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Electric Utility Operations:
CenterPoint Energy Sends Large Temporary Emergency Generation Units to San Antonio
The first five of the 15 large temporary emergency generation units were deployed to the San Antonio area to help address the regional power generation shortfall. https://tdworld.com/55297824
Electrification:
The Role of Electric Vehicles in Grid Resilience and Flexibility
Utilities across the US are piloting Vehicle-to-Grid (V2G) programs in collaboration with fleet operators. https://tdworld.com/55298795
Electric Utility Operations: Emergency Power Measures Activated in Southeast U.S. as Heat Wave Strains Grid
The U.S. Department of Energy (DOE) and the Georgia Public Service Commission (PSC) have each announced actions aimed at addressing the growing strain on the region’s power systems; Sendero Consulting Principal Jay Jayasuriya gives advice to utilities. https://tdworld.com/55299604
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The Past, Present, and Future of Utility Structures
Back in 2021, I had the chance to attend the 100th anniversary celebration of Hughes Brothers, a manufacturer in Seward, Nebraska, known for its wood and steel structures used in electric utility systems. The event brought together manufacturers’ reps, clients, and editors from T&D World for a facility tour, dinner with employees, and a field demonstration. One of the day’s highlights was a live structure test simulating extreme wind loads on an H-frame wood pole reinforced with a steel X-brace. As the wind speed simulation reached 300 mph, the structure finally buckled and collapsed — a dramatic and memorable sight. It was the kind of firsthand field experience that gives editors valuable insight into how these structures perform under stress.
That day also sparked my deeper interest in the ongoing industry debate around wood vs. steel vs. composite structures. Some of the Hughes Brothers representative were firmly in the “Team Wood” camp. But as I began researching the history and evolution of utility poles, I found a fascinating progression of materials and innovations. About a decade ago, T&D World technical editor Gene Wolf wrote a feature titled “The Grid Takes Shape,” outlining how each advancement in structure design — often driven by increased voltage needs — triggered a domino effect of new challenges and solutions. For example, higher voltages required better insulators, which led to the development of stackable disc insulators and longer insulator strings. That, in turn, required stronger hardware and taller poles, which put pressure on wood supply and sparked the exploration of alternative materials.
Steel, Concrete and Composite
Steel and concrete structures entered the mix to meet those evolving demands. Steel lattice towers became popular for their strength and compact footprint, though they were laborintensive to assemble. About 50 years ago, labor-saving tubular steel poles gained favor for being easier to install and lighter than wood — ideal for urban settings and increasingly highvoltage lines like 500 kV and beyond.
Concrete poles, though older than many realize, have also evolved significantly. They were first used in Europe for telegraph lines in the 1850s and improved dramatically with the introduction of spun-cast and later pre-stressed designs, which offered both strength and flexibility. Eventually, manufactur-
ers combined these techniques to balance durability with weight, creating customizable poles tailored to each utility’s needs. Hybrid and composite structures have taken things even further. Companies like Trinity Meyer developed poles that combine a strong lattice base with a tubular top for easier assembly and reduced right-of-way needs. Valmont created a steel-concrete hybrid with a concrete base below ground and a steel top above, optimizing durability and performance. Even wood structures evolved — Laminated Wood Systems now uses bonding techniques and synthetic resins to transform lower-grade or recycled wood into stronger, long-lasting poles. The demonstration I witnessed at Hughes Brothers, with steel components reinforcing a traditional wood structure, exemplified this evolution in action. Composite materials opened an entirely new design frontier. The first fiberglass poles were tested in the 1960s in harsh coastal environments like Maui to combat corrosion issues. Though initially vulnerable to UV exposure, new coatings solved that problem. Over time, manufacturers adopted advanced thermosetting and polyurethane resins to create highly durable, modular pole systems. These allow utilities to mix and match sizes, lengths, and diameters to meet specific project needs — delivering unprecedented flexibility.
Our cover story this month spotlights Ameren Corp.’s approach to hardening its grid against extreme weather. By strategically incorporating fiber-reinforced polymer poles into its wooden sub-transmission systems, Ameren has significantly reduced cascading outages, boosting reliability and customer satisfaction. As Gene once wrote, “Utility engineers have always wanted more choices and selections. They need to modify, change, and improve things like they need to breathe.” That mindset is more critical than ever today, as the industry leans on grid-enhancing technologies to extend the lifespan and capacity of existing infrastructure, especially with new transmission builds lagging behind rising demand.
So, whether you’re Team Wood, Team Steel, or Team Composite, it’s less about loyalty to a material and more about selecting the right tool for the job. Utility structure design has matured well beyond one-size-fits-all, and there are pros and cons to all of them.
With today’s range of materials and hybrid innovations, utilities have more choices than ever to meet their performance, budget, and environmental needs.
There Are Options To SF6
They say one of AI’s strongest characteristics is its ability to find patterns in unstructured data. I wonder what patterns it would find in my unstructured inbox. Most of my emails are about the power grid and it’s technologies, but for the most part the subject matter is scattered all over the place. A few days ago, however, I had several emails discussing the options to sulfur hexafluoride (SF6) gas-insulated switchgear. I hadn’t seen emails about SF6 or its issues for a long time.
It’s one of those subjects that doesn’t readily jump to mind when we’re talking about extreme weather or decarbonization, but it should be. SF6 has one of the highest global warming potentials (GWP) of all greenhouse gases. Its GWP is 24,300 higher than carbon dioxide and can last thousands of years in the atmosphere if leaked from equipment. As I started reading these press releases, it brought back memories of my first encounter with SF6
I had taken the position of senior substation engineer at a southwestern utility and was assigned the task of adding shunt capacitor banks to 10 substations. Each station would have two large parallel 115kV banks installed on its bus. Back in those days, the interruption device of choice was the oil circuit breaker (OCB), but there were problems. Shunt capacitor banks produce high inrush currents and high transient recovery voltages, all of which were beyond OCB technologies.
The Pros & Cons
The solution was a new adaptation of SF6 circuit breaker technology. One that was designed for capacitor bank switching at the 115kV voltage level. SF6 was seen as an amazing medium. Its voltage insulation, current interruption, and arc quenching properties were superior to oil. Also, SF6 circuit breakers required much less maintenance, and it didn’t have the limitations of OCB devices. To be fair, in those days, there wasn’t much talk about global warming or greenhouse gas emissions either. That happened later, but as SF6 became more commonplace some concerns popped up. My first warnings about SF6 gas came at my yearly hazmat recertification classes. The byproducts of SF6 arc quenching were at the top of the hazard list that year. An electric arc inside the SF6 filled breaker tank produces toxic byproducts that are extremely dangerous. So much so, it was recommended that anyone likely to be exposed should wear personal protection equipment.
It wasn’t long after that, the topic of SF6 gas’s GWP started hitting the tradeshows and conferences. From that point on, when SF6 was mentioned the discussion shifted to eliminating SF6 from all transmission and distribution equipment. It took a while, but manufacturers and suppliers accepted the challenging of replacing SF6. It started at the lower end of the voltage and current spectrum, but those have steadily expanded covering a wider range, which is why those emails caught my attention.
What’s the Alternative?
The first one came from a colleague at Siemens Energy. It is expanding the voltage levels of its F-gas-free gas-insulated switchgear (GIS) to the 420kV level with a pilot project in partnership with Elia, Belgian’s transmission system operator. In addition, the European Union (EU) is co-funding the project. The EU has a goal for eliminating F-gases (i.e., specifically gases that contain hydrofluorocarbons) by 2050. The Siemens Energy “clean-air” alternative is mixture of nitrogen and oxygen. The F-gas-free switchgear utilized by this pilot system will replace an existing switchgear in one of Elia’s substations. Another email was from a colleague at Hitachi Energy. They sent me an announcement about Hitachi Energy delivering the world’s first 550kV SF6-free GIS to the Central China branch of the State Grid Corporation of China (SGCC) soon. This 550 SF6-free GIS is part of its EconiQ product portfolio using a mixture of CO2 and oxygen and C4-fluoronitrile gases. SGCC said this project “will contribute to effectively reduce the consumption and emissions of greenhouse gases.” Hitachi Energy has been providing SGCC with 145kV EconiQ GIS and live tank circuit breaker products since 2022.
These emails represent two different alternatives for SF6 replacements from two manufacturers. There are other manufacturers and there are other technologies gaining traction in the quest to replace SF6. So far clean-air, synthetic air, vacuum, and fluoronitrile gas mixtures are the leading contenders. Research is taking place in solid state technologies too. The takeaway here is the fact that options are available and they’re moving into higher voltage and current levels. It’s definitely a trending topic to watch!
SF 6 free 550kV circuit breaker.
Solving The Supply-Demand Dilemma
AI-driven distribution automation is leading the way to a more responsive power system.
Ever since Edison’s Pearl Street station came online, it’s been challenging to match the amount of electricity being generation with the customer’s fluctuating load. It’s a delicate balance requiring constant monitoring and adjustment. Too much generation means wasted electricity and lost money. Not enough electricity and the system becomes unstable. It’s a condition that needs a dynamic solution, but it’s only becoming more challenging as we transition to clean energy. Also, extreme weather events aren’t helping, they’re severely impacting it.
These are constant reminders that the grid’s aging infrastructure needs upgrading, but it’s expensive and slow to happen. In the U.S. more than 70% of transmission line are over 25-years old, with some having reached 100-years of age. Last year only about 125 miles (201 km) of transmission was added. The average age of U.S. power transformers is around 40 years, which isn’t good considering their lifespan is about 25 years. The bottom line here is that the power grid was built a long time ago, for a time and place that no longer exist. Also, it was built using standards there are no longer relevant in today’s ecosystem.
After all, in the 1960s power quality meant keeping the lights on, but in today’s interconnected world even an intermediate power fluctuation costs our customers a lot of money. The term behind-the-meter (BTM) was meaningless in the 1970s, but on our modern power system the BTM segment is an integral part of the power delivery system. In the 1980s 100-year storms were rare storms, but today they’re commonplace and it’s the 500-year that’s happening more often. If that isn’t enough, for several decades electricity demand has been relatively flat and then hyperscale datacenters hit. Last
year the EIA (U.S. Energy Information Agency) announced that electricity consumption has been increasing about 2% annually, and will continue increasing, at that rate, for the next 25 years. That may not sound like much, but a 2% annual growth rate equals a 50% consumption increase over those 25 years. Still, there are technological solutions addressing these issues.
It’s Time for a New Approach
Last month, “Charging Ahead” did a high level assessment of the AI-driven digitalization that’s becoming extremely popular with utilities and grid operators. Mr. Adnan Chaudhry, Siemens Energy’s digital grid guru provided some interesting commentary on how these applications are reshaping the power delivery system. One major takeaway from our discussion was the fact, “continuing to add assets in the grid alone won’t satisfy the growing hunger for electricity.” The
power grid “needs a complete end-to-end digitalization,” and artificial intelligence (AI) is the catalyst making that happen.
Adding AI’s functionality to smart grid applications like AMI (advanced metering infrastructure), community microgrids, and VPPs (virtual power plants) has proven an effective addition for the struggle of supply-demand balancing. AI tames the flood of data from millions of customers’ meters and it makes the assortment of DERs (distributed energy resources) manageable. It allows all those small-scale DERs to be aggregated into a utility-scale resource, which directly addresses the supply-demand issues we’re facing.
