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Powered by Foresight: LiDAR and AI Reshape Risk Management
By ANABEL ROZA, Seattle City Light
New on tdworld.com
Utility Business:
Reports: ICE Agents Pose as Utility Workers, TEP Objects to Misrepresentation
To combat criminal scams, utility workers will identify themselves with name badges and uniforms, and leave notice in advance of their planned visits via mailers and/or doorhangers. https://tdworld.com/55294562 Utility Business: Blackstone Buying TXNM
Including debt and preferred stock, the deal values the parent of PNM and TNMP at about $11.5 billion. It is expected to close in the second half of 2026. https://tdworld.com/55291300
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Allows for enhanced expansion and contraction with ground movement
Impact and UV resistant
Temperature tolerance (-40 to +230 °F)
From Beryl to Better: A Utility Reinvents Itself
Trust, transparency and technology: These three words exemplify CenterPoint Energy’s reinvention of its hurricane preparedness strategy.
Last fall, I wrote about the public scrutiny and criticism of CenterPoint’s storm response after Hurricane Beryl, and I defended the utility’s restoration efforts and condemned the abuse of lineworkers, and the mob mentality and negativity that comes from social media and sensationalism.
I still stand by my comments, as CenterPoint had restored power to 98% of its affected customers by July 19, 10 days after Beryl made landfall, knocking out electricity to 2.2 million customers. That was a record recovery. And it’s never OK to attack lineworkers or to be cruel to CenterPoint’s employees.
But some of the public criticism was warranted, and state regulators demanded answers: CenterPoint’s outage map was lacking (people were looking at the map of Whataburger’s closed locations to figure out where outages were still concentrated). Communication within the company and with customers was an issue.
What happens next is remarkable; the CenterPoint CEO took accountability and apologized. Utilities have learned from disasters over the years, and these lessons have helped them improve resiliency and response on many fronts. But I don’t think I have ever seen a utility step up like CenterPoint did.
As soon as they had restored power, the company set to making changes. CEO Jason Wells appeared before the PUC and the House of Representatives. It relaunched its Outage Tracker. It withdrew its 2024 rate case filing as part of commitment to “act urgently and immediately to improve and strengthen” resiliency. Then came the Greater Houston Resiliency Initiative that included more than 42 “critical” actions to strengthen the grid and improve customer communications and emergency coordination. That was Aug. 5, 2024. Community open houses followed, allowing customers to have their say, but also for the utility to talk about its GHRI plan.
Then in September 2024, CenterPoint hired a new senior VP and chief communications and marketing officer. It was Keith Stephens. He would be responsible for making improvements in how the company communicates and engages with customers, stakeholders, media and the public. He came from National Grid where he was based in London; and he had previously served in leadership roles at PG&E and Fluor Corp. All his positions involved public affairs and communications.
Fast forward to June 2025. Stephens spoke at the American Marketing Association luncheon in Houston to share the utility perspective of marketing and communications. T&D World’s
publisher Diana Smith and an editor for our sister brand Oil & Gas Journal, Conglin Xu, attended for us.
Stephens acknowledged past shortcomings in hurricane response; apologized and promised a new level of readiness and openness. He also emphasized that rebuilding culture and trust takes five to seven years and involves consistent, visible change “even down to how the trucks look when crews arrive.” Consistency — from equipment to messaging — remains central to restoring and maintaining customer trust.
He also said that CenterPoint had redesigned its communications strategy prioritizing frequency, clarity, and transparency. The utility now has a set plan to do updates at 10 days, five days, three days, and 24 hours before a storm, and a minimum of four communications per day during an event. It is providing bilingual, real-time outage updates through the new cloud-based Outage Tracker. The plan also includes extensive use of social media and public-facing platforms like the Houston Chronicle to keep customers informed.
Since launching GHRI in response to Hurricane Beryl, CenterPoint has completed all of its key actions of Phase One and Two. When combined, the company has completed the following actions:
• Installed or replaced more than 26,000 storm-resilient poles.
• Undergrounded more than 400 miles of power lines.
• Installed more than 5,150 automated reliability devices and intelligent grid switching devices.
• Cleared more than 6,000 miles of higher-risk vegetation.
• Installed 100 weather monitoring stations.
Now, CenterPoint is expanding its focus to community resilience and long-term reliability amid Texas’s energy deregulation. Coordination with local communities is in full swing. CenterPoint is donating and installing backup generators at key facilities: clinics, shelters, cooling centers. It is also hosting hurricane preparedness events and webinars for local residents.
CenterPoint Energy’s transformation following Hurricane Beryl offers the electric utility industry a powerful example of how to turn public criticism into meaningful change. The company didn’t deflect — it listened, took accountability, and acted. By investing in transparency, customer communications, and grid resilience, CenterPoint set a new benchmark. Its response shows that trust isn’t rebuilt overnight — it takes visible, sustained progress and a willingness to engage openly with customers and regulators alike. For utilities, the lesson is clear: Preparedness goes beyond poles and wires. It requires culture change, proactive communication, and authentic community partnership. Trust, transparency, and technology aren’t just buzzwords — they’re a utility’s lifeline.
Bio-Inspired Undergrounding Technologies
One of my favorite weekly newsletters just hit my inbox and it was full of news about robots and robotics. The main headline was about utilizing robotic worms to simplify underground distribution line installations, but then a better clickbait headline got me. It said, “robots race against humans in mini-marathon.” I clicked on it, how could I ignore that? Turns out there was a half-marathon race. It was held for both humans and bipedal robots in Beijing a few months ago. It was the first time robots and humans took part in a racing event, but the humans and the robots did not actually race against each other.
They each had a separate race with the robots taking the field after the humans moved out. Being a first time event, the robot developers learned a lot about the rigors of competition. The robots had plenty of problems, nevertheless the crowd witnessed an exciting event. Of the 21 robots entered, only six finished the race. One collapsed a few steps beyond the starting line, one
fell over at the starting, and another crashed into a barrier. In spite of all that, I’m sure their learning curve took a big jump upward. Racing has a way of boosting technology and I can’t wait to see what happens with the next race!
Improving Undergrounding
Getting back to the robotic worms that initially caught my eye, they’re part of the DOE (Department of Energy) three-year GOPHURRS (Grid Overhaul with Proactive, High-speed Undergrounding for Reliability, Resilience, and Security) program. DOE is spending US$ 34 million to fund 12 projects with an eye to improving undergrounding technologies. DOE pointed out “there are no fast or cheap methods for undergrounding lines in existence yet.” That’s why DOE is interested in advancing the technology.
DOE noted, the U.S. distribution system has “over 5.5 million line-miles (8.8 million km)” with the majority being overhead. With about 90% of outages happening on the distribution system, putting them underground is a major goal for grid modernization. Using today’s open trenching methods the cost can range from US$1.5 million to US$6 million per mile to underground the average distribution line. When we start talking about transmission lines, the costs per mile become astronomical!
Before someone writes to tell me there’s also the trenchless process known as horizontal directional drilling (HDD), they’re not fast or cheap either. Also, it’s well-known they damage anything in their path. That is why Sandia National Labs is taking part in the GOPHURRS program with a project of its own. Sandia is developing “a real-time, drill-mounted, cross-bore detector using ground penetrating radar to reduce the risk of damaging existing underground infrastructure.” It can see cross-bore problems and avoid them, which should be a huge plus for keeping the below grade infrastructure intact.
Worm-Like Robots
There are some really interesting projects under this GOPHURRS banner, but it’s worm-like robotics that attracted my attention to the subject in the first place. There are a couple of bio-inspired projects that are capturing interest in the program. The two most popular examples are the worm and the mole, but it wouldn’t surprise me to find other types of burrowing critters inspiring designers. Let’s look at a couple.
Case Western Reserve University is developing “a worminspired construction tool.” It’s a self-propelled robotic sleeve device that moves much like an earthworm. This peristaltic motion uses an expansion and retraction method of movement to dig while laying conduit as it goes. The developers say it’s much cheaper, more accurate, and can turn in a few feet rather than the hundreds of feet needed by today’s HDD methods.
GE Vernova Advanced Research is developing a robotic worm tunneling construction tool they call SPEEDWORM. GE’s designers say, “It mimics the natural movements of earthworms and tree roots.” It digs and installs conduit and cables for underground distribution power lines and can be deployed from a standard pickup truck eliminating complexity.
Cornell University is developing “a mini-mole combustionpower soil fracturing head to minimize environmental disruption.” They reported it uses soft robotics for improved steering and movement. It’s capable of tunneling, laying conduit, and installing cables without damaging the surface.
Robotics have improved many processes and now they’re going to improve some smart grids applications. It’s a promising technology that seems like a fast, cheap, and safe method to install power lines underground. It’s certainly needed with all the new challenges coming our way. It’s definitely a trending technology worth tracking!
Traditional methods of duct bank installations are disruptive, expensive, and visible to the public.
Philipp Berezhnoy / iStock / Getty Images Plus
AI-Driven Digitalization— The Next Step To A Smarter Grid
End-to-end digitalization is critical for addressing roadblocks and bottlenecks.
Have you noticed that technology never stands still? That’s not exactly a news flash for anyone trying to keeping up with this rapidly evolving environment. Watching for new technological trends is one of the best ways for keeping up with smart grid innovations, but it’s not easy. There is, however, a shortcut that professional tech-watchers have learned. Check out the variety of webinars, podcasts, or virtual panel sessions; they can give searchers an edge. First off, these web events are convenient and easily accessible. Second, where else can you learn directly from the experts so easily?
