T&D World - June 2024

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Gallery:

Sights from the 2024 IEEE PES T&D Conference and Expo

Exhibitors opened up their booths for visitors to browse and learn about the newest in technology, tools and services in the industry ... https://tdworld. com/55039300

Transformers:

DOE Finalizes Energy Efficiency Standards for Distribution Transformers

These standards are expected to protect existing domestic supply of core materials used in distribution transformers, increasing resiliency in the distribution transformer supply chain, while preserving steel union manufacturing jobs in Pennsylvania and Ohio.… https://tdworld. com/55016670

Energy Storage:

Salt River Project’s Largest Battery Now Operating

The SRP and NextEra Energy Resources energy storage facility is supporting Google operations with stored wind and solar power.… https://tdworld. com/55018421

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Unlocking the Power of Microgrids

hat is a Microgrid?” has been the top viewed article on www.microgrid knowledge.com for several years. Even speakers at the 2024 Microgrid Knowledge event in April were discussing the definition, noting that the Department of Energy now defines them as “a group of interconnected loads and distributed energy resources within clearly defined electrical boundaries that acts as a single controllable entity with respect to the grid. Microgrids can connect and disconnect from the grid to enable them to operate in both grid-connected or island mode.”

Microgrid Knowledge is in our family of energy media brands now; you may have seen some past articles from Microgrid Knowledge Managing Editor Rod Walton that we have shared. The article I mention, written by Microgrid Knowledge co-founder Elisa Wood, does a great job of simplifying the definition, saying that a microgrid is defined by three characteristics: it’s local, independent, and intelligent. It’s not just a group of solar panels on a building.

out by saying “I am the macro grid,” in addressing a mix of businesses, analysts, institutions, and government reps. “We need to be able to work together; come to us with your ideas,” Wright said. She mentioned that utilities are responsible for providing reliability but when you consider grid resilience, there are no standards related to resiliency. Utilities can struggle to provide resiliency, and rate cases with investments for resilience have been known to be thrown out because of costs, despite federal incentives and grants.

So actually valuing (or quantifying) resilience, and in turn quantifying the value of microgrids, has yet to be done on a higher level. She sees microgrid development and operation as a way to provide resilience. “There are always going to be events that make the grid go down,” Wright said.

I attended the Microgrid Knowledge event this April and learned very quickly that not only is it a deeper topic than I realized, but it’s also a close-knit community that is quickly expanding as microgrids gain more interest and acceptance — and are becoming a part of the solution to some bigger puzzles. Beyond the basic “what is” question, more questions arise for utilities and their relationships with them. What do microgrids mean for utilities? Are they the answers for climate change, security, and electrification? All the big issues for utilities?

Microgrid Knowledge is an event that hasn’t necessarily been all that well attended by utilities in the past because microgrids initially were mainly developed by non-utilities. According to an article by Lisa Cohn, universities were early adapters of microgrids. The U.S. military has been another early adopter. But truthfully, utilities have been involved with microgrids for years as well; and microgrids haven’t caused a utility death spiral.

ComEd built the Bronzeville community in 2018, which was a microgrid cluster designed to help utilities learn how to integrate microgrids with renewable energy and maximize efficiency with networked microgrids. T&D World covered it in its August 2019 cover story.

When you type in “microgrids” as a search term of T&D World’s website, 631 results come up. So, we have been writing about microgrids for a long time. But now, it seems, utilities are reaching across industries to figure out where else to go.

Laura Wright, VP of technical services at Baltimore Gas & Electric, an Exelon company, headlined the event along with representatives from the Department of Energy. She started

In fact, Superstorm Sandy proved to be a pivotal event in history for microgrids. When the Northeast lost power from the storm, Princeton University still had power because it was a microgrid operator.

Another hot topic was load growth, in particular from data centers. Utilities may turn to microgrids to help satisfy the electricity needs of powering the Internet, bitcoin, AI, and the HVAC to protect the sensitive equipment. A typical data center can range from 100 to 300 MW in electrical demand.

Whether owned by the utility or as a partnership with the end user, microgrids may be a way to alleviate the demand. This month T&D World covers microgrids from two different perspectives. On page 32, Snohomish PUD shares how it provided the design and engineering support for the Tulalip Tribes of Washington’s microgrid. PUD sees several benefits from the project including the potential creation of a larger resiliency zone with more microgrids, which could help more of the Tulalip community. It could also be a learning experience in helping PUD better understand how to integrate distributed energy resources onto its grid. This month we include another unique story for T&D World: Senior Editor Jeff Postelwait looks at how national labs are working with utilities to develop new algorithms to study and demonstrate the usefulness and functionality of microgrids. It’s a neat look behind the scenes and makes me proud of how innovative our U.S. labs are. If I were smarter, I would want to work at one.