When 2024 ended, it was estimated that there were roughly 55 gigawatts of DERs located BTM and they’re mostly small rooftop solar installations. Fiftyfive gigawatts means there’s a profusion of them. Because of EIA’s consumption alert, there is a great deal of interest
Adding transmission infrastructure takes time.
in harnessing this untapped quantity of DERs, which would go a long way in addressing the supply-demand dilemma. Keep in mind, managing these massive numbers of DERs isn’t possible without AI.
Speaking of numbers, remember that old geometry theorem, “The whole is greater than the sum of the parts?” In this case, those parts are AI microgrids, AI VPPs, and AI AMI, but it requires a more advanced technology. It has to be the AI-driven genre, which is the most innovative AI. It uses AI as the predominate force behind the system’s functionality. Also, there’s another component needed for this “whole,” and that’s AIdriven distribution automation. It keeps all the others working together. Before getting deeper into AI-driven distribution automation, let’s review some of the basics associated with the standard distribution automation package.
Managing Complexity
Conventional distribution automation systems have allowed utilities to remotely control and monitor the operation of their distribution systems for years. The earliest systems were limited in their abilities compared to modern schemes. They were strained to their limits as they tried respond to changing requirements of the power system. In addition, real-time response to grid changes was sparse. The introduction of smart grid technologies brought about interconnectedness and big-data, which improved power system awareness.
As the complexity of the distribution automation systems increased, so did the quantities of big-data and there was a marked decrease in user-friendliness. Early forms of machine learning were introduced and they became a real gamechanger. Today more sophisticated forms of AI have become commonplace and distribution automation has thrived. MarkertsandMarkets, a research company, projects the global distribution automation market will grow from an estimated US$20.56 billion in 2025 to US$40.40 billion by 2030. They noted that the global distribution automation market is expanding because of the global shift toward grid modernization.
The Answers Are Out There
Looking a little deeper into AI-driven functionality as applied to distribution automation shows it has revolutionized the technology’s decision-making, adaptability, and data driven insights to name a few features. One of AI-driven distribution automation’s strong points is bigdata analysis and using it for forecasts and predictions. It has also improved its ability for breaching silo databases for information that hasn’t been available.
It can give today’s utility planning group the benefit of knowing weather patterns and being able to shift through historical data. The maintenance and operations can now be linked to information about how often a distribution circuit was being overloaded in real-time. In effect, AI-driven distribution automation systems can tap into various databases available that have been commonly utilized because it’s too complicated for manual data-mining, and that only touches the surface.
One last feature before moving on. Faults happen even to the best designed distribution circuits, but AI-driven distribution automation offers fast fault detection, identification, and rapid system restoration, which is very important for customers. These and other features have been developed to improve the power delivery system and we’ll explore them more later, but for now the topic being addressed is supply-demand support. That brings us back to the plethora of gigawatts BTM that can become AI-driven VPPs.
Flexibility is Needed
Aggregating BTM resources has been popular with third parties and utilities for many years, but this approach is somewhat different. AI-driven distribution automation working with AI-driven AMI, and AIdriven VPP technology, however, provides the power grid with a flexible power supply. It provides a quick response to fluctuations in the balancing of electricity’s supply and demand. That reduces the risk of outages and lessens voltage instability and provides better real-time control and monitoring, which lets the advance VPP utilize its DERs more effectively.
AI-driven distribution automation VPP platforms are a responsive techno -
CHARGING AHEAD
logical application that is flexible and adaptable to the fluctuations common with balancing the supply and demand of electricity. Being located on the distribution network puts them close to the load, which means they do not need transmission line additions, or much if any permitting or interconnection delays. Their configuration can be tailored to deliver the exact performance requirements based on the utility’s needs, priorities, and they’re really user-friendly.
At the beginning of the year, DOE (Department of Energy) updated their VPP applications study. It started off saying they are a critical solution to the challenges facing our power grid. It went on saying, “VPPs are cost-effective solutions for balancing the grid that can be deployed at scale within six months to maximize the use and value of existing infrastructure.” DOE felt that “most utilities can implement some form of VPPs today without any policy or regulatory changes. However, VPP deployment has been highest in areas where state regulators and policymakers have implemented VPP-supportive actions.”
An Evoloving Situation
VPPs are an effective method that’s changing the dynamic landscape of supply and demand, but as DOE indicates utilities and grid operators need support and encouragement. There were over 33 gigawatts of operation VPPs in the U.S. at the end of 2024, so the technology has been proven. Still more regulatory and policy support is needed. VPP technology is an off the shelf technology and it has been working on many power delivery systems.
These AI-driven distribution automation VPP platforms are a major shift from traditional energy systems and the energy landscape shows it. They’re cost-effective solutions that are becoming increasingly more sophisticated. VPPs are developing more autonomous features for their operation. These feature are needed for quickly equalizing the power system’s supply-demand issues. It’s getting progressively more difficult maintaining that critical balancing point in a modernizing grid. Watching this digital grid technology evolve is going to be exciting!
QUICK CLIPS
Deloitte Report: AI Data Center Power Demand to Surge 30x by 2035
A new Deloitte report projects that power demand from U.S. AI data centers could increase more than thirtyfold by 2035 — from 4 GW in 2024 to 123 GW — posing significant challenges for energy infrastructure.
The report, Can U.S. Infrastructure Keep Up With the U.S. Economy?, highlights concerns from both data center and power executives. About 72% of respondents cited grid capacity as a major hurdle to meeting future load growth. Additional concerns include supply chain disruptions, security risks, and mismatched construction timelines.
US power demand from Al data centers is expected to boom
AI’s rapid adoption is reshaping investment trends across sectors. In 2024, references to “data centers” in investor calls grew fivefold. Capital spending by U.S. utilities and hyperscalers is expected to surpass $1 trillion by 2032, and the tech sector plans another $1 trillion in AI-related manufacturing over the next four years.
Source: Deloitte analysis of data from DC Byte, Wood Mackenzie, S&P Global, Lawrence Berkeley National Laboratory, Center for Strategic and International Studies, and Wells Fargo.
deloitteinsights.com
Surveyed executives emphasized the need for innovation — both technical and regulatory — to close the gap between infrastructure and demand. Data center companies prioritized efficiency improvements, smarter infrastructure, and renewable integration, while power providers called for new funding models that avoid raising residential rates.
“There is an opportunity in infrastructure development to support the national strategic priorities of AI and energy dominance,” said Martin Stansbury, principal at Deloitte & Touche LLP. “Collaboration will be critical, as will an understanding of additive infrastructure that brings efficiency, capacity, and flexibility.”
The report is based on Deloitte’s 2025 AI Infrastructure Survey, which gathered insights from 60 data center and 60 power company executives.
Researchers Help Utilities Understand Power Outage Costs
Researchers at Lawrence Berkeley National Laboratory (Berkeley Lab) are partnering with electric utilities across the country to create more accurate cost estimates for both short- and longterm power outages, building tools to guide investments in grid reliability.
The highlights of the work include an update to Berkeley Lab’s Interruption Cost Estimate (ICE) Calculator, a public website allowing stakeholders to estimate the costs of localized, shorter duration (up to 24 hours) power interruptions, and a newly published study in the journal Nature Communications featuring the power interruptions.
Berkeley Lab researchers asked households and businesses across ComEd’s service area on their response to power outages affecting the entire county and lasting many days.
The researchers used the survey results to calibrate a regional economic model, called the Power Outage Economics Tool (POET), to estimate the economic impact of widespread, multiday outages across the entire region consisting of the counties surrounding the ComEd service territory in Illinois, Indiana, and Wisconsin. The estimates included direct impacts on customers without power and indirect impacts on those in the surrounding
Businesses Cancel $1.4 Billion in New Factories, Energy Projects in May
As the U.S. Senate prepares to vote on massive tax and spending bill that would increase taxes on clean energy factories and projects, businesses canceled another $1.4 billion in new factories and clean energy projects in May, according to E2’s latest monthly analysis of clean energy projects tracked by E2 and Clean Economy Tracker.
The latest cancellations — including battery, electric vehicle and solar panel factories in West Virginia, New York, Alabama, Arizona and Washington — mean $15.5 billion in new factories and electricity projects have been cancelled since January 1. The cancelled projects were expected to create nearly 12,000 new jobs.
Republican congressional districts are losing the most. More than $9 billion in investments and almost 10,000 jobs have been cancelled, delayed or closed in Republican districts so far in 2025.
The $1.4 billion in projects cancelled in May were expected to create at least 1,000 new jobs. Another 600 workers were laid off across five closures announced last month. May’s cancellations also include GM’s decision to cancel plans for an EV factory in Tonawanda plant in New York and instead shift its investments there to build 8-cylinder gas vehicles.
E2 Communications Director Michael Timberlake said, “The consequences of continued policy uncertainty and the expectation of higher taxes on clean energy businesses are becoming painfully clear. Businesses are reacting to the Senate’s proposal — like the House’s — that would
drastically scale back the very tax credits that had been driving an American energy and manufacturing boom.
“These cancellations are just the first shoe to drop. With renewable energy supplying more than 90 percent of new electricity in America last year, canceled projects will likely mean less available energy and higher electricity prices for consumers and business alike.”
Amid the cancellations, businesses in May also announced nearly $450 million in
Combined, the eight projects announced in May are expected to create at least 1,310 new permanent jobs if completed. Through May, 62 percent of all clean energy projects announced — along with 71 percent of all jobs and 82 percent of all investments — are in congressional districts represented by Republicans.
According to a separate report from the Clean Energy Buyers Association, average household utility bills would rise by more than $110 per year and businesses would see at least a 10 percent increase in energy costs if Congress goes forward with its plans to repeal clean energy tax credits.
May’s announcements bring the overall number of major clean energy projects tracked by E2 to 397 across 42 states and Puerto Rico. Companies have said they plan to invest nearly $132 billion in these projects and hire 123,000 permanent workers. (These figures reflect ongoing revisions and updates).
investments for new solar, EV and grid and transmission equipment factories across five states — including a $120 million investment by electric vehicle maker Rivian to build 1.2 million-square-foot supplier park in Illinois that is expected to create 100 new jobs. Separately, Prolec-GE Waukesh announced plans for a $140 million electricity transformer manufacturing facility in North Carolina expected to create 330 new jobs.
Since federal clean energy tax credits were passed by Congress in August 2022, a total of 53 announced projects have been cancelled, closed, or downsized. More than 21,000 jobs and $18.2 billion in investments were connected with the abandoned projects. Additionally, If the bill were to pass, it could immediately halt the following projects in Kansas:
• EDP Renewables’ Plum Nellie Wind Farm in Cloud County.
• Invenergy’s Pixley Solar Energy Center in Barber County.
• Sunflower’s Boothill Solar Project in Ford County.
For Ameren, composite poles offered the right balance of durability, worker safety and material properties.
By RILEY ADAMS, Ameren, and TED FOTOS, Creative Composites Group
Utilities have two priorities: keep the power on and stay on budget. But extreme storms regularly fight these priorities for Ameren Illinois and Ameren Missouri. These two Heartland utility companies under Ameren Corporation share a single “Ameren way” of design, construction and safety standards. They also share the same challenges: both states suffer the same extreme weather conditions and have responded to these challenging circumstances with a solution that would help keep the lights on for Ameren customers.
Careful consideration and testing led both Ameren companies to TridentStrong Fiber Reinforced Polymer (FRP) utility poles. By staggering these poles among their wooden sub-transmission line infrastructure, Ameren has significantly decreased cascading losses, resulting in more reliable service and more satisfied customers.