In terms of popular topics, digitalization is a widespread attention grabber, but there’s an interesting twist as digitalization evolves. The web broadcasts are not zeroing in on the run of the mill digitalization. They’re focused on the combination of
digital-based applications and artificial intelligence (AI), but there’s a caveat. It’s important that the digitalization isn’t limited to IT (information technologies) networks. It needs to include the OT (operational technologies) portion too. These environments have to exchange data and interact together rather than operate separately.
Growth of Digitalization
Digital technologies mixed with AI are simplifying the smart grid’s complex digital-based applications, which is helping their acceptance. After all, the more user-friendly the technology is will impact how well it’s received by the marketplace. The research company ResearchAndMarkets recently published some fascinating facts concerning the smart grid market. According to their research, “The global smart grid market is poised for significant growth.” They went on saying, “the global
smart grid market, valued at US$55.54 billion in 2024, is projected to grow to US$145.42 billion by 2030.”
That percentage of growth in such a short period of time indicates the technology is meeting the customer’s expectations for grid efficiency, resilience, and improved flexibility. AI-driven smart grid technologies are making grid-enhanced technologies more dynamic, which is helping solve many of the increasing load growth as power grid challenges mount. It’s the real-time data analytics and situational visualization capabilities that enable a better blending of the physical world with the virtual world. Keeping it simple, it’s the integration of IT and OT. This has been labeled the convergence of IT and OT (IT/OT). Some experts say it’s a transmutation that has made possible a variety of digital-based applications to operate beyond the
We
alvarez / E+ / Getty Images
traditional boundaries so prevalent in traditional organizations. The IT/OT convergence adds more awareness while extending its reach. The integration of AI into smart grid applications has brought a significant tool when it comes to bigdata analytics.
Real-Time Decision Making
AI is automating many operational and maintenance tasks, and it’s more responsive with load and energy management platforms to name a few. State-of-the art digital technologies are responsible for bringing the edge of the grid to a new prominence in the power delivery system. It has also made the behind-the-meter more accessible benefiting both sides of the meter, but the introduction of AI is redefining the concept of the modern smart grid. It’s facilitating real-time analysis of the massive amounts of big-data coming from smart grid systems, but it’s more than just this specific data stream. AI platforms are making information available from multi-databases improving
intelligent decision-making. The process is transforming the power delivery system, but it’s still a long way from a totally digitalized power system. So it’s reasonable to say that if we’re going forward, it’s going to take a more coordinated effort. With that in mind, it’s time to talk with an expert. “Charging Ahead” contacted Adnan Chaudhry, the senior vice president Digital Grid at Siemens Energy for his thoughts on digitalization joined with AI.
Mr. Chaudhry began the discussion saying, “Continuing to add assets in the grid alone won’t satisfy the growing hunger for electricity challenging utilities worldwide. To fully use the existing transmission assets on the grid, we need to digitize everything and utilize AI analytics. Digitalization combined with AI is the missing element for taking the power grid’s efficiency to the next level, but many utilities are only starting this process. They may have a digital substation or maybe a few powerlines with dynamic line rating technology. It’s a great starting point, but more is needed to make the most of underutilized assets.”
Chaudhry continued, “How can the power grid handle the increasing power demand? It needs its efficiency increased. Adding lines, generation, or substations is crucial, but a highly time-consuming process, which can’t quickly solve today’s grid congestion or other bottlenecks. It’s not a secret, we have never used the existing grid anywhere near its actual limits. It’s always been constrained by assumptions and the static limits set on its assets. When sensors are added to a line, the data tells the user how much capacity is really available in that line. Many are surprised that it can be 20% or more.”
Mr. Chaudhry explained, “To enhance the grid in a holistic way, it’s essential to add sensors to transformers, switchgear, and other equipment. For real-time operations you need real-time data, as it gives a dynamic overview of network conditions. That’s why Siemens Energy’s digital grid portfolio focuses on digitizing the entire system from end to end. It also takes advantage of external
databases that use AI’s predictive analysis to improve various aspects such as planning, load management, operations, and maintenance. AI and machine learning applications have brought predictive maintenance to a new level improving efficiency and productivity.”
Chaudhry continued, “A good comparison of what is happening in the power grid can be found in the automobile industry. Thirty years ago, cars didn’t have sensors. We had no way knowing the condition of the engine, transmission, or other components. Maintenance was determined by the calendar or the vehicle’s mileage. We didn’t know the condition of the engine, so at ten thousand miles the vehicle was brought in for maintenance. Today the vehicle’s instrumentation notifies the driver of any potential problems and recommends maintenance within a specific timeframe. This is exactly what our sensors on the power grid do. Predictive analytics have reduced the number of unscheduled outages and made us more efficient in the process. It’s not a
question of whether to digitize or not. It a question of how to do it efficiently and cost effectively!”
Aligning Real & Virtual Worlds
AI-driven digitalization applications are a new approach that many utilities and grid operators are actively pursuing. Some are utilizing a simple approach while others are going deeper into the technology. Companies like GE Digital, Hitachi Energy, Oracle, Schneider Electric, Siemens Energy, and others offer a variety of products.
For several years, American Electric Power (AEP) and Siemens Energy have been working together on the implementation of a digital twin of AEP’s entire transmission network. It’s a massive undertaking considering AEP has over 40,000 line-miles (64,374 line-km), covering 11 states serving nearly 5.6 million customers. According to Siemens Energy, AEP expects to utilize a complete digital model of their physical grid that can quickly adapt to grid changes while
increasing renewable capacity efficiently, safely, and reliably.
Late last year, Southern California Edison (SCE) received an achievement award from the Association of Edison Illuminating Companies for its AWARE (Advanced Waveform Anomaly REcognition) platform. This inhouse suite uses AI-driven tools to analyze system realtime data. The data comes from substations, AMI (Advanced Metering Infrastructure), and SCADA (Supervisory Control and Data Acquisition) systems. The AI algorithms identify abnormal patterns in grid behavior. It also “pinpoints the location of potential problems.”
A few months ago, Alphabet Inc. announced their Google and Tapestry units have formed a partnership with PJM Interconnection, the largest regional transmission operator in North America. PJM manages over 88,000 line-miles (141,600 line-km) in 13 states. The collaboration’s goal will apply AI-driven technology to consolidate the dozens of databases and tools used by PJM for their interconnection procedures into a unified model of the PJM network. The unified model will speed up the interconnection process, which will enable PJM to make faster decisions with greater confidence.
Stay ahead with the latest research and strategies for making informed insulator selection with The Insulator Education Initiative - an information hub with research, comparison tables, videos and online tools for optimizing grid performance, reliability & safety.
The digitalization of the power delivery system is a growing trend and it’s expensive, but the experts are predicting the return will surpass the outlay significantly. When AI technology is combined with smart grid applications it enhances grid stability, optimizes demand management, improves energy efficiency, and the list grows. Mr. Chaudhry said it best, “To fully use the existing transmission assets on the grid, we need to digitize everything and utilize AI analytics.”
It’s also extremely important we understand how these technologies work and what their limitations are, which can be a challenge since they are evolving so quickly, but that’s what makes it fun. Capgemini reports that “a planned and holistic approach is needed for grid transformation by digital innovations.” Of course, we have to overcome legacy thinking too. It can hold us back more effectively than any other obstacle, but this could be the next step to the future grid!
QUICK CLIPS
Expert Panel Begins Investigation into Iberian Peninsula Blackout
An investigation has been launched into the widespread power outage that affected the Iberian Peninsula on 28 April 2025. A joint Expert Panel has been established by the European Network of Transmission System Operators for Electricity (ENTSO-E), in coordination with its member Transmission System Operators (TSOs), the Agency for the Cooperation of Energy Regulators (ACER), National Regulatory Authorities (NRAs), and Regional Coordination Centres (RCCs). The panel includes experts from both affected and unaffected TSOs and is chaired by representatives from TSOs not directly impacted by the incident.
The investigation will follow a two-phase approach in line with the “Incident Classification Scale Methodology.” The first phase involves the collection and analysis of relevant data to reconstruct the sequence of events and identify the causes of the blackout. Findings from this phase will be compiled into a factual report. The second phase will focus on developing recommendations to reduce the risk of similar events in the future, to be published in a final report.
The process is being conducted within the framework of European Union Regulation (EU) 2017/1485 on the System Operation Guideline. Final results will be shared with the European Commission and EU Member States through the Electricity Coordination Group before being published.
Preliminary Timeline of Events
On 28 April 2025 at 12:33 CET, a blackout occurred across Spain and Portugal, with a limited impact in a small area of southern France. The broader Continental European power system remained unaffected.
In the 30 minutes prior to the incident, two intervals of system oscillations (in power and frequency) were observed in the Continental European synchronous area: between 12:03–12:07 CET and 12:19–12:21 CET. Measures were taken by the Spanish (Red Eléctrica) and French (RTE) TSOs in response. At the time of the blackout, system conditions were within normal operational ranges, and no oscillations were reported.
At the time, Spain was exporting 1,000 MW to France, 2,000 MW to Portugal, and 800 MW to Morocco.