As we learn more about the potential of microgrids, it becomes clear they hold one of the keys to addressing some of the most pressing challenges facing utilities today. They won’t ever replace the macrogrid, but the future of energy definitely looks increasingly decentralized, intelligent and more interconnected.

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SHOW INSIGHTS Learning Labs: No Regrets and ADMS

T&D World Live will feature two learning labs prior to the beginning of the conference, both held on Monday, Sept. 30 from 1 p.m. to 5 p.m. One will take an overview of transmission and distribution planning for the next couple of decades as an old grid faces new challenges. The second will discuss implementing ADMS and DERMS and the change management that comes with that. See below for further detail and be sure to look for registration for these pre-conference workshops at https://events.tdworld.com/2024.

No-Regrets Strategies for Transmission and Distribution

In the next 25 years the world of transmission and distribution will change drastically with some distribution circuits providing up to 10 times the electricity they do today. The grid will be stressed during winter nights as peak shifts to support transportation and winter heating. The grid tends to last 40 or more years, so half of the grid likely will not get upgraded by 2050, and the other half needs to be built to deal with the higher demand. Demand that could be two-way, exporting during the day, and importing at night. Most upgrades are 70 percent labor and 30 percent materials and equipment. Some materials (like wooden poles) may not be available others may have lead times measured in years. Changes to regulations may make building or upgrading new distribution or transmission more difficult and expensive, further slowing the pace of upgrades.

This session lead by Doug Houseman, a principal consultant with 1898 & Co. and long-time contributor to T&D World magazine, will look at some of the “no regrets” strategies and tactics that will lower the cost of upgrades and stretch scarce dollars to do more. Regulators are going to be tough negotiators on new capital investments as the cost of energy rises and will look to minimize cost increases for infrastructure. The session will deal with everything from poles and structures to construction standards, to real estate, software, communications, protection, and other no regrets moves that a utility can make to be ready for the future. After all no one wants to bring a new electric

Pre-conference workshops allow attendees to network before the start of the main event, while learning a focused topic.

vehicle home and find out they are not able to charge it at night.

ADMS/DERMS Implementation Strategy for Success

This learning lab will provide information that utilities need to plan, integrate, and commission an advanced distribution management system (ADMS), which includes functions for electrical optimization, outage management, DER Management, and other advanced applications. The workshop will cover the basic and advanced functionality of the latest ADMS (distribution management, outage management and distributed energy resources management); effective implementation stratefies and internal resource requirements and an ADMS business case.

Robert Uluski, executive consultant with ESTA International, will lead the lab, along with Dr. Stipe Fustar in IT integration and architecture for ESTA International. Instructors will present system integration guidelines and challenges, current technology offerings and implementation strategy. Attendees will come away with insights on the the importance of ADMS/DERMS for optimal distribution system efficiency, reliability, an overall performance. They will aslo discuss the challenges to utilities posed by increasing penetrations of Distributed Energy Resources (DERs) including distributed generators, energy storage, and controllable loads (including electric vehicles, programmable thermostats, etc.). Finally, the session will provide attendees with change management strategies for distribution system operators, engineers and other ADMS/DERMS stakeholders.

Energy Management’s New Frontier

Have you taken advantage of any of the financial and tax benefits offered by the Inflation Reduction Act (IRA) or the other government programs yet? I did, and like all government programs, read the fine print. There can be limiting caveats, but it was really worth the effort. The Wolf den had an antique HVAC (heating, ventilation, and air conditioning) system that required constant maintenance. The existing system probably could have been kept limping along for a few more years, but with all the stimulus paybacks that wasn’t logical.

It was time to replace that relic in my garage. Once the dust settled I was anxious to see how the new HVAC had affected the monthly energy bills. I’m happy to say they were noticeably lower. The HVAC hasn’t been operating for a full year yet, but it appears that overall the energy costs are down from the previous year by nearly 18%.

That’s a substantial savings and to me that “once-in-a-lifetime” economic inducement was worth it. It’s the economic push I needed to upgrade my aging HVAC. Others may decide to add solar panels, or perhaps buy that electric vehicle (EV). For now the HVAC was enough, but it pays to study the offerings.

Old Infrastructure

some cases months to upgrading their electric service. A new EV owner is not going to be a happy with any delay that keeps them from charging their EV at home.

There are, however, some digital technological applications that address these load issues. They range from smart plugs to smart appliances that are controlled by smartphone apps, but they usually work by turning on/off circuits, which is not good for motor driven appliances.