Weather Woes
The Midwest may be spared from most hurricanes and earthquakes, but high-speed straight-line winds and tornadoes are regular events. Hit by winds exceeding 100 miles per hour, heartland utilities can lose scores of wood poles in a bad storm. Poles tip over, or in high enough winds, simply snap, taking the power lines down with them. This creates dangerous conditions near downed poles and wires, and a downed pole can create a “cascading” outage, as lines and poles are pulled down by other downed poles.
Cascading outages cost everyone dearly. Customers may be without power for days as line crews work as fast as safely possible to replace downed infrastructure. And during active storm conditions, the cost to repair or replace poles and lines can double or triple. Ameren wanted a solution to this no-win situation.
Wood Alternatives
Both Ameren utilities considered multiple alternatives to solve their cascading wood problem. Wood poles with steel reinforcements were tried, but, in high winds, they broke below ground since they weren’t driven down to below the butt of the pole.
The utilities hardened the grid in high-wind zones up to 20 miles in length, trusting the composite poles to stay standing even if storms pull down the wood poles.
Photos courtesy of Ameren Corp.
Steel seemed promising but was ruled out. Ameren places a high priority on worker safety, and adding a highly conductive steel pole in the energized zone was a potential safety issue that other materials avoided entirely. And the significant weight of steel was a further blocker.
Ameren also considered larger-diameter wood poles. Higher ANSI Class poles would be more resilient, but the utility industry is competing with many others to obtain these large-diameter poles. They’re more scarce and pricier, and they also require a significantly larger footprint,
which is the amount of space needed to install the pole safely and effectively.
Composite poles by Trident Industries, a member of Creative Composites Group, emerged as the solution Ameren needed.
Proof is in the Pictures
Ameren first purchased TridentStrong poles in 2010. Chosen due to their favorable footprint and performance characteristics relative to their diameter and height, the FRP poles brought Ameren’s infrastructural resiliency. They bend just the right amount in high winds, absorbing
the impacts of the high winds and returning to their normal state without damage in most actual cases.
Ameren approached the composite integration practically: They spoke with their line crews and learned that a single crew can install four to five sub-transmission line poles during a storm in a working day. They also assessed historical outage data to identify the service locations most in danger of cascading and in need of grid hardening with composite poles.
With these benchmarks, Ameren began installing one FRP pole every fifth pole, with four wood poles in between, on sub-transmission lines in the areas most likely to suffer cascading outages. Ameren chose the single-layer FRP pole with a 14inch diameter for poles 60 to 70 feet and 15 inches for poles over 75 feet. Ameren also uses TridentStrong multi-layer poles at corners, dead-ends and other unguyed locations where needed. The utilities hardened the grid in high-wind zones up to 20 miles in length, trusting the composite poles to stay standing even if storms pull down the wood poles.
It Worked
Tested by many powerful storms, Ameren’s technique proved extremely effective. The composite poles stayed standing, bending as needed to remain upright, even if the intervening wood poles leaned or came down. Outages were reduced to a handful of poles, allowing Ameren to restore power to customers in a few hours.
As seen in the photos, winds strong enough to snap wood poles during a terrible March storm in Missouri didn’t affect the FRP poles. And an ice storm that hit Illinois in January merely tipped the wood poles between the TridentStrong poles, a scenario that would’ve resulted in a cascading outage with just wood poles in place. The only composite poles that have broken so far have been hit directly by a tornado, which also flattened steel poles. The resiliency of FRP poles installed in this configuration has allowed Ameren lines to withstand storm after storm, and the poles show no signs of deterioration even 10 years since installation. Their resiliency and long service life give composite poles an excellent total cost of ownership.
Photos taken after a storm that ripped through Wildwood, Missouri, with winds strong enough to snap wood poles.
A recent Life Cycle Cost Assessment shows that, although a single FRP pole has an initial cost three times greater than a single wood pole, there is no difference in total life cycle cost, due to FRP’s very long service life.
The TridentStrong pole design has made the installation and replacement process simpler for utilities. FRP has a high strength-to-weight ratio, and Tri dentStrong poles have a single profile from top to bottom, shipping in one piece. To aid line crews, CCG marks both the balance point and the ground line with removable tape, removing guesswork. TridentStrong poles have additional lay ers of simplicity and security: The poles come factory-predrilled, making them immediately ready for attachments like crossarms and transformers in the field. Ground wires are also factory-installed inside the pole, preventing possible cop per theft and saving line crews from the time and expertise spent on ground wire installation.
Ameren places additional value on the relationship with Creative Compos ites Group (CCG). Every pole has a serial number linked to a traceability report that is tied to the purchase order, all to ensure quality throughout the life cycle. Ameren staff have visited TridentStrong manufacturing sites multiple times to personally confirm CCG’s outstanding quality control finding the site impressive and the CCG staff to be true partners.
Working in Segments
Ameren Illinois and Ameren Missouri have chosen to play the long game — and they’re winning. Customers are happier, power stays on more consistently and projects remain on budget. FRP poles have proved time and again that the staggered installation method is well worth the cost to buy in.
RILEY ADAMS is senior manager – Electric Programs at Ameren Illinois. Ameren Illinois delivers energy to 1.2 million electric and more than 800,000 natural gas customers in Illinois. Its service territory covers more than 1,200 communities and 43,700 square miles.
TED FOTOS is TridentStrong president, Creative Composites Group. The Creative Composites Group supplies innovative Fiber Reinforced Polymer (FRP) composite products for major infrastructure markets.
The staggered installation method avoided a cascading outage.
ComEd demonstrates the vital role utilities play in Illinois’ equitable transition to electric vehicles.
By CRISTINA BOTERO and DENISE MUNOZ, Commonwealth Edison Co.
Electric vehicle adoption is accelerating across Illinois — fast. In the first quarter of 2025, new electric vehicle (EV) registrations in the state grew three to four times faster than in the U.S. as a whole, relative to the same period in 2024. One likely reason, the state’s largest utility, Commonwealth Edison Co. (ComEd), launched new EV programs as part of its first beneficial electrification plan.
Since their launch, these programs have incentivized over 5,500 new public and private EV charging ports (roughly one port energized every two hours over the last 17 months) and supported the purchase or lease of over 1400 new and preowned electric fleet vehicles to date.
Most notable is where the support is going: 78% of the rebate funds paid by ComEd have gone to low-income customers and those located in or primarily serving
low-income and equity-eligible communities. At the center of this unprecedented equitable transition is a deliberate, equity-focused strategy that prioritizes access, affordability and trust, along with close collaboration with a wide range of stakeholders including the state and multiple other partners in the private and public sector.
This transition is only at the beginning, as ComEd recently received approval to continue investing in customer EV programs through 2028.
The Illinois Transition Illinois has come a long way in the transition to EVs. According to the Illinois Office of the Secretary of State, The state
Newly delivered electric vans incentivized with ComEd’s rebates.
Photos courtesy of ComEd.
has over 142,000 full battery electric EVs registered today, a sharp increase from the barely two dozen EVs registered in 2010. The state has a goal of 1 million EVs by 2030, set by Gov. J.B. Pritzker in 2021.
Significant barriers exist for widespread and equitable adoption of EVs in Illinois and across the country. The three most often encountered are high upfront costs, limited access to charging infrastructure and limited education on EVs. Signed in September 2021, Illinois’ Climate and Equitable Jobs Act (CEJA) amended the Electric Vehicle Act (EVA) to include beneficial electrification provisions designed to remove barriers, tap into the state’s electric grid, and deliver greater climate and air quality benefits.
Beneficial electrification (BE) is the replacement of direct fossil fuel use (for example, gasoline, diesel, propane and heating oil) with electricity. By definition, BE must result in net quantifiable benefits to society through reduced emissions, cost savings and improved electric grid operations, as an example. BE includes transportation electrification measures — that is, transitioning from internal combustion engine vehicles to EVs. EVs rely on electricity rather than on gasoline or diesel fuel, which makes them a low- or zero-emissions transportation option that does not release pollutants such as carbon dioxide, sulfur dioxide, nitrogen oxides and particulate matter through a tailpipe at surface level.
First BE Plan
ComEd’s first BE plan (BE Plan 1) was approved by the Illinois Commerce Commission in 2023. It is an investment of up to US$231 million total between 2023-2025 in customer rebates, as well as education, awareness and pilot programs, to support the state’s EV adoption goals while delivering net benefits to all of ComEd’s 4 million customers.
ComEd’s BE Plan 1 has equity front and center, reserving more than half of its rebate funds for — and offering higher incentives to — low-income (LI) customers and those located in equity investment eligible communities (EIECs) throughout ComEd’s service territory. The utility’s plan focuses on incentives for electric fleet vehicles of all weight classes and on public and private
charging infrastructure, both of which are instrumental to delivering on the plan’s benefits and supporting Illinois’ EV goals.
Rebate Programs
ComEd’s BE Plan includes three new EV rebate programs to support the purchase and installation of residential EV charging, the purchase or leasing of electric
fast-charging (DCFC) EV charging infrastructure deployment. This make-ready program covers up to $8000 per L2 port and up to $1000 per kW of DCFC for public or private installations. Eligible costs include customer-incurred electrical costs, civil costs, contracting and permitting.
fleet vehicles and reduce the financial burden for nonresidential customers to make a site ready for EV charging. ComEd launched these new programs in February 2024, announcing Walker Miller Energy Services as its implementation partner and making nearly $200 million available across all three rebate programs between 2024 and 2025:
1. The first and largest of ComEd’s rebate programs offers rebates of up to $180,000 for the purchase or lease of new and preowned fleet EVs of all weight classes, including transit and school buses. Fleets as small as one vehicle are eligible for the program and both business and public sector customers can participate.
2. The second rebate program offers business and public sector customers rebates to make a site ready for level 2 (L2) or direct-current
3. ComEd’s third rebate program offers residential customers up to $3750 in rebates for the purchase and installation of smart L2 EV chargers at home. Participating customers also get to switch to a time-variant supply rate from ComEd or an alternative retail electric supplier, allowing them to save by charging their EVs during times when rates are the lowest, thereby increasing grid utilization.
Provider Networks
ComEd has cultivated two critical provider networks to streamline access to EVs and EV charging and boost participation. Both networks were launched in 2024:
1. A network of fleet EV dealers and manufacturers integrates ComEd’s rebates at the point of sale, slashing upfront costs for EIEC businesses and public entities. For example, a
ComEd CEO Gil Quinones presents the Village of Skokie with one of the first fleet EV rebate checks as part of its BE Plan 1, next to Gov. J.B. Pritzker.
small delivery company in Waukegan was able to switch to EVs without paying anything upfront because the dealer used a voucher to cover the cost.
2. A growing network of Illinois Commerce Commission-certified EV service providers (EVSPs) support the design and installation of EV charging infrastructure for residential and nonresidential customers, with many of the members offering instant rebates on behalf of their customers.
As of July 2025, over 170 participants were enrolled in ComEd’s dealer network, including dealers, auto groups and directsale original equipment manufacturers. ComEd’s EVSP network has also grown to over 120 members, of which more than 20% are diverse-business certified (for example, minority, women or veteran owned), a figure ComEd is actively increasing through targeted recruitment in EIEC regions. These stakeholder networks not only drive participation but also foster economic opportunity, as local contractors join the electrification workforce.