Based on currently available data, the following sequence of events occurred:
• At 12:32:57 CET, a series of generator trips occurred in southern Spain, resulting in an estimated 2,200 MW of lost generation. No generator trips were reported in Portugal or France. These events led to a frequency drop and a voltage
increase in Spain and Portugal.
• By 12:33:21 CET, the frequency had fallen to 48.0 Hz, prompting the activation of automatic load-shedding mechanisms in both Spain and Portugal.
• At the same time, AC transmission lines between France and Spain were disconnected by protection systems responding to a loss of synchronism.
• At 12:33:24 CET, the electricity system in the Iberian Peninsula fully collapsed, and HVDC connections with France ceased operation.
Restoration efforts began immediately. Key steps included:
• 12:44 CET: The first 400 kV transmission line between France and Spain was re-energised.
• 13:04 CET: The interconnection between Morocco and Spain was restored.
• Around 13:30 CET: Spanish hydro power plants with black-start capability initiated restoration procedures.
• 13:35 CET: The eastern France-Spain interconnection was re-energised.
• 16:11 and 17:26 CET: Two black-start capable power plants in Portugal successfully started, initiating localized restoration.
• 18:36 CET: A 220 kV tie-line between Spain and Portugal was re-energised, accelerating Portugal’s recovery.
• 21:35 CET: A southern 400 kV tie-line between Spain and Portugal was restored.
• 00:22 CET, 29 April: The transmission system in Portugal was fully restored.
• Around 04:00 CET: The transmission system in Spain was fully restored.
Expert Panel Leadership and Participants
The Expert Panel is co-led by Klaus Kaschnitz (Austrian Power Grid, Austria) and Richard Balog (MAVIR, Hungary). Participants include experts from ENTSO-E, RCCs, and TSOs. Key ENTSO-E expert convenors are:
• Olivier Arrivé — Chair, System Operation Committee
• Robert Koch — Convenor, Steering Group on Resilient Operation
• Albino Marques — Convenor, Regional Group Continental Europe
The process of appointing Expert Panel members by ACER and the NRAs is underway.
Further updates and findings will be released as the investigation progresses.
Entergy New Orleans Completes Upgrades to T&D Lines
Entergy New Orleans crews have completed major upgrades to transmission and distribution lines in Mid-City, Gentilly, and New Orleans East to help strengthen the electric grid and reduce the risk of outages.
The company deployed a specialized bare-hand crew to complete the work, a team of linemen trained to safely repair high-voltage, energized transmission lines.
The team completed work on a major transmission line in New Orleans, replacing older insulators on 26 towers with stronger, more modern equipment. Working in coordination with distribution and vegetation management teams, they also replaced aging wooden cross arms and cleared overgrown vegetation.
Additional work is under progress in New Orleans East, where the bare-hand crew is replacing insulators on several
water-crossing circuits. The crew is scheduled to complete critical upgrades on the Michoud–Front transmission line crossing over Lake Pontchartrain.
The line provides an interconnection between Entergy and Cleco and serves as an emergency power source for the New Orleans grid. The enhancements will strengthen the electrical grid and improve regional reliability.
North Houston Pole Line provided experienced contract support. Linh Tran, Grid Engineer; Josh Rollins, Transmission OC; Kenyon Stipe Sr., Transmission Line Supervisor; and Frank Morse, Senior Manager of Transmission Lines, played important roles in planning and execution. The Tulane Network also supported the project’s success.
IEEFA Report: Proposed Transmission Lines to Cost West Virginia Ratepayers Big
The latest report from the Institute for Energy Economics and Financial Analysis (IEEFA) has examined proposed transmission lines for northern Virginia data centers expected to cost West Virginia ratepayers $440 million.
The results revealed that the Mid-Atlantic Reliability Link and Valley Link transmission lines, both of which are anticipated to cut through parts of West Virginia, were proposed in response to forecasts of growing electricity demand in northern Virginia due to data centers. IEEFA believes grid operator PJM’s Regional Transmission Expansion Plan (RTEP) process should be reformed so that ratepayers across the PJM footprint are not bearing costs associated with transmission infrastructure due to data centers and by state policy decisions to attract more data centers.
“These projects are but two examples of how ratepayers are subsidizing electrical infrastructure projects that likely would not be needed without the addition of massive data center loads,” said Cathy Kunkel, IEEFA energy consultant and author of the report. “Under PJM’s existing transmission cost allocation methodology, West Virginia ratepayers, and others across PJM,
will bear additional costs in the future for further transmission needs associated with data centers, if forecasts of data centerdriven load growth in northern Virginia over the next 20 years materialize.”
According to previous IEEFA reports, there is a possibility that demand forecasts for data centers will turn out to be overstated, due to potential utility overestimation of data center demand and financial weaknesses in the artificial intelligence (AI) business model. The forecasts of growing data center loads, as well as the risk of stranded infrastructure costs, questions traditional methods of utility cost allocation.
PJM’s transmission cost allocation methods totally assume that regional transmission costs could not be attributed to a single new user or class of users. PJM’s transmission cost allocation methodology does not support Virginia making policy decisions to encourage a buildout of data centers.
Ratepayers across the region will continue subsidizing the tech industry’s electrical infrastructure demands except for PJM changing course.
Entergy
New Report Grades All 50 States on Electricity Market Competitiveness
The R Street Institute, a nonpartisan public policy research organization that promotes free markets and limited, effective government, has released a new report grading each U.S. state on the competitiveness of its retail electricity market. The State-by-State Scorecard on Electricity Competition evaluates how well states are fostering customer choice and market-based electricity options, highlighting best practices and recommending improvements.
This is the first comparative scorecard of its kind, providing an independent, data-driven assessment of how states approach electricity competition. The scorecard examines a range of factors including customer access to alternative suppliers, regulatory frameworks, market structure, transparency, and consumer education.
“Consumers demand choices and alternatives, and the provision of electricity shouldn’t be an exception to that expectation,” said Kent Chandler, R Street’s Resident Senior Fellow in Energy and Environmental Policy. “States that embrace competition can deliver lower prices, greater innovation, and more responsive service. Our scorecard offers both a snapshot of where states stand today and a roadmap for how they can move forward.”
State Grades:
• A-: Texas
• B+: District of Columbia, Illinois, Ohio, Pennsylvania
• B: Delaware, Maine, Rhode Island
• B-: Massachusetts, New Hampshire, New Jersey
• C+: California, Connecticut, New York, Virginia
• C: Colorado, Maryland, Michigan
• C-: Arizona, Hawaii, Montana, North Carolina, Oregon, Vermont
• D+: Arkansas, Kansas, Kentucky, Louisiana, Nevada, South Carolina
• D: Alaska, Florida, Georgia, Indiana, Iowa, Missouri, New Mexico, North Dakota, Oklahoma, South Dakota, Tennessee, Washington, West Virginia
• Not Scored: Nebraska (entirely served by public power utilities)
The authors (Chris Villarreal, Kent Chandler, Michael Giberson) also evaluated factors such as the role of regional transmission organizations (RTOs), the treatment of regulated monopolies, the availability of smart metering, and how well states equip consumers to make informed energy decisions.
“Electricity competition is more than just offering customer choice — it requires meaningful engagement, clear information, and regulatory structures that allow innovation to thrive,” said Chris Villarreal, Associate Fellow in Energy and Environmental Policy at R Street. “Our scorecard is designed to help policymakers see what’s working and where improvements are needed.”
Key areas analyzed in the scorecard include:
• States’ approaches to customer choice and competitive foundations
• Role and treatment of rate-regulated monopolies
• Availability of alternatives within traditionally regulated systems
• Wholesale market participation and RTO integration
• Smart meter deployment and access to energy usage data
• Price caps and product differentiation
• Customer education, marketing transparency, and complaint resolution
• Utility commission staffing and market oversight
• Role of state utility consumer advocates
The scorecard is intended as a resource for policymakers, regulators, and stakeholders who want to understand and improve the state of retail electricity competition. It highlights case studies of successful reforms and offers state-specific strategies to enhance competitiveness and consumer empowerment.
Seattle City Light underwent a shift to data-driven utility vegetation management to manage risks and improve reliability.
by Anabel Roza
For decades, utilities have approached vegetation management with a predictable cycle — assess, trim, repeat. While effective at preventing some outages, this method has long relied on broad assumptions rather than precise risk-based data. The result? Utilities are spending resources on trimming trees that pose no imminent threat while hazardous trees remain undetected until it’s too late.
Seattle City Light’s transmission lines often run through challenging terrain. Integrating LiDAR with AI-driven analytics enables precise, proactive assessment of vegetation threats in these remote areas.
Images courtesy of Seattle City Light.
The energy sector is now at an inflection point. Technologies including LiDAR, AIpowered analytics and real-time satellite monitoring are reshaping how utilities manage vegetation-related risks. Instead of reacting to outages or conducting static, scheduled maintenance, utilities can now predict and prevent failures before they happen — fundamentally shifting how grid reliability is managed.
Seattle City Light (SCL) is exploring this transition by integrating data-driven tools to modernize its approach to vegetation management. By combining older technology like aerial imaging and LiDAR scans
with satellite imagery and AI-powered risk modeling, the utility is working to move beyond cycle-based trimming toward a dynamic, risk-prioritized strategy. The shift is not only about improving reliability but also about optimizing spending, reducing emergency response costs and minimizing wildfire risks.
