director of Safety and Enforcement Division at the California Public Utilities Commission (CPUC). In her current role, she oversees utility and rail infrastructure safety for California, leading a team of more than 200 safety experts. Malashenko’s focus is on modernizing the state’s approach to infrastructure by expanding the safety program to go beyond compliance by incorporating risk assessment and getting creative about how to address both emerging and long-term issues, such as cybersecurity and wildfire threat mitigation. Prior to working at the CPUC, Malashenko was a strategy consultant with IBM’s Energy and Utilities Practice, where she spearheaded client-facing strategy engagements, business process transformation programs and system implementation efforts. Malashenko has a bachelor of arts degree in economics and political science from University of Pennsylvania.

Elizaveta Malashenko is director of Safety and Enforcement Division at the California Public Utilities Commission (CPUC). In her current role, she oversees utility and rail infrastructure safety for California, leading a team of more than 200 safety experts.


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