Resources and Partnerships
In addition to its new rebate programs and provider networks, ComEd also launched multiple customer EV resources in 2023 and 2024, including a fleet EV tool kit (adding to its existing residential EV tool kit), an interactive EV load capacity map and free fleet electrification assessments
Since their launch, these programs have incentivized nearly 5500 new public and private EV charging ports (roughly one port energized every two hours over the last 17 months).
(FEAs). These tools help business and public sector customers assess their fleet and charging infrastructure needs from a variety of angles, highlighting cost-saving options in transitioning to an EV, identifying prime locations with ample grid capacity for larger EV charging infrastructure and offering personalized, expert assessments from ComEd staff for customers interested in fleet electrification and charging infrastructure deployment.
The role of the state and the utility in the equitable transition to EVs has never been more central, and ComEd and the state of Illinois are demonstrating how to make this work and how to continue the momentum going forward.
ComEd has also partnered with the Metropolitan Mayors’ Caucus, a collaboration of mayors throughout Illinois, on its EV readiness program. The program equips municipal governments in the ComEd region to advance transportation electrification by facilitating investment in EV charging infrastructure, promoting beneficial electrification and expanding EV market opportunities.
The program uses an EV readiness checklist as the organizing framework for municipal resources, best practices and policy templates that support strategic actions for communities to gain “EV Ready Community” designation, such as zoning and planning, permitting, safety and community engagement. To date, the EV readiness program has designated 23 municipalities as EV Ready, with more receiving this designation in 2025. It has also become a model for the national Interstate Renewable Energy Council’s (IREC) charging smart program, focused on increasing EV adoption nationwide.
Equity-Eligible Communities
ComEd’s success in promoting transportation electrification among low-income and equity investment eligible communities is no accident. It is the result of a deliberate, equity-focused strategy that prioritizes access, affordability, and trust. From the outset, ComEd designed its BE programs with these customers in mind, reserving more than 50% of its customer rebate budget exclusively for LI and EIEC participants and offering them higher rebate amounts. This financial commitment has translated into tangible participation.
ComEd’s equity approach goes beyond higher rebates and reserved funds. Recognizing the unique barriers faced by these communities — such as limited access to information, upfront cost concerns and historical distrust of utility initiatives — ComEd has deployed a multipronged
strategy to ensure the benefits of electrification are not just accessible but embraced. This begins with a hyperlocal, multicultural outreach and engagement model tailored to the diverse fabric of northern Illinois.
ComEd has also been listening. By partnering with trusted communitybased organizations, local businesses and respected residents, the utility has built bridges into neighborhoods often overlooked by traditional EV adoption programs. ComEd outreach teams have collaborated with community-based organizations in Chicago’s South and West Sides — areas with high EIEC concentrations — to host workshops at community centers, churches, park districts and even a hair salon, ensuring the message of electrification resonates in familiar, comfortable spaces.
Targeted digital campaigns further amplify this effort, with paid social media ads on platforms like Instagram and Nextdoor, programmatic ads geotargeted to EIEC neighborhoods and personalized email blasts that speak directly to residents’ needs — like how an L2 charger can cut charging time compared to standard outlets.
Another initiative that will further boost participation is ComEd’s ambassador program. This program recruits local leaders from diverse organizations — selected for their geographic reach, familiarity with environmental justice or sustainability issues, and ability to connect with underserved populations — to champion electrification. In 2025, 15 team members from three organizations, representing communities from Rockford to the South Side of Chicago, were selected to train on EV benefits and ComEd’s offerings. Each sponsoring organization received a stipend to support their organization, incentivizing participation while empowering local voices. The goal is to have ambassadors directly facilitate rebate applications in their communities, with participants citing the personal connection as a key motivator.
This equitable and targeted engagement strategy is deeply intentional. It acknowledges the history of these communities, respecting past challenges like redlining or environmental neglect. Cultural sensitivity is a cornerstone of this program. To reach customers effectively, outreach team members speak Spanish and educational material is available in a variety of languages to reach the widespread population of the area. Events are also chosen to reflect the region’s diversity — from the high-profile Chicago Auto Show to grassroots gatherings like the Bud Billiken Parade, a historic celebration of African American culture in Chicago.
For business and public sector customers, barriers like high upfront costs and long project timelines are tackled head on with innovative program features. The make-ready reservation feature lets EIEC participants reserve funds for charging infrastructure projects that will complete within six months, providing certainty that dollars will be there when the work is done. Since its launch, over 70% of reservations have gone to EIEC businesses, including a community college in Chicago’s Englewood neighborhood planning a charging hub for its shuttle fleet.
Meanwhile, the EV fleet rebate program’s point of sale feature delivers instant rebates via vouchers — reducing a $50,000 EV purchase to $40,000 at signing, for example — making electrification feasible for cash-strapped public entities like rural fire districts and small logistics firms in Rockford.
The numbers speak for themselves. By blending financial incentives, authentic engagement and practical tools, ComEd has not only driven significant participation but also set a blueprint for equitable electrification others could follow.
Outlook
As ComEd marks the first anniversary of its new EV programs, it also celebrates approval from the Illinois Commerce Commission (ICC) to continue investing in beneficial electrification through 2028. The utility’s second BE plan is the result of close collaboration with multiple key stakeholders to ensure alignment of priorities. It is largely a continuation of the programs started in 2024, with some modifications for improvement.
The role of the state and the utility in the equitable transition to EVs has never been more central, and ComEd and the state of Illinois are demonstrating how to make this work and how to continue the momentum going forward.
Editor’s note: To learn more about ComEd’s efforts to support a clean energy future, visit www.ComEd.com/Clean.
CRISTINA BOTERO is the Senior Manager for the Beneficial Electrification (BE) team at ComEd. She serves as ComEd’s primary subject matter expert on Electric Vehicles (EV) and her team is in charge of shaping and evolving ComEd’s Beneficial Electrification plans, strategy, and offerings. She has been with ComEd for five years, and prior to joining ComEd held a variety of Engineering roles with BP, Tesla, Argonne National Lab, the Massachusetts Institute of Technology (MIT), and GE focusing on diverse energy technologies.
DENISE MUNOZ is the Director for Strategic Planning & Innovation and Clean Energy Program Implementation at ComEd. Her team designs and manages strategies across the full portfolio of ComEd’s Energy Efficiency and Beneficial Electrification Portfolio and Demand Side Management solutions for customers to support the overall ComEd Strategy, policy and regulatory commitments. Her team also has responsibility for the innovation and new products function ensuring the development of new products and services that directly support the achievement of portfolio targets as a result of the Climate and Equitable Jobs Act (CEJA). Since joining ComEd in 1992, Denise has held a variety of roles in Energy Efficiency, Distribution Operations, Project Management, Regulatory, and Marketing.
78% of the rebate funds paid by ComEd have gone to low-income customers and those located in or primarily serving low-income and equity-eligible communities.
Beyond the Right-of-Way
MidSouth Electric Cooperative invests in technology to minimize power disruptions.
By COMFORT MANYAME, EMPACT Engineering
About 10% of the service territory for Midsouth Electric Cooperative (MSEC) lies within the Sam Houston National Forest. This area is predominantly characterized by Loblolly and Shortleaf Pine trees, which can attain heights exceeding 100 ft. Consequently, these trees pose challenges in maintaining a clear right-of-way (ROW) of 10 ft on either side of the conductors and preventing vegetationrelated outages.
Over the years, vegetation has been the primary cause of outages at the cooperative with a service territory spanning 1600 square miles across six Texas counties. Of the vegetation-related outages, more than 95% are attributed to trees outside the ROW (Fig. 1). This observation aligns with the findings of research conducted in most utilities, which has consistently shown that trees growing within the ROW contribute a negligible percentage of vegetation outages compared to trees outside the ROW.
Determining the Effects of Weather Conditions
Over the last five years, most of MSEC’s vegetation outages were experienced during storms (Fig. 2). This is consistent with research that shows that more than 80% of power outages are due to severe weather. However, it appears even in “normal” weather conditions, trees outside the ROW still cause a significant number of outages. Research has also shown that not only dead trees, but live trees contribute significantly to power outages. Rainy and windy conditions have had an equal contribution to outages year-over-year on the MSEC system. Following a substantial rainfall, some saturated soils, especially sandy soils, lack the necessary stability to support tree roots, leading to their eventual collapse and hence more outages experienced in areas dominated by such soils.
A maintained distribution right-of-way. Photos by EMPACT.
Unkempt distribution right-of-way.
Performing a Geospatial Analysis
In response to the significant number of postdrought vegetation-related outages, a comprehensive geospatial analysis was performed using LiDAR data, MSEC outage data, environmental data and satellite imagery. This analysis was instrumental in developing an optimal vegetation management (VM) program to update the cooperative’s current plan. The project was carried out by EMPACT Engineering, a consulting firm specializing in engineering and technology, located near MSEC’s headquarters in Navasota, Texas.
EMPACT Vegetation Insights (EVI) delineated the sections of the MSEC distribution system that required immediate ROW clearance and areas that could withstand extended trim cycles. Additionally, the MSEC service territory was also characterized based on lightning strikes, vegetation cover type and soil types. These data inputs were used in modeling tree mortality and determining optimal trim cycle lengths.
Characterizing the MSEC Territory
The vegetation cover type data used in the analysis is a 398 class, 10-m spatial resolution dataset developed through a collaboration of the Texas Parks and Wildlife Department (TPWD) and other partners. The dataset was developed from National Agricultural Image Program (NAIP)
Figure 3. Vegetation cover types in MSEC’s service territory.
Source: Texas Parks and Wildlife Department Data.
aerial imagery and more than 14,000 ground data points. This data is used by a wide variety of partners in Texas for conservation planning and management.
A 150-ft buffer was established around MSEC conductors to form a “utility forest.” This forested area immediately surrounding MSEC primary conductors contains tall trees that could potentially cause an outage or damage utility infrastructure.
Based on the TPWD data, the top five vegetation cover types in MSEC utility forest are Post Oak Savanna (Savanna Grassland); Pineywoods (Upland Hardwood Forest); Pineywoods (Disturbance or Tame); Post Oak Savanna (Post Oak Motte); and Pineywoods (Pine Forest or Plantation). (Fig.3 and 4).
Conducting a Soil Survey
The team characterized MSEC territory’s soil using the Soil Survey Geographic Dataset (SSURGO). This digital soil survey, which is developed and distributed by the Natural Resources Conservation Service (NRSC), is currently the most detailed level of soil geographic data available. SSURGO provides information about soil characteristics, properties and suitability for various uses.
Because soil moisture is considered the single most important factor affecting plant growth, the analysis focused on the soil
Figure 2. MSEC Weather Effects on vegetation outages from 2019 to 2023.
Figure 1. MSEC vegetation outages from 2019 to 2023.
Graphics by EMPACT.
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available water capacity (SAWC) in the top 150 cm of the soil or the root zone. (Fig. 5).
SAWC is the amount of water that a soil can store and can be accessed by plants and is expressed as inches, volume fraction (inches of water per inch of soil), or as a percentage. SAWC
demonstrates the soil’s capacity to support plant growth between rainfall events and its ability to effectively buffer the root environment against periods of water scarcity. A higher SAWC is advantageous for tree survival during drought conditions.
Analyzing Rainfall
Like SSURGO, precipitation data for Texas was also obtained from the NRCS. This data was created from 1981 to 2010 rainfall averages.