Vegetation management is only the starting point. What if utilities could layer LiDAR and AI-powered vegetation risk assessments with weather modeling, historical outage data and infrastructure condition monitoring to create a truly predictive operational system? As utilities
begin integrating multiple data streams, the potential for a smarter, more resilient grid becomes clear. This isn’t just about managing trees; it’s about managing risk intelligently.
Beyond LiDAR
LiDAR has revolutionized vegetation management by providing high-resolution, three-dimensional scans of transmission corridors. These surveys capture precise details about trees, power lines and structures, enabling utilities to assess encroachments and clearance violations with accuracy never before possible. But LiDAR alone isn’t enough.
Even with frequent flyovers, LiDAR data is static — it captures a moment in time. A tree might look stable in a scan today, but unseen stress factors like disease, drought or soil erosion could cause it to fail weeks later. By the time the next scheduled assessment comes around, the damage may already be done.
To bridge this gap, utilities are now combining LiDAR with real-time satellite monitoring, AI-powered analytics and historical reliability data. SCL is actively exploring how to layer these data streams
This scene illustrates the costly consequences of reactive vegetation management. Predictive analytics using satellite imagery and AI can anticipate these events, significantly reducing response costs.
to improve risk prediction. This includes:
• AI-driven risk assessments. Machine learning models analyze tree species and environmental conditions to predict which trees are most likely to cause failures. This can better identify vegetation stress indicators such as declining tree health, rapid die-off or shifting soil conditions.
• Dynamic risk scoring. Instead of treating all circuits equally, AIdriven models assess which areas require immediate intervention versus which can be safely deferred.
• Grid resilience modeling. SCL integrates maximum sag and maximum sway data into its risk assessments, modeling how conductors behave under different weather conditions to identify circuits most vulnerable to vegetation-related outages.
SCL is already using AI within its Work Studio platform that estimates tree health and assess fall-in risk. These models analyze vegetation stress, species type and environmental factors to highlight trees that could be at risk of failure. By combining
these AI-driven insights with LiDAR data, SCL can go beyond standard encroachment assessments and begin prioritizing trees that pose the greatest actual threat to reliability — not just those that happen to be within a clearance zone.
Why This Shift Matters
The traditional “trim everything on a fixed schedule” approach is outdated and inefficient. Utilities are under pressure to reduce costs, improve reliability metrics and enhance wildfire prevention strategies. AI-powered vegetation management is proving to be a critical tool in meeting these goals.
Consider the benefits:
• Increased reliability. A proactive, risk-based approach reduces vegetation-related outages and minimizes penalties.
Historical aerial imagery, like this 1991 photo, helps utilities understand how vegetation and landscapes change over decades. Integrating historical data with current LiDAR and AI analytics improves the accuracy of predictive modeling.
One unstable tree can compromise grid reliability or increase wildfire risks. SCL is actively exploring integrated LiDAR, AI and satellite monitoring tools to dynamically prioritize such vegetation risks.
The Data-Driven Approach
• Cost optimization. AI helps utilities prioritize spending by directing resources to high-risk areas instead of blanket trimming every circuit.
• Wildfire prevention. Predictive modeling enables utilities to identify high-risk vegetation before it becomes a problem, mitigating wildfire threats more effectively.
• Regulatory compliance. With increasing scrutiny from regulators,
utilities that adopt advanced risk modeling can demonstrate a proactive approach to vegetation risk mitigation.
SCL’s efforts are part of a broader industry movement toward leveraging AI and predictive analytics across utility operations. Grid modernization isn’t just about adding renewables or battery storage — it’s also about improving operational intelligence to manage risks more effectively.
SCL is exploring multiple innovations to better understand and mitigate vegetation risk. Key areas of focus include:
• LiDAR-based digital twins. By creating 3D models of its transmission corridors, SCL can conduct remote inspections, assess structural integrity and predict potential clearance violations.
• AI for vegetation risk analysis. Machine learning models process massive datasets, flagging trees at risk of failure based on species
This screenshot from Seattle City Light’s Work Studio platform demonstrates how AI identifies trees posing fall-in and health risks. Leveraging these analytics allows targeted vegetation management, focusing resources where they matter most.
type, environmental stressors and proximity to high-voltage lines.
• Circuit prioritization models. By layering historical outage data, vegetation encroachment trends and environmental conditions, SCL is working towards a system where circuits can be dynamically ranked for risk-based intervention.
• Emergency preparedness improvements. Instead of responding to outages reactively, SCL is working to anticipate storm impacts by integrating real-time
KEY QUESTIONS UTILITIES SHOULD BE ASKING
As the industry moves toward more predictive, data-driven decision-making, utility leaders should be asking:
1. How can we better integrate LiDAR, satellite imaging and AI into a unified risk assessment framework?
2. What existing data sources—such as weather modeling, outage reports and infrastructure monitoring—can be combined to enhance predictive analytics?
3. How do we balance automation with field-based verification to ensure AIgenerated risk assessments translate into effective action?
4. How can we shift from reactive maintenance cycles to fully dynamic, riskprioritized asset management?
Utilities that embrace these questions and take action will lead the next era of grid resilience.
vegetation risk models into grid management strategies.
This shift will certainly prove valuable. When severe windstorms hit the Pacific Northwest, utilities with predictive vegetation management systems will be able to preemptively reinforce at-risk circuits, reducing overall outage impacts. The ability to identify hazard trees before they fall has become an essential component of grid reliability planning.
Looking Ahead
The next five years will bring even more advancements in how utilities assess, predict and mitigate vegetation risks. But predictive modeling should not be limited to vegetation alone. Future innovations will likely expand into:
• Weather and climate forecasting. AI-driven weather models could integrate real-time satellite imagery, temperature shifts and wind pattern analysis to predict outages before storms hit.
• Reliability and outage prediction. Utilities could leverage historical outage trends and infrastructure stress indicators to anticipate which circuits are most at risk for failure.
• Cost-optimized maintenance planning. AI could determine not only where failures are most likely to occur, but also where preventative maintenance dollars will have the greatest impact.
SCL is actively exploring how to integrate these tools into its long-term strategy. The goal is to move beyond fixed maintenance cycles and create an
adaptive, risk-based system that continuously evolves based on real-time conditions and predictive analytics.
Moving Beyond Guesswork
The electric grid is only growing more complex. With climate change increasing the frequency of extreme weather events, utilities cannot afford to rely on outdated, cycle-based vegetation management strategies.
SCL’s journey reflects an industry-wide transformation. The utilities that embrace data-driven, risk-based vegetation management today will be the ones best positioned to improve reliability, reduce costs and enhance resilience for decades to come.
The future of the grid will not be managed with hindsight. It will be powered by foresight — and the time to invest in that future is now.
ANABEL ROZA (anabel.roza@seattle.gov) is the vegetation and wildfire mitigation manager at Seattle City Light, overseeing risk-based strategies to improve grid reliability and wildfire resilience. With a background in economics, environmental studies and operations, she brings a data-driven approach to vegetation management, integrating LiDAR, satellite imagery and AI-powered analytics into SCL’s decision-making framework. She is currently pursuing her MBA, with a focus on strategic leadership and clean energy. A former Navy officer, she applies her experience in risk assessment, operations and leadership to modernizing utility infrastructure and resilience planning. She is actively exploring how utilities can move beyond static maintenance cycles to prioritize circuits based on predictive analytics.
Georgia Co-op Boosts Resilience
Habersham Electric Membership Corporation (EMC) proactively invested in a grid modernization and resiliency plan that improved service reliability for its 28,000+ members.
The newly deployed technologies enable real-time monitoring and automated fault detection, isolation and restoration.
Images courtesy of Habersham EMC.
By Mark Leach, Habersham EMC
Habersham EMC (HEMC), chartered in 1938 as a nonprofit cooperative, provides reliable, clean and affordable energy across more than 3,800 miles of line in six counties across northeast Georgia: Habersham, Hall, Lumpkin, Rabun, Stephens and White. As part of the co-op’s commitment to providing its more than 28,000 members with the most reliable and efficient service possible, Habersham EMC proactively undertook a grid modernization program in 2020 that invested in some grid-enhancing solutions from S&C Electric Co.
As a result of this innovative program, in 2024, we saw an overall 14.6% average reduction in outage duration compared with the preceding three years. Individual members experienced a 38% decrease in the minutes they were out of power.
The newly deployed technologies — IntelliRupter PulseCloser Fault Interrupters, TripSaver II Cutout-Mounted Reclosers, and IntelliTeam FMS Feeder Management Systems — enable real-time monitoring and automated fault detection, isolation and restoration.
This program has helped us deliver on our commitment to continually provide our members with clean, reliable affordable energy. By investing in grid modernization and focusing on resilience, we were able to improve the reliability of our electricity delivery to our members.
The Challenge
The HEMC distribution system is built through heavily forested and mountainous terrain. The challenges we face as a utility are far different from those faced in other areas of the country and even within the state of Georgia. Access is difficult to many areas where our lines are built, and outages caused by animals and trees falling are constant. Therefore, innovative application of automation technologies is instrumental to helping us improve the resilience and reliability of our grid.
As a utility with mountainous terrain covered by large tracts of national forest, we face a continuous battle to improve reliability. HEMC has taken this challenge head on with a goal to offer some of the best reliability within the state.