MSEC territory receives 41 to 48 in. of rainfall on average. This is favorable for Loblolly and Shortleaf pines, which dominate parts of the MSEC territory in the Sam Houston National Forest. (Fig. 6).
The 7-in. rainfall gradient in MSEC territory from west to east influences vegetation growth rate. For instance, the Highway 6 Substation, located in the western region, receives 6 in. less rainfall compared to the southeastern substations such as Fish Creek and Woodhaven. Consequently, this affects the vegetation cover type as well as growth rates, which leads to a need to treat these substation areas differently when it comes to VM.
Planning Hazard Tree Control Using a Tree Mortality Model
As per ANSI 300 Part 7-2012, a hazard tree is a structurally unsound tree that poses a risk of injury to individuals or property damage if it fails. Hazard trees are a subset of danger trees, which encompass any trees that may encounter electrical supply lines.
Prolonged dry periods, as observed during the Texas droughts of 2010-2014 and 2021-2022, have resulted in an increase in tree mortality within the MSEC territory. This has subsequently led to a heightened number of hazard trees in the utility forest.
After registering record vegetation outage numbers
Figure 4. Vegetation cover type distribution in MSEC’s utility forest.
Figure 5. MSEC’s Soil Available Water Storage in the root zone (0-150cm).
Figure 6. Precipitation (30-year average) in the MSEC service territory.
immediately following the 2012 drought, MSEC responded by creating and employing a GIS-based Tree Mortality model. The model was developed in ArcGIS using SSURGO data, vegetation cover type, rainfall data and MSEC outage data as model input. The intersection of low SAWC, lower rainfall and forest vegetation cover (Pines and Oaks) automatically present a greater risk of hazard trees or dead trees. The resultant map (Fig. 7) is used to dispatch and direct crews to “hot spots” instead of driving the full span of the service territory scouting for dead trees. Timely removal of hazard trees using the model helped the co-op to reduce vegetation outages by 60%.
Performing LiDAR Vegetation Analysis
The team captured LiDAR data from early June to early July 2024 and analyzed for the whole MSEC service territory. Figure 8 is a screenshot of the current vegetation status around conductors on one of the feeders. The different colors represent distance of vegetation from the conductors based on MSEC ROW clearance practice. Red is 0-3 ft, yellow is 3-6 ft and green is 6-10 ft. MSEC maintains a 10 ft clearance between conductors and vegetation. Armed with this actionable information (which is available for the whole system), MSEC will dispatch crews to these exact locations where vegetation has been identified to be in violation of the ROW distance.
The Dobbin substation had the highest overall number of miles with vegetation within the 10 ft ROW. Furthermore, the
same substation also has the highest number of miles with vegetation within 3 ft of conductors (about five times the second highest). Ideally this would be the top priority for ROW work.
Calculating the Number of Trees in the ROW
At the substation level, the team broke the analysis down to the tree level to get an estimate of the number of trees involved in each encroachment violation. Knowing the tree count helps in estimating the effort and cost needed to clear the ROW.
They also looked at the vegetation location around feeders. ROW companies apply a double rate to clear vegetation on lines that have vegetation encroachment on both sides of the line. (Fig. 12) Armed with this information, MSEC now has a good idea of cost estimates before ROW crews bid for the following year’s clearance work.
As far as trim cycle recommendations, MSEC maintains a 10 ft ROW around their distribution lines by trimming any encroaching branches and foliage. The co-op operates on a five-year trim cycle for most of its service territory.
After their analysis, EMPACT Engineering recommended MSEC to maintain the current trim cycle but also to pay close attention to sections with fast-growing vegetation. (Figures 13-15). The “Short” group represents areas where environmental factors promote rapid regrowth after trimming which necessities more frequent visits. The “Normal”
Figure 7. Tree mortality risk model/map for MSEC territory.
group represents MSEC’s five-year cycle; and the “Long” group represents areas where there is mostly grassland, pastures/fields or areas with no significant tree growth. This latter group can do with even less, or in some cases, no visits at all.
(Fig. 14). The Sandy and Dobbin substations each have at least 50 miles of line in the short cycle length category, which necessitates more frequent visits than the rest. Roans Prairie, Bishop
and Bedias closely follow with at least 35 miles each exposed to potential rapid vegetation re-growth.
Recommending a Feeder Trim Cycle Length
(Fig. 15). When looking at the MSEC system exposure to fast regrowth at the feeder level, Feeders 182414, 032413 and 182413 have the greatest exposure (>20 miles of line exposed) and hence require the most attention. The top three feeders are closely followed by 142403, 072401, 142402, 012404, 032414 and 122414 all with at least 15 miles of line exposed to fast re-growth.
A shorter than “normal” cycle length, preferably every two to three years is recommended for the top nine feeders and mandatory mid-cycle reviews for the rest of the feeders. Another way to look at these results is that there are cost savings wherever the feeder does have areas that do not require frequent revisits.
Looking Forward
More than 95% of MSEC vegetation-related outages are attributed to trees outside the ROW. This highlights the cooperative’s vulnerability to hazardous trees, while simultaneously demonstrating the effectiveness of its ongoing and consistent VM program. Notably, only a small percentage of vegetation outages are linked to trees growing within the ROW.
An effective VM plan must incorporate grid performance data, environmental data, vegetation data, institutional (tribal) knowledge and innovative approaches such as remote sensing (LiDAR, satellite imagery, etc.) and geospatial analytics. EVI is founded upon these fundamental methods, data and a robust collaboration with the utility. Using the EVI report, MSEC can now do the following:
• Informed Bidding Process. EVI has provided MSEC with data and information that they will share with their ROW contractors during the bidding process. They can influence the process in two ways. First of all, they will have a comprehensive understanding of the vegetation intensity of their utility forest. This enables them to negotiate a more favorable price for sections of the system where there is minimal or no vegetation. Secondly, the cooperative recently discovered that ROW contractors charge double the price for sections where vegetation clearance is required
Figure 8. This close-up of a LiDAR point cloud shows vegetation encroachment, June 2024.
Figure 9. Vegetation encroachment in the MSEC right-of-way.
on both sides of the conductors. EVI provided the cooperative with this information for every section of line where there was encroachment into the ROW.
• Cycle Optimization. Knowing the characteristic of the utility forest has helped MSEC to have a good idea of regrowth rates based on the microenvironment. Rainfall gradient of 7 in. from the west to the east of the territory and different soil types with different water holding capacities influence how fast vegetation will grow. Also, the different vegetation types influence the type of growth expected.
The second way this has optimized their cycle is by moving forward feeders that need attention earlier into the cycle and vice versa. This ensures that money is spent where it needs to be spent, and attention can be given to feeders that require urgent attention and saved on feeders that do not require any immediate work.
Validation of Coop’s Current Plan
Several years ago, MSEC developed a VM plan using GIS modeling and predominantly freely available data. This plan remained in use until EMPACT Engineering conducted an update using LiDAR and more recent datasets. This update proved beneficial for the cooperative, as it revealed that the circuits identified by EVI as those requiring the most attention were the same circuits scheduled for trimming by the cooperative this year and the following year.
This discovery validated the cooperative’s plan based on current data and analytics modeling. EVI enhanced the value proposition and optimized the cooperative’s plan by adopting a more quantitative approach. Instead of merely identifying circuits that required clearing, they now have a comprehensive
understanding of the extent of clearing required, encompassing the length of the line and the number of trees in the ROW.
LiDAR vs Satellite Imagery
The question of whether LiDAR or satellite imagery is superior for UVM has been posed repeatedly. Each technology offers unique advantages. LiDAR provides survey-grade location accuracy and 3D modeling of the terrain and vegetation, while satellite imagery, particularly multispectral imagery, enables more detailed vegetation analytics, such as assessing vegetation health and identifying species. A combination of these technologies provides a comprehensive understanding of the vegetation and effectively conveys its characteristics.
As LiDAR technology becomes more affordable and efficient, it presents a favorable opportunity for utilities. LiDAR offers multiple applications, contributing to cost reductions and significantly
Figure 13. Trim Cycle Length recommendations.
Figure 10. Miles of line encroach into the right-of-way by a substation.
Figure 11. Trees involved in a right-of-way encroachment by a substation.
Figure 12. Encroaching vegetation location.
enhancing its value proposition. In the case of MSEC, LiDAR is used not only for vegetation analytics but also for correcting their GIS with precise location data, conducting joint use audits and managing pole loading. This multifaceted application of LiDAR has made it highly valuable. EMPACT Engineering has assisted MSEC in analyzing vast point cloud data to derive actionable information, demonstrating the potential of LiDAR in this domain. If a utility lacks access to LiDAR data or does not have capacity or capability to analyze such data, they can still freely use available datasets such as SSURGO, Precipitation and Vegetation Cover type as a foundation. MSEC serves as a notable example of this approach. They developed their initial vegetation management plan, which has demonstrated significant effectiveness, employing GIS and free data.
Smart Automation Starts with Phase Identification
Their recent collaboration with EMPACT Engineering and integration of LiDAR technology into their operational processes has significantly enhanced the efficacy of their vegetation management planning. This advancement has eliminated a substantial amount of uncertainty from their entire workflow, encompassing budgeting, bidding and execution in the field.
DR. COMFORT MANYAME, GISP, is the director for geospatial R&D at EMPACT Engineering. Prior to this role, he served as the technology and research strategy lead for MidSouth Electric Cooperative in Texas for more than a decade. He leads EMPACT Engineering’s vegetation management research, using high-resolution LiDAR and remote sensing imagery. His work has been widely published, including in Esri’s “GIS Best Practices for Municipalities, Cooperatives, & Rural Electric Utilities” and RE Magazine. He holds a Ph.D. from Texas A&M University in College Station, Texas.
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Figure 15. Feeder trim cycle length recommendations.
Figure 14. Substation trim cycle length recommendations.
Reducing Wildfire Risk with IVM
With fire incidents on the rise, vegetation managers in fire-prone regions should look to IVM techniques as a component of risk mitigation.
The increasing number, severity, and duration of wildfires in recent years has revealed a fundamental truth: there are no quick solutions to the problem. There are effective ways to reduce the risk of fire, and once implemented they can start to work relatively quickly, but mitigating the risk of fire is a long-term commitment, often requiring a fundamental shift in thinking among utility vegetation managers (UVMs) and the utilities and citizens they serve. Part of that shift may involve adopting integrated vegetation management (IVM), or IVM, techniques.
IVM: Not Just Herbicides
It’s critical to understand that IVM doesn’t just mean replacing mowing with herbicide applications. It simply means that in practice, any and every available method of vegetation control is on the table – hand cutting, mowing, and herbicide use, along with the biological control achieved when low-growing native forbs and grasses effectively “crowd out” undesirable brush and other vegetation.
Most often, we see IVM promoted as a means to economic, environmental, and operational stewardship, and for good reasons. The average peracre cost to apply herbicides is significantly lower than the cost to mow that same acre. In addition, herbicide applications emit far less greenhouse gas than mowing, and require fewer crew members and fewer hours. But for utility vegetation managers (UVMs) in fire-prone areas…which is rapidly expanding to include parts of the Eastern and much of the Central and Western United States1…IVM offers real advantages in fire risk mitigation.
IVM and Fire Risk Mitigation: How It Works
A mowing-only program can actually contribute to fire risk, or to an increase the severity, duration and spread of a fire once it’s started.
How? First, mowers can spread the seeds of undesirable brush species, resulting in higher stem counts across a wider area. Second, mowing leaves brush and plant debris behind to dry out – and become the perfect ladder fuel. Finally, mowing increases the chances of ignition due to sparks or contact with hot equipment.