Getting Started
HEMC’s grid modernization and resilience plan started in 2020 after the arrival of our new CEO, Bryan Ferguson. With an extensive background in the utility industry, he began the hiring and placement of personnel to achieve his goals in safety, member satisfaction, and reliability.
Ferguson then hired a new vice president of engineering and operations, a new director of engineering and a new manager of engineering and the plan to fully deploy an automated and effective grid
modernization system began to become reality. The goal of the initiative was to improve service reliability for all members.
The Goals
HEMC started our grid modernization journey by identifying the top 10 worstperforming circuits on our system. Specifically, we looked at reducing the number of sustained outages (measured using SAIFI and SAIDI). Then, HEMC developed a plan to deploy automation with these key goals:
• Improved reliability and resilience: Advanced protective devices will allow power to be automatically restored following a fault.
• Reduced downtime and maintenance: Because advanced protective devices are automatically resettable, Innovative application of
we avoid the need for frequent site visits to replace fuses.
• Enhanced safety: Advanced protective devices allow for more precise and faster responses to faults, minimizing the risk of electrical fires.
• Integration of smart grid technologies: This project includes real-time monitoring, communication capabilities, and data analytics, providing HEMC with more control and insight into our distribution networks.
• Advanced fault detection: This is achieved through the incorporation of advanced fault detection technologies, including ground
fault protection and arc fault detection.
The Solution
Once our goals were established, it was time to create a plan. HEMC chose to collaborate with S&C Electric Co. to implement grid-enhancing technologies to make these goals a reality.
“We are dedicated to staying at the forefront of grid modernization to better serve our members,” said our CEO, Bryan Ferguson. “Our close collaboration with S&C has been instrumental in enhancing the resilience and reliability of our system. We are proud to be a leader in adopting advanced technologies that improve the
overall efficiency and sustainability of our operations.”
The HEMC plan was simple:
• Replace every oil-filled recloser on our lateral lines with a new S&C TripSaver II recloser. These modern reclosers automatically restore power after temporary faults, preventing outages and unnecessary truck rolls or site visits.
• Break up our feeders into smaller sections by installing S&C IntelliRupter fault interrupters at key feeder locations.
The S&C automation solution included equipment for feeders and laterals. The fault interrupter incorporates PulseClosing technology, which uses 95% less energy than conventional reclosers when testing for faults.
Once our fault interrupter and fault detectors were installed, these devices were connected to our system wide fiber network and to SCADA. This provided complete visibility and real-time access from our control center at our headquarters office to all this equipment throughout our territory. With real-time notifications and full control of our circuits, we can immediately identify fault locations when they occur.
HEMC has been able to set up automated restoration loops using the new fault interrupters and the feeder management system. When a fault is detected, the devices begin to communicate between each other to identify, isolate, and switch as necessary to keep the power on for as many of our members as possible. By deploying this equipment as HEMC did, the utility implemented automation schemes that allow sectionalization and rerouting of power in seconds.
HEMC did not only focus on automation. Our plan also included a focus on right-of-way trimming, upgrades to overloaded circuits and building more ties so that a loss of power in one area could immediately be fed from another circuit.
The Results
Since deploying S&C technology, Habersham EMC has achieved a 14.6% average reduction in outage duration compared to the previous three years.
Additionally, individual members experienced a 38% decrease in the minutes
Habersham EMC is responsible for more than 3,800 miles of line.
they were out of power. This reduction in outage duration means fewer disruptions and more reliable power for the homes and businesses that depend on electricity for everything from mobile phones and personal computers to transportation and home health care.
HEMC uses industry standard metrics for recordkeeping and for tracking reliability. This includes SAIDI, SAIFI, and CAIDI. By deploying automation equipment in the field, HEMC has seen an overall downward trend in SAIDI, SAIFI and CAIDI metrics. In fact, our CAIDI metrics are below the national average standing at 77.53 for 2024.
These service improvements have led to increased member satisfaction. In the fourth quarter of 2024, Habersham EMC was recognized by Touchstone Energy as a member cooperative that received one of the top five American Customer Satisfaction Index (ACSI) scores for energy utility services among all cooperatives participating in measurement for Touchstone Energy.
We received an ACSI score of 89 on a 100-point scale. HEMC’s score is higher when compared to publicly measured cooperative utility scores reported in the syndicated 2024 ACSI Energy Utility Study and places HEMC 15 points higher than the average investor-owned utility score of 74, 14 points higher than the average municipal utility score of 75, and 11 points higher than the average cooperative utility score of 78.
To improve our system’s performance further, we recently installed new Compact IntelliRupters at one of our stations. This version retains the core functionality of the IntelliRupter in a more compact form factor. It is designed for specific applications where space is limited, such as overhead lines and underground distribution systems. HEMC is the first co-op in the state and second in the nation to implement this version. We know this will add to the successes we are seeing in automation and reliability.
The Future
Looking ahead, HEMC will continue to collaborate with S&C, and deploy IntelliRupter fault interrupters, TripSaver reclosers, and other advanced solutions
across our system to quickly isolate outages and improve the level of service we deliver to our members.
We will continue to build a modern grid that delivers on our promise to provide clean, reliable, affordable energy for our members.
MARK LEACH is a technical leader with nearly 40 years of experience in leadership, engineering and
program management in the electric utility space. He has a thorough knowledge of nearly all operating areas within the utility industry including distribution and transmission operations, power generation, SCADA, metering, system automation and coordination, regulatory and MDM systems. He has served and led industry related, national committees and has been successful at budgeting and leading large statewide organizations. His passion is developing new strategies and planning to meet the future needs of the industry.
NO COMPROMISE. MORE CAPACITY. and
Still Made in Seward, Nebraska, USA
Delivering for Growing Demand
Attendees of Accenture’s IUEC 2025 shared their ideas for delivering energy that is affordable as well as clean and reliable.
By Jeff Postelwait, Managing Editor
Of the many topics explored at Accenture’s International Utilities and Energy Conference 2025, whether it was artificial intelligence, nuclear energy or data centers, attendees viewed each one in terms of whether it would help or hinder the over-arching goal of meeting soaring energy demand forecasts.
IUEC is an invitation-only event for senior executives across all energy sectors, with representation from heavy and light industry also. At the Conrad Hotel in Washington, D.C., there was much talk about how to deliver reliable and clean electricity to customers who are concerned about rising costs of electricity as well as rising costs in almost everything else.
Scott Tinkler, Global Utilities Industry lead, Accenture, identified what he called a “trilemma” of energy affordability, reliability and sustainability.
“Reinvention is no longer optional,” Tinkler said during an opening plenary session at IUEC. He added that global electricity demand has exceeded 4% for the first time since the 2000s.
This demand growth is driven by data centers and the artificial intelligence industry.
To address this trilemma, Calvin Butler, CEO of Exelon Corp. as well as a vice chair at the Edison Electric Institute (EEI), said his utility is setting aside $38 billion over the next 10 years for power grid improvements.
“Our customers have very different needs today than they did yesterday, and they have different expectations of us too,” Butler said. “Our customers need to be on this journey with us.”
The Challenge of Load Growth
Levi Patterson, director of Energy, Science and AI Infrastructure Policy at NVIDIA, took an optimistic view of the large growth forecast for energy demand.
“When I started my career, I was a nuclear engineer in the world of the Nuclear Renaissance that never really happened. If we had had this demand growth that we are seeing right now, maybe more would have happened. This demand surge could
An aerial View of Exelon building with parking lot and Baltimore Harbor behind it in the United States
allow us to bring some cool new technologies to market faster than we ordinarily would have,” Patterson said.
Butler agreed with demand being a powerful driver for needed change, saying there was 16 GW of anticipated new load growth in Exelon’s home state of Illinois alone. He added to his prepared remarks in a one-on-one interview with T&D World afterward.
“This is the first time we’ve experienced this level of demand, probably since the ‘60s. You look at the advent of air conditioning, right? I mean, we’re talking that long. So, this demand curve forces us to look at things differently, but it is also driving new technologies,” Butler told T&D World.
Of his work at EEI, Butler said he would like to foster greater collaboration among energy stakeholders to help build the infrastructure upgrades and retrofits needed to address all the demands on the energy sector.
“Collaboration is going to be the only way we achieve our goals, where the federal government steps in and removes barriers to building new generation. The government also understands that these regional authorities need to free up pipeline to get new projects going. I mean, it takes us almost 6 to 7 years to do siting to build new transmission lines. We are not going to achieve our goal of meeting this energy dominance or energy security with that type of regulation bogging down the system,” Butler said.
Speakers also frequently mentioned the human element in solving these issues. Maryland Gov. Wes Moore took the stage to say the economy needs electricity, and that the electricity industry needs the best people it can find to keep the economy growing.
“I knew that I could sum up what we needed to do in the State of Maryland in one word, and that was growth. We needed to make sure that our economy was growing. We needed to make sure that our economy was more competitive, and we needed to make sure that that growth was gonna be inclusive growth, And the thing that I always felt, and why this conversation around utilities and power became so important, was something had to power the growth. Something had to be the engine behind what we were getting going,” Moore said.
Moore went on to say that diversity, equity and inclusion initiatives are a solid path to elevating more people to do the kind of skilled work the power grid requires. I asked Butler, who introduced Moore, if he agreed with this approach.
“Yes. I think the industry has done a wonderful job in making itself a place where people can have family sustaining careers. We’ve worked with labor in tandem to ensure that we have talent coming in through the pipeline. Butler said. “I believe what makes Exelon as strong as we are is that we represent the communities that we serve. And when you look at us, we have the number one most reliable utility in the nation in ComEd, number three, most reliable utility in the nation, Pepco Holdings. Number four, most reliable utility in the nation in BGE and number eight in PECO to have four out of the top eight.”
Data Centers
There were entire panels devoted to the issue of demand from data centers. In its recent studies, Accenture found power consumption by data centers could surge to over 7% of total US electricity by 2028 and increase to 16-23% by 2033. Further,
Accenture’s report, “Powering the future of US data centers,” released in March 2025, says that renewable sources alone will not be enough to meet this demand and other energy supply options like nuclear and natural gas must be incorporated into the generation mix.
David Velazquez, president and CEO of PECO, an Exelon utility, said the growth could be called an “explosion.”
“How do we meet demand at speed? If you’re planning a data center, you’ll need to know what the sites are. We talk to hyperscalaers and big customers about this. It’s a complex problem to solve because of the scale of these hyperscalers,” he said. “Our largest customers used to be refineries, but now we are talking about hyperscalers that demand gigawatts of energy. Fortunately they don’t come online at full scale. They ramp up.”
James Mazurek, managing director — Accenture Strategy, Utilities, said Accenture looked at the needs of data centers and hyperscalers to determine what their drivers are. Electricity supply, labor availability, siting, GPU availability, maintenance and property taxes are all important considerations.
“The wild card in all of this is when a state’s executive leader just declares we want to drive data center activity in our jurisdiction. That happened down in Tennessee a few months ago,” Mazurek said, adding that Virginia, Texas and Illinois are each major hotspots for data center growth and expansion.
Power Generation
Accenture’s research on load growth found that energy sources such as gas-fired power and nuclear power from small modular reactors will play a key role in the energy mix going forward.
“There’s an abundance of supply in Texas right now, and the same holds true in Illinois and some other jurisdictions as well. This gets back into natural gas again as well. Data centers generally require firm, dispatchable generation. Right? 24/7. Texas has an abundance of that,” he said, adding that most Texas operating as its own power grid is another benefit for hyperscalers.
Exelon President and CEO Calvin Butler and Maryland Gov. Wes Moore discuss energy affordability and reliability on stage at Accenture’s IUEC 2025.
Courtesy of the Maryland Governor’s Office.
States that were retiring coal plants, like New York for example, are also seeing crypto mining operations move in where the coal plant infrastructure was still in place — leading to massive new load being added in an area where a power generation asset once sat, Mazurek said.
Maria G. Korsnick, president and CEO of Nuclear Energy Institute (NEI), and Julie Kozeracki, director of Strategy for
ASPEN
ENGINEERING SOFTWARE
the U.S. Department of Energy Loan Programs Office, held a talk called “Nuclear’s New Groove,” where both women said the successful installation of two new nuclear units at Southern Co.’s Plant Vogtle represented breaking down a barrier to new nuclear power construction.
“There’s been a lot of interest and attention to SMRs, but as you heard the president say, we need the big ones too,” Kozeracki said. “The folks at Southern ran thru a wall for us and completed Vogtle 3 and 4 and now the Westinghouse AP1000 is up and running.”
As for the underestimates of project construction costs and timelines, Kozeracki said these were to be expected of the two first new nuclear units to be constructed in the U.S. in the last 30 years, and will not happen again.
“If you look at the lessons of Vogtle, a lot of these were cost overestimations, and many of those will not be repeated. A lot of analysis shows that a $14 billion project was never possible,” she said, adding that the Westinghouse bankruptcy during the design phase and the COVID restrictions were compounding factors.
“You can’t just not build something for 35, 40 years and then come right out of the gate and have it go completely fine. We hadn’t been doing it for years. We should see this as a story of American grit and perseverance,” Korsnick said. “We now have a plan and a proven design to go on.”
Increasing load growth forecasts will drive SMRs to be adopted in the US, Korsnick said.
OneLiner
Short circuit, relay coordination and breaker rating for transmission networks.
Power Flow
Full-featured power flow for transmission systems.
DistriView
Fault simulation, relay and fuse coordination, voltage drop, harmonic analysis, and reliability calculation for distribution networks.
Relay Database
Customizable database for relays and related equipment.
Line Database
Customizable database for overhead lines and underground cables with built-in electrical parameters calculation engine.
EDX Module
Customizable platform for collaborative OneLiner/Power Flow model building and database-driven model data management.
“The load growth forecast for the last 40 years has been kind of boring. To have a forecast like this is amazing but also challenging. If companies end up building SMRs, it will probably be a lot of SMRs,” she said.
Affordable Power
At an opening plenary session, Exelon CEO Butler said he sometimes gets in trouble for a quote of his saying that clean energy may need to take a backseat to providing cheaper energy for consumers.
“My CEOs say ‘But Calvin, we are committed to clean.’ I said, ‘Yes, but our customers need affordability right now and we have to meet them where they are at,”’ Butler told attendees from the stage.
In a later interview, I asked him to explain this in greater detail. He says Exelon utilities do try to deliver both affordability and sustainability in every jurisdiction, and the company’s constituent utilities are on paths to meeting their climate goals.
“Clean energy is a priority. When you look at our own path to clean, we are on track to be net zero business-driven emissions by 2050,” Butler said. “What I was referring to is that because of the inflationary times that we’re in, our customers are feeling that pain and they no longer lead with clean. They lead with affordability. So when I say it’s taking a back burner, it means that is not the first conversation we have. It’s ‘Calvin, how can you help me pay my bills?’”
In these times, utilities should also work to make sure customers understand what their electricity bills pay for, he said, adding that it is up to utilities to tell them.
“As difficult as it is for people to pay more, people don’t mind paying for what they feel they’re getting value for. You know, your iPhone, a lot of people get the latest model and it costs them more, but they see value in what those upgrades are. What we have to do better as an industry is articulate the value that we bring,” he said.
Wall of data centers and wires. Data center expansion is fueling
Empresas Públicas de Medellín, a Colombian utility, leverages technological advancements to enhance safety and efficiency.
By Diego Mauricio Tauta Rúa and Elizabeth Jaramillo Marín, EPM
The timely adoption and effective use of advanced technologies in vegetation lifecycle management for transmission and distribution lines offer significant benefits to utilities, helping them address challenges related to service quality, resource efficiency, infrastructure security and personnel safety. As electrical networks grow in complexity and demand for service reliability increases, emerging technologies play a crucial role in maintaining high standards of safety, sustainability and operational efficiency. Over the years, technological advancements have become essential for improving performance, reducing downtime and enhancing worker safety.
Empresas Públicas de Medellín (EPM), a Colombian utility company, is integrating innovative technologies into its vegetation
management (VM) processes. By leveraging satellite imagery for vegetation analysis and introducing Laser Obstacle Remover (LOR) technology to enhance trimming operations, EPM is actively addressing the evolving needs of modern VM.
Satellite Tools
Effective VM starts long before trimming operations. At EPM, strategic initiative-taking planning is a key priority to ensure the efficiency and success of VM efforts. One of the most impactful technological tools currently being evaluated is satellite imagery analysis, which has significantly improved vegetation monitoring and resource optimization.
Satellite imagery enables precise vegetation monitoring around transmission and distribution lines, providing accurate, up-todate data for decision-making. By leveraging detailed mapping, utilities can identify areas of concern and predict potential risks
Images courtesy of Empresas Públicas de Medellín (EPM).
and optimize operational resources across the entire vegetation management lifecycle. In addition, they can generate risk reports, integrating vegetation threat analysis with network vulnerability indicators (e.g., bare overhead lines, critical users and remote areas).
This data-driven approach allows to monitor vast areas quickly and efficiently, ensuring that VM shifts from a reactive to a proactive process. By using satellite imagery, EPM can minimize service disruptions caused by vegetation interference, optimizing costs and time in the process.
Past Evaluations, Current Advancements
In previous years, LiDAR + drone solutions were tested in EPM’s VM strategy, as was discussed in an article, “Technology Advances a Tropical Country’s VM,” in the 2021 T&D World Vegetation Management Supplement. While the technology
Currently, traditional vegetation monitoring relies on manual field inspections, which are time-consuming, costly and limited in scope. By integrating satellite imagery, EPM aims to significantly improve inspection efficiency and accuracy, allowing for real-time vegetation health assessments over large areas. This results in reduced inspection time compared to pedestrian-based monitoring and more precise and strategic pruning activities, minimizing service interruptions.
Pilot Project and Beyond
In Q2 2023, EPM collaborated with an analytics company to conduct a pilot project in one of the most critical circuits in the west region of the Antioquia department. Within just two months, a comprehensive encroachment risk report was generated, categorizing risks from low to high. Field validations confirmed an important level of accuracy.
Additional benefits included assessing the phytosanitary condition of surrounding trees, enabling proactive measures to prevent tree falls and identifying GIS data inconsistencies, a common challenge in extensive network systems.
The next phase involves expanding implementation to a larger area (thousands of kilometers) to gather performance insights and define the optimal integration of this technology into EPM’s operational processes.