But IVM program incorporating selective herbicides and selective application methods can not only return the environmental, budgetary and operational benefits we hear so much about. It can help reduce the risk of fire, and help limit the spread of fires that do start. Here’s how:
A well-executed IVM strategy allows native grasses and forbs to flourish. This not only helps prevent the growth of undesirable vegetation, it allows UVMs to establish fuel breaks throughout rights of way. In turn, these fuel breaks provide landscapes from which firefighters can more effectively work to prevent the spread of fires.
1. An IVM program can reduce the amount of mowing required. Less mowing means fewer undesirable seeds are spread, a fewer chances for ignition due to sparks from mechanical equipment.
2. An IVM program helps reduce the amount of available fuel. As undesirable vegetation dries, it becomes more vulnerable to spark or flame. An IVM strategy helps prevent the growth of trees and brush, reducing the amount of fuel available and reducing the chances of interaction between lines and vegetation.
As the threat of wildfire expands to include areas once considered lower-risk, and as the severity of wildfires continues to increase, a solid IVM program can serve as a foundational component of a fire risk mitigation program, and can provide a variety of additional environmental and economic benefits.
If you’d like to learn more about the benefits of IVM and selective herbicide use, visit Corteva. us/TDW, or reach out your Corteva vegetation management specialist.
1Increasing Large Wildfire in the Eastern United States: Donovan, Crandall, Fill, Wonkka, Geophysical Research Letters, 18 December 2023
Serving on the Front Lines of Storm Response
In the electric utility industry, it’s not when a storm will hit, but when line crews need to respond.
By JOEL MULLINAX
, TRC Companies
In the electric utility industry, those who participate in storm response have a special bond. You can feel it in the planning sessions that start long before storm season begins. You can sense it at the learning forums where storm response professionals come together to share best practices. And it is palpable in the staging areas where crews from utilities and support organizations assemble and prepare to drive toward the storm — while everyone else is evacuating in the opposite direction.
Many of the best memories I’ve made and closest friendships I have in the industry have been a result of storm response duties, which have been an important
part of my work throughout my career. My last storm response deployment was in 2017, where I supported Duke Energy in Florida for 23 days after a major hurricane. And that work continues today with my position overseeing teams that serve as an extension of utilities across the Southeast.
No matter the location or circumstance, every storm response staging area feels familiar to me. The temperature of the sandwiches and quality of the coffee may vary, but one thing stays constant — there’s always a calm confidence that comes from a group of people who are ready to do something important and are fully prepared for the challenges ahead.
That consistency is one of the things that makes me deeply proud to be part of the community of people who work together on storm response.
Responding to Natural Disasters
While some things will never change about storm response operations, one thing that is evolving is the year-round unpredictability of natural disasters. Not only are the severity and frequency of major storms increasing, but the geographic impact of these storms has widened and become harder to predict.
For example, areas that have historically been at lower risk for significant hurricane damage have been hit hard in recent years. Last year’s hurricane damage in western North Carolina is a powerful example of that. But it’s not just
This work is dangerous, the deployments are often long and the accommodations are never glamourous, but every year selfless people in our industry rush to volunteer for these roles despite the risks.
hurricanes. Areas where tornadoes have not been prevalent have faced major damage in recent years. Ice storms have hit regions that typically don’t face outages from ice buildup on grid infrastructure. And wildfires, which are so often sparked by lightning from thunderstorms, are regularly posing major risks to utility infrastructure across the entire nation rather than just in Western states.
All these factors make storm preparedness even more critical, and it is inspiring to see how organizations across the utility industry collaborate to achieve the planning, adaptability and cooperation needed to meet these challenges. For my team, preparation for storm season has been underway for several months and includes extensive planning with the utilities we serve. We work as an extension of utilities’ own crews and contractors, allowing utilities to quickly expand the number of
A community’s power was out due to a completely broken pole, creating unsafe conditions. This required multiple crews working tirelessly to get power safely and quickly restored. Photos courtesy of TRC.
experienced transmission and distribution (T&D) technicians, designers and engineers who can be deployed for damage assessment and recovery planning.
Volunteering for Storm Response
Our storm response teams are comprised of volunteers, and we work on a mutual aid model that mirrors the collaboration so many utilities use in response to major events. For storm response deployments last year, we drew in TRC employees from across the country to work on incidents in the Southeast. They came from as far as Texas, Virginia, Ohio and a long list of other locations to join local resources, allowing us to deploy 200 teams to emergency areas.
We always work in two-person teams to ensure safety. The senior team member conducts damage assessment and maps the required design and engineering work. These are highly experienced utility professionals who are often former line personnel with decades of experience in T&D and in emergency response. The
assessor is paired with a more junior utility professional, providing an intensive apprenticeship in one of the most important roles of his or her career. I am incredibly impressed by the abilities of the next generation of professionals who adept at using digital technologies for the design work that is central to storm response. This bodes well for the future of our industry as storm response becomes even
more critical.
Soon after a major storm rolled through, trees, poles and lines alike are found scattered around communities with almost no communication, making coordination and mobilization a challenge.
We work closely with utilities to deploy these teams exactly where and when they are most needed. We can then re-deploy them to support other utilities that have infrastructure impacted by the same emergency or utilities that are facing damage from a different emergency. We have a war room to orchestrate the cross-organization communications and
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When communities experience devastation at scale, TRC’s teams come from all over the country to help them recover and get the lights back on.
logistics for all of this, which is expertly managed by Chris Duncan, TRC’s storm director.
Assessing the Damage
Everyone who serves in a storm response role knows how often damage assessment
ASPEN
teams also act as first responders. And the stories of crews’ bravery, selflessness and public service are an enormous testament to our industry. So often, damage assessment teams are the first to arrive in an impacted neighborhood, often finding people in dire circumstances. The crews
give out water, food and blankets to people who have lost everything. Crews often save people from drowning, rescue trapped victims, perform CPR and provide lifesaving first aid until EMTs can arrive on scene. Being first on scene also means storm response crews are among the first to
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be able to provide emotional support to storm survivors. That makes empathy and selflessness important qualities for people on storm response assignments. They are helping people who are often in shock, who have had their lives impacted in a traumatic way and need far more than just power or food. Again, and again our crew members rise to the occasion. They quickly become part of the community, too, given that the T&D rebuilding process can often take weeks after a major storm.
Honoring the Storm Responders
With qualities like bravery, selflessness, empathy and calmness under pressure, it is no surprise that many of the best storm responders in our industry are military veterans. After careers in the military, they became line and/or design personnel to apply their skills building and managing mission critical infrastructure, and their military experience becomes an enormous asset during storm response missions.
This work is dangerous, the deployments are often long and the accommodations are never glamourous (especially when you sleep in your truck), but every year selfless people in our industry rush to volunteer for these roles despite the risks. With storm season rapidly approaching, it is important to recognize how much work has gone into preparing for the emergencies that will occur in the coming months. There are a lot of jobs where it is hard to feel like you are truly making a difference in the world. This isn’t one of them. In advance of what will likely be a very busy storm season, it is an honor to be serving in a role that supports communities facing
Utilities band together to help get the lights back on so communities can get back on their feet.
Photo courtesy of TRC.
Liberty Utilities is leveraging the power of artificial intelligence and large language models to increase efficiency in its vegetation management program.
By PHIL SWART, Contributing Writer, JASON GROSSMAN, Liberty Utilities
Utility vegetation management (UVM) has evolved significantly over the past several decades.
Today, foresters and vegetation managers are spending more time behind a screen than under the canopy. From writing work plans and responding to regulators, to preparing stakeholder communication and compiling contractor audits, the work has become increasingly administrative. And while technology often promises to help, it can just as easily complicate.
That’s where large language models (LLMs) come in. These tools aren’t here to replace the need for field work or entirely remove administrative tasks; they’re here to make the office work more manageable. LLMs are helping UVM professionals draft documents, summarize
reports, improve internal communication and reduce time spent on repetitive writing tasks. This article will explore where they fit into daily operations, how they’re already being used by UVM professionals and how you can get started.
Cutting Through the AI Buzz
Artificial intelligence (AI) has become the banner under which seemingly every new tool is marketed across every industry. From health care to finance to vegetation management (VM), “AI-powered” solutions are everywhere. The result? A mix of hype, confusion and skepticism.
UVM is just as susceptible to this AIinfusion, and this overuse of the term has led many professionals to tune out. Large language models offer something different. These tools are designed to work with
words, not just data points or maps. They help with the tasks that occupy much of a UVM manager’s time: administrative office work.
Unlike much of the AI noise, LLMs have immediate, practical applications. They don’t require custom integrations or enterprise-wide rollouts. They are accessible in a browser and ready to support the real work happening in UVM offices today. Best of all: they are free to try and use on a limited basis.
Many professionals are already familiar with tools like OpenAI’s ChatGPT or Microsoft’s Copilot but have yet to apply them in a work environment. This is where a significant opportunity lies. By using familiar platforms with industry-specific prompts and materials, UVM teams can begin discovering new efficiencies without
additional investment or IT department overhauls. With responsible experimentation and thoughtful application, these tools can become another tool in your UVM toolbox.
What Are Large Language Models?
Large language models are a form of AI trained to understand and generate human language. They excel at reading text, summarizing content, drafting documents and answering questions based on the information you give them.
To put it in context: Apple’s Siri is an example of AI because Siri understands spoken language and answers basic questions. Netflix recommendations are powered by machine learning (ML) to personalize your recommendations by predicting
your preferences based upon behavior and viewing history. Face ID technology uses deep learning to analyze and recognize your face, regardless of whether you grow a beard, wear glasses or otherwise change your image. Generative AI goes a step further and creates new content, like digital artwork or music. Large language models like ChatGPT and Microsoft Copilot are part of this last group, and they focus specifically on working with language.
The advantage of LLMs is their flexibility. They work directly in a web browser, respond to natural language input and require no special software to get started.
Most LLMs operate as general-purpose tools, but their strength in UVM comes from specificity. The more you tailor your prompts and inputs — using real-world documents, reports and terminology — the more relevant and valuable the output becomes. For example, asking a model to rewrite a public notification letter with safety-focused language and a fifth grade reading level can yield a community-ready draft in seconds.
Moreover, LLMs are becoming increasingly multimodal, meaning they are beginning to interpret not just text but other data formats such as charts, photos and PDFs. While this is still emerging, the future includes models that can crossreference multiple data types in a single session, allowing for deeper insight into
UVM reports, visual inspections and asset management records.
A Real-World Example: Liberty Utilities
Jason Grossman, manager of vegetation management at Liberty Utilities in Missouri, has been experimenting with LLMs for over the past few years. His approach is focused, results-driven and directly tied to the work his team does every day.
Here’s how his team is using LLMs:
• Summarizing Incident Reports: Grossman inputs vegetation-related incident reports into an LLM and receives a concise summary with recurring patterns and suggested preventive actions.
• Turning Regulations into Microlearning: Long, complex utility documents are summarized into bullet points or turned into simple internal training pieces that are easier for staff to absorb.
• Drafting and Reviewing RFPs: From scopes of work to evaluation criteria, he uses LLMs to draft and refine documents that would otherwise take hours.
• Supporting Public Communication: Stakeholder letters, social media posts and public education content all start with an
Jason Grossman, manager of vegetation management at Liberty Utilities in Missouri, has been experimenting with LLMs for over the past few years.