Laser Obstacle Remover (LOR)
In 2024, EPM introduced Laser Obstacle Remover (LOR) technology for vegetation management. LOR uses a precision laser beam to remotely trim vegetation, particularly tree branches that pose a risk to power lines. Traditional pruning methods often require workers to climb trees or operate near live power lines, exposing them to safety hazards. LOR technology eliminates these risks by enabling remote-controlled trimming.
EPM adopted a methodical approach to LOR implementation, which included technological surveillance and industry research, Proof of Concept (PoC) testing to validate effectiveness
A validation process conducted at selected sites confirmed the accuracy of vegetation management results.
An analysis of GIS data highlights key findings about the quality and accuracy of geographic information.
This shows a close-up of a branch being trimmed using the Laser Obstacle Remover technology.
Courtesy of Empresas Públicas de Medellín (EPM).
and acquisition and employee training for safe and efficient deployment.
The results have been highly beneficial, offering improvements in:
• Tree Health: LOR enables precise and controlled trimming, avoiding excessive cutting that can harm trees. Unlike traditional pruning, which can weaken vegetation, LOR targets only specific branches, preserving tree structure and reducing environmental impact. Additionally, as this technology does not require tree climbing, it minimizes potential physical damage to trees.
• Personnel Safety: Safety is a primary concern in vegetation management, especially near electrical infrastructure. Traditional methods expose workers to electrocution risks, falls, and other hazards. With LOR technology, trimming is performed remotely, eliminating direct interaction with live wires. Work at height is reduced, significantly lowering the risk of injuries, and overall work conditions are safer, ensuring better protection for field crews.
• Operational Efficiency: LOR increases efficiency and speed in vegetation management by reducing manual labor requirements and operational delays. It also enhances precision, ensuring only necessary branches are removed, and minimizes service interruptions, improving reliability. This technology is especially beneficial in hard-to-reach areas, where traditional trimming methods are difficult or costly. Remote-controlled laser trimming enhances accessibility, reduces downtime and optimizes resources.
• Cost Savings: By decreasing manual labor and specialized equipment needs, LOR technology could offer significant cost savings. The reduced maintenance requirements further lower operational expenses. Additionally, fewer service disruptions translate into fewer customer complaints and improved service continuity.
Continuing Technological Integration
Looking ahead, EPM is committed to continuing the development of its technological management process for LOR. The company plans to focus on adapting internal processes and integrating human capital to fully leverage this new technology’s potential. EPM recognizes that the effective use of advanced technologies requires not only the right tools but also an empowered workforce capable of maximizing their potential.
As part of this ongoing development, proper training and process adaptation will be crucial in ensuring that field crews and managers can make the most of the new technology. By continuously investing in workforce development and embracing change, it can ensure that its vegetation management program remains at the forefront of innovation.
EPM’s long-term vision for technological integration also involves continuous collaboration with environmental authorities; this ensures that innovative technologies, especially LOR, are in line with environmental regulations and standards. EPM is committed to minimizing the environmental impact of its operations while ensuring that its technological solutions contribute to long-term sustainability. By maintaining an open dialogue with regulators, EPM can address concerns and adapt its practices to promote ecological balance.
A Pioneer in Latin America
EPM has taken on the role of a pioneer in the Latin American region by being one of the first utilities to integrate these technologies into its vegetation management processes. This leadership in technological innovation highlights EPM’s commitment to providing service while continuously improving its operational efficiency and safety standards.
By integrating LOR into its vegetation management practices, EPM has taken a major step forward in safety, sustainability and operational excellence.
Left: The Laser Obstacle Remover (LOR) equipment was used for remotely trimming vegetation. Aboce: A close-up view of the LOR control screen displays real-time information during vegetation trimming operations.
Images courtesy of Empresas Públicas de Medellín (EPM).
Through the combined use of satellite imagery for vegetation analysis and LOR technology for trimming, EPM has set a new standard in the region for utilities aiming to modernize and enhance their vegetation management processes. These technologies are not only helping to improve efficiency and safety but are also paving the way for a more sustainable, data-driven approach to vegetation management. By using these cuttingedge solutions, EPM is working to ensure that it can meet the evolving needs of its customers while minimizing service disruptions and reducing costs.
Modernizing VM
The adoption of satellite imagery and LOR technology represents a transformational shift in vegetation management. These innovations could significantly improve service quality by reducing vegetation-related disruptions; operational efficiency through proactive monitoring and precision trimming and worker safety by minimizing exposure to hazardous conditions.
EPM’s proactive approach provides valuable insights for global utilities, demonstrating how technological solutions can address long-standing challenges while ensuring safety and environmental responsibility.
The successful adoption of these technologies offers valuable insights for utilities around the world, demonstrating how new technological solutions can help address long-standing challenges in vegetation management while maintaining a focus
on safety and environmental responsibility. The lessons learned from EPM’s experience serve as a roadmap for other utilities aiming to modernize their processes, improve service reliability and adopt more efficient practices. EPM’s ongoing dedication to technology-driven improvements sets an excellent example for the future of vegetation management in Latin America.
DIEGO MAURICIO TAUTA
RÚA (diego.tauta@epm.com.co) is a team leader-technology management for Empresas Públicas de Medellín (EPM). He is an electrical engineer from the National University of Colombia, with more than 17 years of experience in the utilities infrastructure sector. He holds a master’s degree in electrical engineering and a master’s degree in technological innovation management. For more than seven years, he has led technological innovation management at EPM, driving advancements in the industry. In addition, he has been a university professor for more than nine years, specializing in research on innovation and technology management in the transmission and distribution (T&D) sector, with several publications on the topic.
ELIZABETH
JARAMILLO MARÍN (elizabeth.jaramillo@epm.com.co) is a technology management professional for EPM. She is an industrial engineer from the University of Antioquia in Colombia and holds a master’s degree in industrial engineering from the Polytechnic University of Turin in Italy. With more than 10 years of experience in technology management at EPM, she has developed a strong expertise in leading and implementing technological innovations to improve operational efficiency and service quality. Throughout her career, Elizabeth has focused on integrating advanced technologies into business processes, ensuring alignment with strategic goals and fostering continuous improvement in organizational performance.
OUR WUNPEECE TRANSMISSION SPACERS REDEFINE THE INDUSTRY STANDARD FOR UNDERGROUND POWER TRANSMISSION INSTALLATIONS. WITH PRECISION ENGINEERING AND UNMATCHED QUALITY,
Charging an EV at a residential home. Duke Energy Florida launched a fouryear Behavioral Managed EV Charging Program aimed at reducing peak grid load by encouraging EV owners to charge during off-peak hours.
Managing the EV Surge
How Duke Energy Florida is reducing peak demand through behavioral charging.
As electric vehicle (EV) ownership accelerates across the U.S., utilities face the critical challenge of managing the increased energy load. For Duke Energy Florida, which serves nearly 2 million customers in one of the country’s fastest-growing EV markets,
finding a sustainable way to manage this growth was essential. EV adoption rates in Florida are projected to continue rising, with Guidehouse Insights estimating EV registrations to surpass 3.6 million by 2032. Facing the reality of this rapid increase, Duke Energy Florida took
proactive steps to manage grid load while continuing to support its customers’ EV adoption journey.
In collaboration with Itron, the utility launched a four-year Behavioral Managed EV Charging Program aimed at reducing peak grid load by encouraging EV owners to charge during off-peak hours. This article outlines the program’s objectives, challenges and successes, offering insight into an effective approach for managing EV-driven load increases.
Addressing the Challenge
Florida’s transition to EVs is driven by both environmental goals and rising demand from consumers. According to Southern Alliance for Clean Energy (SACE), Florida’s cumulative EV sales reached 335,826 by June 2024, reflecting a 45% growth over the previous year. The surge in EV adoption presented Duke Energy Florida with a clear challenge:
Images courtesy of Itron
Installing a charging station for an EV. Florida’s transition to EVs is driven by both environmental goals and rising demand from consumers.
managing the growing load from residential EV charging on the low-voltage distribution grid while maintaining system reliability and customer satisfaction. To do this, the utility needed a program that would not only shift demand from peak to off-peak hours but also incentivize lasting behavior changes among EV owners.
In January 2022, Duke Energy Florida launched its Behavioral Managed EV Charging Program. The goal was straightforward but ambitious: incentivize customers to charge their EVs during off-peak hours, thus reducing peak demand and easing strain on the distribution grid. The program focused on three core objectives:
• Reducing System Peak Demand: Shifting the majority of residential EV charging to off-peak hours to
avoid costly grid expansions.
• Engaging Customers: Encouraging EV owners to actively participate in managing grid load through monetary incentives.
• Optimizing Grid Performance: Ensuring that load shifts are stable and sustained to avoid temporary
fixes and provide long-term reliability.
Implementing the Program
To implement the Behavioral Managed EV Charging Program, Duke Energy Florida needed a solution that would allow seamless integration with its existing
Duke Energy Florida serves nearly 2 million customers in one of the country’s fastest-growing EV markets.
grid infrastructure and cater to the behavioral nuances of residential EV users. The utility turned to Itron’s Grid Edge Distributed Energy Resource Management System (DERMS) — a solution built on Itron’s fifteen years of experience designing and scaling programs for utilities and their consumers. Duke Energy Florida uses the solution to manage everything from vehicle and customer enrollment to incentive tracking, charging session monitoring and reporting.
Itron’s Grid Edge DERMS is driven by Grid Edge Intelligence, a combination of advanced metering infrastructure (AMI) providing measured and verified grid awareness, precise load disaggregation which is crucial for distinguishing EV load from general household consumption, and EV telematics data which originates directly from the vehicle. It provides Duke Energy Florida with real-time monitoring and insights into EV charging sessions, making it possible for the utility to track charging patterns and manage
peak demand shifts effectively.
Itron’s Grid Edge DERMS also made it possible for Duke Energy Florida to offer its Off-Peak Charging Credit Program to all EV owners in its service area with a Level 2 charger. The program offers a $10 monthly bill credit as an incentive for EV owners who charge during specified off-peak hours. To give the participants some flexibility, the program permits onpeak charging up to twice per month without penalty.
Driving Impact: Program Success and Customer Response
Since its launch, Duke Energy Florida’s Behavioral Managed EV Charging Program has seen remarkable success in both enrollment and load-shifting outcomes. To date, over 3,000 vehicles have been enrolled, and these participants have collectively consumed more than 10 GWh of electricity through the program. Of this total charging usage, approximately 4% has taken place during peak demand
hours, reflecting a 96% reduction in onpeak EV charging among participants.
Customer response to the program has been overwhelmingly positive. By the end of 2022 and 2023, the program met its enrollment targets and demand remained so high that interested customers were placed on a waitlist. This response highlights not only customer enthusiasm for the initiative but also a widespread understanding of its benefits — both for
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An electric vehicle charges. EV adoption rates in Florida and elsewhere are projected to continue rising.
personal savings and for supporting a reliable, efficient energy system.
Keys to Successful Behavioral Managed Charging Programs
Duke Energy Florida’s Behavioral Managed EV Charging Program offers valuable lessons for utilities seeking to address the challenges posed by increased EV adoption:
• Engage Early and Often with Customers. By clearly communicating the goals, incentives and benefits, Duke Energy Florida ensured that participants understood their role in supporting grid reliability and saving on their monthly bills. Regular updates and transparent data reporting reinforced trust, which ultimately helped Duke Energy Florida achieve high levels of program retention and compliance.
• Flexibility is Key to Participation. Giving customers the option to charge on-peak a limited number of times each month was essential in maintaining engagement. This approach respects customers’ needs while steering them toward behavior that supports grid stability.
• Respond to Emergency Conditions. During critical hurricane conditions, program charging restrictions were lifted so participants could prepare for travel out of forecasted areas of impact to ensure their safety.
A Blueprint for the Future of EV Charging
With the program’s initial success, Duke
Energy Florida is exploring options to expand the off-peak charging incentives to accommodate future growth in EV ownership. Expanding the current program could ensure that a significant portion of this load remains off-peak, helping the utility maintain grid stability without extensive infrastructure upgrades.
Duke Energy Florida’s managed EV charging program provides a roadmap
for utilities nationwide facing similar challenges. As EV adoption continues to grow, behavioral managed charging programs represent a promising approach for ensuring grid stability, reducing peak demand and engaging customers as active participants in the energy ecosystem.
Christopher Clark
The Duke Energy line technician transitioned from a job on the railroad to a career in the line trade.
• Born in Longwood, Florida, and has a brother and a sister.
• Married to his wife, Jessica, for seven years. They have two children: Christopher Jr., 11, and Kinley, 8.
• Enjoys hunting, fishing, spending time with his family and cooking.
• Working on replacing a pad-mounted viper recloser due to damage to the existing equipment. His crew is also working on pole replacements and upgrading live front transformers to dead-front transformers.
Early Years
I was employed at the railroad and was looking for a long-term career. My friend, Chase Goldman, was an apprentice with Duke Energy, and he encouraged me to apply. I have no family within the trade. My first job with Duke Energy was as a groundman on the SL crew at the Jamestown Operations Center.
Day in the Life
As a line technician, my responsibilities are the safety of myself, my teammates and the public. I also help the line apprentices to progress so they will hopefully be one of my peers in the future. I also specialize in line construction and maintenance, overhead and underground facilities as well as troubleshooting and storm restoration.
Challenges and Rewards
The daily challenges with my job include adverse weather, long hours, work-life balance, continually changing specifications and work methods and the introduction of new and improved equipment. One of the rewards is passing on the trade to the next generation of line technicians. I also love to see the joy and relief our customers have when their power is restored after severe weather. Finally, I enjoy looking back at projects I have completed and take pride in the craftsmanship and quality of my work.
Safety Lesson
I have been an active member of the event-free committee since I first got employed by Duke Energy. I got a first-hand lesson on the importance of developing a safety culture as well as identifying hazards and implementing mitigating measures. I was able to see the importance of those lessons when we had an incident. A public vehicle struck a pole, which fell when we
“I would do it 100 percent all over again and recommend it to anyone who is considering it.”
were on-site. The primary conductor had been covered, and everyone was out of harm’s way. This reinforced the importance of being alert and always maintaining situational awareness to lessen the effects of a potentially dangerous situation.
Memorable Storm
While I was restoring power following Hurricane Beryl, the scope of work was constantly changing. We did everything from picking up back lot wire to working out four-way junction poles. It was extremely hot and humid, which made the jobs even more interesting. The trip lasted 12 days.
Tools and Technology
Most of the battery-powered tools are great for helping with ergonomics and extending my career. As far as new technologies go, there is always a new piece of equipment that is better than the one before. The new tools and equipment improve safety and productivity.
Plans for the Future
I would do it 100 percent all over again and recommend it to anyone who is considering it. The career is challenging and rewarding and allows me to provide for my family like no other career I am aware of.
Christopher Clark is a line technician at Duke Energy’s Jamestown Operations Center. Courtesy of Christopher Clark
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EPRI’s Climate READi Framework: Building Resilience in the Power Sector
As society’s reliance on electricity continues to grow, the power sector is assessing its current and future resilience against weather and climate-related hazards to ensure the reliable delivery of power to customers.
To assist the power sector in managing physical climate risks and developing adaptation strategies, EPRI launched the Climate Resilience and Adaptation Initiative (Climate READi) in April 2022. The Climate READi Framework , launched in May 2025, is the product of three years of collaboration and offers resources that support proactive and integrated planning for an evolving energy system and climate.
Introducing EPRI’s Climate READi Framework
The Climate READi Framework is a structured, data-driven, science-based approach to physical climate risk assessment and adaptation planning. It provides guidance and methods that companies can use to assess the impact of climate hazards on their assets and systems, and identify and prioritize adaptations that enhance resilience. Over the past three years, EPRI has collaborated with more than 40 electric companies and over 100 academic, consulting, financial institutions, national labs, regulators, and government agencies to develop this framework.
To facilitate access to Climate READi resources, EPRI developed the Climate READi Compass: Navigating Physical Climate Risk Assessments for the Power System, which provides a starting point for navigating the framework, including its 60+ deliverables.
Who Can Benefit from the Climate READi Framework?
The framework is designed for a variety of stakeholders within and adjacent to the electric power sector. Its application may vary by organization, and the framework provides technical guidance to help organizations tailor assessments accordingly.
• Power companies can use the framework to evaluate their resilience to physical climate risks and develop adaptation strategies. The company’s assessment activities will vary depending on the company’s corporate structure, existing planning processes, regulatory requirements, asset portfolio, and market participation.
• Regulators can use the framework to understand the full process for assessing physical climate risk and justifying climate resilience-related investments. The framework can also help regulators understand what information can be provided from a physical climate risk assessment and help them structure regulatory guidance in a way that is informed by science.
• Investors may be interested in understanding power companies’ efforts to address potential physical climate risks to their assets and systems.
• Consulting firms can support power companies in completing all stages of physical climate risk assessments, leveraging Climate READi guidance in their work with power companies or utilizing the framework as a thirdparty comparison against current assessment practices.
• U.S. and international standards organizations can incorporate Climate READi insights in ongoing efforts to catalog, identify, and potentially revise climate-related standards.
• Research organizations have played a significant role in the development of Climate READi materials through technical expertise. EPRI invites these organizations to continue participating in the Climate READi Affinity Group (CRAG). EPRI is also working on a resource that identifies core remaining research gap themes where progress is needed to advance future framework development and physical climate risk assessment in the electric power sector.
Preparing to Apply Climate READi
Companies can begin by assembling a team of internal subject matter experts to conduct the assessment, collect necessary data, and collaborate across the organization to address assessment needs. During the pre-assessment scoping stage, companies need to understand the scope of their physical climate assessments and can use past climate impacts and organizational priorities as a starting point for this exercise. Plus, they need to determine climate and power system data availability and modeling setup based on the accessibility of high-quality hazard data, asset information, and modeling linkages.
The Climate READi Compass also provides guidance on preparatory tasks, some of which may occur concurrently, and companies can take in advance of launching into their physical risk assessment journey.
Leveraging Climate READi to Build a Resilient Energy Future
The Climate READi Framework offers a critical tool for helping electric companies customize climate risk assessments tailored to their unique circumstances and supporting proactive planning to improve the safety, resilience, and security of energy delivery to customers.
Whether your organization is just starting its climate resilience journey or refining existing strategies, the Climate READi Framework can guide users through identifying vulnerable assets, integrating climate risk into system models, prioritizing investments, and selecting appropriate climate data sources.
LAURA FISCHER is principal team lead, Climate READi, at EPRI.