Photo by Liberty Utilities.
Aerial shot of an articulated boom lift positioned for tree trimming. ID 378085096 © SensejG | Dreamstime.com
REAL TOOLS, REAL TIME SAVE
Here are some real-world examples of how AI and LLM are helping Liberty Utilities to save time and increase efficiency in UVM.
• Invoice Automation: One prompt shaved off 126+ hours a year — just by cleaning up contractor billing formats.
• Business Cases: Build three-year ROI comparisons for internal vs. contract tree crews in minutes.
• Scope Creation: Scopes for herbicide, bare ground and TGR work can be done with 90% less effort.
• Training: Create and deploy crew quizzes and onboarding modules in a week.
• Leadership Reports: Prepare execready summaries from raw field data — before coffee’s done brewing.
Next, here are some battle-tested prompts to try:
• Provide a statistical analysis to see if the TGR-treated trees show a reduced average regrowth estimate and provide three charts that provide evidence to support the data conclusions as well as a written document in the format of a scientific paper.
• Review this safety incident and provide five follow up questions comments or concerns.
• Write a five-question quiz for contract utility foresters on herbicide safety practices based on the attached presentation.
• Create a professional and detailed Request for Proposal (RFP) for vegetation chemical control services to be used by a utility company. The RFP should include the following components: “I need a detailed business case for transitioning utility tree crews from contract to internal employees using a hybrid model. The case should focus on financial, operational and strategic benefits, with a subtle yet persuasive approach to encourage leadership buy-in. The writing style should be professional, analytical and structured for executive decision-making.”
• Turn these rough notes into a polished summary of the meeting. Keep the key message but make it clear,
professional and provide supporting evidence for the ideas and thoughts expressed.
• Here are my notes: “Write a SMART goal for employees to use ChatGPT to optimize and streamline their daily operations, increase efficiency and automate tasks. At the end of the year, I want them to enter a prompt that summarizes their usage and topics as well as an estimated time savings.”
• Write the prompt for them so that it is consistent across the board: “I want to get better at writing effective prompts for ChatGPT so I can receive more accurate, useful and creative responses. Please coach me on how to write better prompts. Start by explaining the core elements of a well-crafted prompt, then give me examples of weak vs. strong prompts. Finally, guide me through practicing with a few examples and provide feedback on how to refine them.”
Finally, here are some things to keep in mind when you first start out.
• Why It Works: This isn’t a shiny new tool collecting dust. It’s already in use by field leaders and program managers across utilities enhancing how teams train, report, write and analyze. And once someone on your team starts using it, others follow.
• A Quick Word on Privacy: Treat it like a consultant, not a filing cabinet. Don’t use personal or sensitive data. Use general or hypothetical scenarios to model workflows or build drafts. Stay smart, stay compliant. It’s a productivity partner, not your document vault.
• Early Mover Advantage: Those adopting AI now are already seeing faster audits, better QA workflows and fewer hours lost in Word docs. Those who wait? They’ll be benchmarking you later.
• Need a Win for This Week: Next time you’re stuck staring at a blank screen, open any LLM and treat it like a brainstorming partner. You’ll be surprised how quickly it gets you unstuck.
—Jason Grossman,
Liberty Utilities
LLM-generated draft that his team tailors before publishing.
• Data Analysis: Grossman uses LLMs to analyze historical regrowth data following tree growth regulator applications, helping him evaluate treatment success over time. This allows him to make data-informed decisions about future use and advocate for broader integration of TGRs within his IVM program.
Each of these use cases began with curiosity and a willingness to test. His team documents the prompts they use, evaluates the results and refines their process over time. This allows them to create internal templates that others on the team can reuse, thereby making LLMs more efficient with each project. Their approach demonstrates that adoption doesn’t need to be formal or complicated. A practical, trial-based mindset can lead to measurable gains in quality and turnaround time.
Common LLMs in Use Today
Before diving into hands-on applications, it’s helpful to know which tools are leading the way. Several LLMs are readily available for use in UVM-related workflows, each offering unique strengths.
• ChatGPT (OpenAI): Perhaps the most widely recognized, ChatGPT is available through a browser-based interface and offers a conversational approach to language tasks. It’s capable of drafting content, answering questions and summarizing documents. Paid versions include access to advanced models and features such as custom instructions and memory.
• Copilot (Microsoft): Integrated into Microsoft 365 applications like Word and Excel, Copilot brings LLM functionality directly into familiar office tools. It’s especially useful for teams already using Microsoft
systems and can support task-specific writing, formula generation and report drafting within your existing workflow.
• Claude (Anthropic): Claude is known for its helpful tone and strong performance in long-document summarization. It’s designed to be more cautious in its output, which some users prefer for sensitive or regulatory language.
• Notebook LM (Google): Designed specifically for knowledge management, Notebook LM allows users to upload internal documents and ask questions based only on that library. It’s a good choice for organizations building searchable archives of institutional knowledge.
• Gemini (Google): A flexible, Google-connected model with strong search and reference
Leaders in microgrids have something in common
abilities. Gemini is good at pulling in external context and responding in a straightforward tone.
• DeepSeek (DeepSeek AI): An emerging LLM with strong multilingual capabilities and fast performance. However, it is owned by a Chinese company, and some utilities may choose to restrict its use due to data security and jurisdictional concerns.
Regardless of the platform you choose, it is essential to follow best practices around data privacy. Under no circumstances should sensitive, proprietary or customer-specific information be shared with a public LLM. Treat each interaction as if it were a public conversation and always review and edit content before sharing it externally.
Five Ways You Can Start Using LLMs
You don’t need to overhaul your systems or change your workflows to try an LLM. These tools are available via web browser
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and can support you in a few common UVM tasks:
• Draft Homeowner Notices: Input a few details, and the LLM will draft professional, respectful notices that can be reviewed and mailed out.
• Summarize Regulatory Documents: Turn long reports into key bullet points or even first-draft SOPs.
• Build Templates: Create consistent audit forms, QA checklists or weekly summary reports.
• Capture Field Insights: Convert notes or debriefs into training documents or job briefings.
• Educate the Public: Generate plain-language content explaining pruning practices, herbicide use or storm preparation measures.
Each of these use cases can be expanded as your team gains confidence. A single success often opens the door to more creative applications, such as onboarding support, annual report writing or grant proposal development. In many cases, teams find that LLMs are most helpful not in
generating perfect results, but in giving them a strong first draft to improve upon. Time savings is a major benefit, but so is consistency. Once you’ve created a prompt and reviewed the output, the same task can be repeated month after month with minimal edits. This makes LLMs especially useful for recurring reports, social media updates and seasonal communications.
Bridging the Gap Between Office and Field
Clear communication is the backbone of a successful vegetation programs. From utility staff and supervisors to foremen and field crews, miscommunication can lead to delays, safety issues or unnecessary conflict.
LLMs can help. By converting technical language into field-ready instructions or customizing summaries for different roles, they ensure that everyone is working from the same page. For example, a vegetation manager’s notes can become:
• A concise job brief for the general foreman.
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• A one-pager for the crew.
• A summary for the contractor’s admin staff.
Grossman has used LLMs in this exact way to improve clarity while reducing the need for follow-up calls or last-minute corrections.
This is about much more than saving time; it’s about improving alignment across the entire UVM program. When everyone from planners, tree crews, herbicide crews and utility staff are working with the same information, formatted in a way that speaks to their role, the result is better coordination and fewer errors. And when unexpected changes arise — as they often do in field work — the ability to quickly update and redistribute clear, revised instructions becomes even more valuable. This alone is a prime reason to try LLMs.
UVM work involves unique constraints: terrain, weather, local policy and landowner expectations all shape what can be done. LLMs can’t replace judgment, but they can help document and share that judgment more effectively.
Preserving Institutional Knowledge
Much of what makes a vegetation program run smoothly is stored in people’s heads. As senior staff retire or change roles, there’s a risk that institutional knowledge disappears with them.
LLMs can help turn informal knowledge into reusable resources. By inputting field notes, audio transcripts or rough bullet points, you can generate formal documentation like safety briefings, onboarding materials or process guides.
Notebook LM is one tool designed for this kind of task. Unlike general LLMs, it only uses the material you upload. That makes it ideal for creating a secure, internal reference library based entirely on your own documentation.
Think of this not just as backup but as a foundation for training and continuous improvement. A structured knowledge library ensures that lessons learned on one circuit, in one season, or with one contractor don’t get lost. Instead, they become part of your team’s long-term memory, accessible and easy to update.
And when paired with prompt-based workflows, the benefit multiplies. You can ask the model specific questions such as, “What did we do differently on the Fairfield substation after the 2022 storm season?” and receive a clear, concise response drawn directly from your archived documents.
Running a Pilot: Start Small, Learn Fast
If you’re curious about LLMs, the best way to begin is by trying one. Choose a task that’s repetitive but important, like drafting customer notices or summarizing outage logs. Assign a team member to test the tool, review the results and share what they learn.
Create a shared folder for successful prompts so your team can build on each other’s experience. You’ll quickly identify where LLMs help and where human input is still essential.
One common concern is accuracy. LLMs should never be used to make safety decisions or replace subject matter expertise. Instead, treat them as a digital assistant that’s fast, adaptable and capable of helping with language-based tasks. The most effective pilots often begin
with non-public-facing content such as internal training materials, policy drafts or QA checklists.
Be intentional about feedback. Keep track of what works and what doesn’t. Over time, you’ll develop a list of best practices that reflect your unique workflows, tone and communication style. That internal playbook will become a valuable asset.
Where This is Headed
While today’s LLMs operate mostly as stand-alone tools, future versions will likely be integrated with GIS, inspection software and contractor management systems. This could allow LLMs to generate reports based on real-time data, assist in multilingual communication or even flag high-risk areas by referencing historical patterns.
Utilities that begin experimenting now will be better prepared for these advancements. Developing comfort and fluency with LLMs today makes it easier to evaluate and adopt more advanced integrations later.
The convergence of LLMs with other AI tools — such as image recognition, LiDAR and drone inspection software — could lead to systems capable of producing comprehensive vegetation risk reports with minimal manual intervention. Even before those systems arrive, LLMs can assist in synthesizing outputs from existing platforms, offering narrative summaries and recommendations alongside maps and tables.
It’s not hard to imagine a future where LLMs are embedded directly into vegetation dashboards, helping managers interpret contractor progress, identify missed work and draft weekly updates — all from the same interface.
Writing Better Prompts for Better Results
Getting the most out of an LLM requires one key skill: asking better questions. A well-crafted prompt leads to a better, more useful response.
Instead of saying, “Write a letter,” say, “Write a letter to homeowners letting them know that [insert contractor name] will be pruning trees in two weeks as part of our regular safety maintenance. Emphasize professionalism and safety. Include [insert
utility] contact information.”
Specify your audience, your tone and your goal. Save prompts that work well so others on your team can use them too. You’ll soon have a small internal playbook for everything from stakeholder notices to QA summaries.
Prompt crafting is not about using perfect language. It’s about being specific, thoughtful and willing to revise. Don’t be afraid to ask for rewording, alternative formats or summaries with varying levels of detail. LLMs are tools, and they perform best when guided by someone who knows the context.
As your team gets better at working with prompts, you’ll begin to see patterns — certain wording works well, certain structures yield better outputs. Treat this knowledge as a living resource, one that can be shared and improved upon over time.
Supporting the People Who Keep the Lights On
UVM is a people-first profession. It’s about safety, reliability and community. It’s also about making complex decisions, often with limited time and resources. Large language models offer a way to support our UVM teams doing this work not by replacing them, but by giving them tools to work more efficiently.
Whether you’re a program manager, forester or general foreman buried in spreadsheets and reports, LLMs can help. They won’t take you out of the office, but they might help you spend less time there. After all, most of us entered this profession because we appreciate trees. Wouldn’t it be nice to spend more time with them in the field?
Editor’s Note: To learn more about AI, ML and LLMs in UVM, listen to the Line Life Podcast episode featuring Phil Swart and Jason Grossman at linelife.podbean.com.
PHIL SWART (reddirtarborist@gmail.com) is the regional sales manager at ArborWorks, where he helps utilities and cooperatives address corridor vegetation challenges with practical, science-based solutions.
JASON GROSSMAN (jason.grossman@libertyutilities. com) is a seasoned utility vegetation management professional with almost 20 years of experience leading data-driven, field-tested programs that prioritize safety, reliability and operational efficiency.
Miles Bell
The journeyman lineman investigates large outages in Duke Energy’s reliability department in western North Carolina.
Early Years
I learned about becoming a lineman shortly after I got out of school from a friend, and it just seemed like the perfect fit. My dad is a farmer, and I grew up working outside on equipment and with my hands, and I always knew that was where I wanted to be. It didn’t take long to fall in love with line work, and it just seemed to come natural to me. I was the first person in my family to become a lineman, but now my younger brother is a transmission lineman.
Day in the Life
I started as an apprentice lineman for Duke Energy and worked my way up to journeyman. I recently moved into the reliability department at Duke Energy. My main responsibilities now are investigating large outages and finding ways to harden our system and eliminate problems that cause outages for our customers. My typical workday now consists of looking at circuits and lines that consistently give us trouble and coming up with ways to improve on our reliability. The major challenge I face is trying to increase reliability in a mountainous area. I live in the Blue Ridge Mountains of North Carolina, and we have some rough territory and a lot of inaccessible lines. The biggest reward for me is always helping to get lights back on and help our communities during and after storms.
Safety Lesson
If you do line work long enough, you are sure to have some near miss encounters due to the constant variables you face all day every day. For me, one that really changed my outlook on everything was a near miss while we were rigging a pole into an inaccessible area. We had some things shift unexpectedly, and thankfully, no-one was in the line of fire, and we always adhere to strict safety protocols as part of our work. I always had the mindset to be careful working primary, and the rest of it was, “just go get it done,” until this moment. It really scared me and made me realize there are a lot of other ways to end up injured other than electrical events. I think a lot of people take things like this for granted, just like I did. It was really my “ahha” moment and changed my whole outlook on the day-to-day. It made me want to step up, be a better leader and influence others to slow down, always think safety first, be mindful of their surroundings and never cut corners.
Memorable Storm
My most memorable storm moment was this past year during Hurricane Helene. We had nearly 100% lights out and were
To learn more about Duke Energy’s experiences of restoring power following Hurricane Helene, listen to a future Line Life Podcast episode featuring Miles Bell and his coworkers at linelife.podbean.com.
• Born in Hendersonville, North Carolina.
• His brother is a transmission lineman for Duke Energy.
• Married to his wife, Haley, for 11 years. They have two children: seven-year-old Hadley and five-year-old Ridge.
• Enjoys camping, hunting, fishing, hiking, and playing sports.
• Loves going to Lineman’s Rodeos.
• Is currently working on multiple projects to build circuit ties between substations to allow for back-feed during outage situations. After these are complete, he and his crew will begin working to SCADA connect the circuits and make them self-healing capable.
starting from scratch. It took a week to get a single light on in the county I live in. After working 18-hour days and driving home in pitch black darkness every night, we heated up the first breaker and part of town lit up. It was the most amazing feeling I have ever had doing line work. People literally came out in the streets shouting and crying tears of joy. I ended up working storm for over two months. We had some rural areas where miles of line washed down the river. The roads were also either really rough or completely gone, which made the working conditions tough and impossible in some areas. Some places were completely cut off to travel to except by helicopter. The areas that were hit worst were the most challenging areas to begin with.
Tools and Technology
Just a few of the tools I can’t live without are an impact, side cutters, climbing gear and a good flashlight. There are some amazing technologies being developed and improved on daily for the industry, and it’s really exciting. For example, there is a battery tool for just about everything now. This helps reduce injuries and to be more efficient. We are using a lot of new equipment to help reach inaccessible areas that make work safer and quicker.
Plans for the Future
I would most definitely go into the power industry if I had to do it over again. It’s a rewarding career that will provide a great life for you and your family. There are always opportunities to be creative and think outside the box. It’s really cool to work in an industry that provides a service that improves the lives of everyone around you. My plans for the future are to continue working in the utility industry until retirement.
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What does an 18-ton underground vault have to do with reliable power? A lot! Our new training tool at Nebraska City Station helps us evaluate critical hands-on skills for roles like steamfitter mechanics, ensuring the people behind the power are ready for anything.
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Puget Sound Energy @ PSETalk
PSE has partnered with the @CityOfSumnerWA on the White River restoration project that aims to restore salmon habitat and reduce flood risks in the area.
Tennessee Valley Authority
Demolition crews safely brought down both stacks and a large emissions-control building at the retired Bull Run Fossil Plant. Clearing these structures marks a key step toward repurposing the site for potential new energy technologies to help power the region.
Evergy @evergypower Planning for the unexpected is part of what we do every day. At Evergy, reliability isn’t just about
Texas-New Mexico Power (TNMP)
reacting to extreme weather— it’s about staying ready for it. When severe weather hits, our teams are already in motion— strategically positioned to restore power quickly and safely.
Full circle moments like these showcase the power of mentorship and the deeprooted bonds within the lineworker community.
Three TNMP employees— including a former instructor and a recent graduate—had the honor of serving as judges at the Northwest Lineman College graduation rodeo. Their involvement reflects not only their individual journeys but also TNMP’s ongoing commitment to growing and supporting the next generation of lineworkers.
MEDIA SALES
Director, Business Development
Stephen M. Lach
Phone: 708-542-5648
Email: slach@endeavorb2b.com
Account Manager
Brent Eklund
Phone: 303-888-8492
Email: beklund@endeavorb2b.com
Account Executive
Andreja Williamson
Phone: 630-721-0712
Email: awilliamson@endeavorb2b.com
INTERNATIONAL SALES
Europe
Sarah Howell
Phone: +44 7935 299 884
Email: showell@endeavorb2b.com
South America, Central America
Fernanda Vega
Phone: +55 21 97673-9692
Email: fvega@endeavorb2b.com
Middle East, India, Asia, Australia, Africa
Saurabh Kapoor
Email: skapoor@endeavorb2b.com
EVENT SALES
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John Blackwell
Phone: 518-339-4511
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Account Manager
Denne Johnson
Phone: 607-644-2050
Email: djohnson@endeavorb2b.com
International Linemen’s Rodeo, and Events
Sam Posa
Phone: 913-515-6604
Email: sposa@endeavorb2b.com
MEMBERSHIP SALES
UTILITY ANALYTICS INSTITUTE
Membership Development Manager
James Wingate
Phone: 404-226-3756
Email: jwingate@endeavorb2b.com
Utility Analytics Institute, Smart Utility Summit and Smart Water
Inertia – Good or Bad?
At the end of April, a massive blackout swept through parts of Europe, centered in Spain. While early media coverage fixated on a lack of inertia, the Spanish government later clarified that the primary issues were related to visibility and control of inverter-based resources. The final report with the detailed analysis is still pending, so the real root causes are still unknown. Still, the role of inertia, both natural and synthetic, remains a critical design question for grid operators.
Inertia is a term all engineers learn in Introduction to Engineering. Like friction, it’s a concept they can usually explain to non-engineers. But quantifying how much inertia is needed to keep the grid stable is another matter. Even among the engineers studying it, there’s debate over how to calculate these values, particularly as new sources like grid-forming inverters enter the mix. There are competing models of how to calculate values, and several peer reviewed papers that offer different answers to those questions.
So why was the lack of inertia being blamed? About 70% of generation came from inverter-based resources (IBRs), which provide less inertia than synchronous machines. Plus, most synchronous generation was offline that mild spring day.
These measures may sound demanding — but if we’re serious about a zero-carbon grid, they’re not optional. They’re essential.
What the media missed were other forms of inertia — loadside motors, pumped hydro, and even IBRs themselves. These are often overlooked. While we don’t have the full data picture, some snippets suggest:
• The load was dropping during the lunch period
• Solar output hit a 2025 record just before the event
• Grid voltage was reported high at the time
One hypothetical scenario — unconfirmed by the Spanish report but technically plausible — is that voltage remained elevated beyond overvoltage relay thresholds. Inertia may have delayed the system’s response just long enough to trip protection. If substation load and nearby generation were lost, it could have triggered a cascading failure. Though recent findings emphasize visibility and control of IBRs, this possibility shows how inertia — typically stabilizing — can under certain conditions act as a destabilizer. FERC Order 901 and NERC’s efforts rightly focus on IBRs, but we must also model synthetic and load-side inertia more rigorously.
A recent NERC alert makes clear: we still lack accurate grid models. As we redesign the grid, we need to understand the transient and dynamics of each source and their impacts, including inertia. Are synchronous condensers and new protection schemes part of the future? How much synthetic inertia can we draw from storage and grid-forming inverters? Can we turn off inertia when needed, and when is that time? What highspeed controls will we need? Should 10% of ALL generation
be reserved for primary frequency response? Can operators adjust sources from 1 kW to multi-gigawatt plants in real time?
There have been eight other blue-sky blackouts globally in 2025. Fixing our models and understanding these dynamics is critical to future grid stability.
Early Findings
In June, the Spanish government reported that while solar wasn’t the root cause, it was a major contributor — particularly due to issues with interconnection, control, and visibility.
The report is short on details. It mentions control problems before the blackout and sudden losses of distributed generation (117 MW in one case). Curtailment wasn’t cited, but visibility and solar loss were mentioned repeatedly.
The ENTSO-E investigation is still ongoing, but Spain’s report suggests several urgent actions for North America:
• Full system visibility: All interconnections must be visible to DSOs or TSOs in real time.
• Dynamic modeling: Owners/installers must provide transient and dynamic system models. Inverter manufacturers must supply models to operators.
• Operator control: DSOs/TSOs must be able to curtail generation and change power angles directly.
• Inclusive rules: Apply to all, including storage, wind, and limited/no-export systems.
• Pre-approval of changes: Active component updates must be approved with updated models.
• Ride-through and relay standards: All systems must have utility-grade relays and ride-through capability, with <2 seconds of inadvertent export.
• Accountability: Systems must respond to control commands — or owners bear liability.
• Frequency response: All systems must support primary frequency response.
The DOE should be funded to test inverter behavior, and state commissions should revisit interconnection rules. AHJ inspectors need stronger training, and installers should be licensed for commissioning systems.
These measures may sound demanding — but if we’re serious about a zero-carbon grid, they’re not optional. They’re essential.
DOUG HOUSEMAN is a veteran of the industry, with many years of experience in the global industry. He has spent the last four decades consulting on T&D related issues. Doug is a managing consultant for 1898 & Co. He is a senior member of IEEE and a very active member of the Power and Energy Society. His work spans more than 50 countries and more than 200 utilities.