Smarter Energy Management

That’s why a demonstration project funded by DOE is creating such a stir within the residential customer-base. Last year the National Renewable Energy Laboratory (NREL) announced their two year collaboration with SPAN had been successfully completed. The goal of the project was to develop a smart electrical panel-based home energy management system (HEMS). The team reported they had integrated NREL’s “foresee” technology into SPAN’s smart electrical panel. Its field testing was successful, and the technology is ready for market.

The IRA is getting lots of attention because homeowners are an important element in decarbonization. Speeding up the replacement of HVACs, adding solar-plus storage, and switching over to EVs pays big dividends in the climate change battle. There’s a lot of new load in this surge of residential electrification. It’s increasing the connected load, which ups the demand load.

These financial incentives will only exacerbate that. I recently read a study that said home service panels (i.e., circuit breaker panel) may have issues if adding more loads. The study went on to say that in the U.S. about 40% of the homes’ panels are rated about 100 amps. When you consider all of these new incentive additions, there are homeowners who are going to need upgrades to their service panels.

It’s a safe bet some of them will also have to get their local utility to upgrade the service connection to their homes. Unfortunately these upgrades can be expensive and are time consuming. Supply chain problems can add weeks and in

This type of enhanced electrical panel has the potential to be a game changer for the homeowner who is adding IRA qualifying devices to their electrical ecosystems. Several manufacturers such as Schneider Electric, Eaton, Koben, and SPAN among others offer these enhanced electrical panels. The features offered vary with manufacturer and models selected. They can operate autonomously or require some interaction with the homeowner. Like all digital technologies the homeowner needs to do their homework. Without going into too much detail, these digital systems take advantage of digital breakers, sensors, computer-control, and AI integrated sophisticated software. The advanced models can distinguish the homeowner’s devices and utilize their real-time data to track their consumption and forecast energy usage. NREL said these smart HEMS panels “can perform multi-objective optimization-based control of the household loads and behind-the-meter distributed energy resources.”

In other words, that watt-hungry EV charger we started out with can do its work when the home and the distribution grid have lower demand on them. By careful monitoring these autonomous wonders may prevent upgrading the home’s electrical service, which is a win/win for the homeowner and the utility. It’s not a cheap product, but reduced energy consumption has financial considerations, and these HEMS panels also qualify for IRA incentives!

Smart electric panel. Courtesy of SPAN.

International Competitive Bidding National Electric Transmission System of Chile.

Within the framework of the General Law of Electrical Services of Chile, in accordance with the provisions of the New Works Decree No. 58 of 2024 and the Expansion Works Decree No. 4 of 2024, both of the Ministry of Energy, and with aAs stated in Article No. 157 of the Regulation of Transmission Systems and Transmission Planning approved by Supreme Decree No. 37 of 2019 of the Ministry of Energy, the National Electrical Coordinator will carry out the call for International Public Bidding for the Award of the Construction and Execution of the following Expansion Works of the Transmission System:

final list of works will be confirmed during the bidding process.

To participate in this process, Interested Parties can acquire the Bidding Rules corresponding to the Call, which will be available during the first half of June, and request registration in the Participant Registry, in the manner that will be indicated in the aforementioned Rules. through the website: https://www.coordinador.cl/desarrollo/documentos/licitaciones/nuevas/2024-obras-nuevas-decreto-n58/. These Tender Rules will be available free of charge at the link to the Website.

Legal persons, both Chilean and foreign, may acquire the Bases and register in the Registry of Participants, who may participate individually or as part of a consortium or association, complying with the demands and requirements established in the General Law of Electrical Services and in the Bidding Rules.

National Electrical Coordinator

The Need For Speed

Expanding the power grid to keep up with the customer’s demand.

Remember that old expression, “May you live in interesting times?” Some say it’s a curse, while others say it’s a blessing. For a techie, it’s a saying that describes what’s taking place in the power delivery system. It covers the excitement those cutting-edge technologies generate as they appear. It describes the anticipation of managing challenges like moving from fossil fuel to clean-energy, and doing it swiftly.

According to the International Energy Agency’s Electricity 2024 report, “Global electricity demand is expected to grow at a faster rate over the next three years, with all the additional demand forecast to be covered by technologies that produce low-emissions electricity.” Those technologies are for the most part wind, solar and energy storage, which continue to increase as fossil fuels are replaced. That brings us to something that is making this a very interesting time: high-voltage direct current (HVDC) technology.

Since we can’t move the load centers closer to all of the anti-global warming generation that’s coming online, we need an efficient transmission system to move it to the load centers. There are several considerations making this challenge even more interesting. Renewable generation like wind farms is moving further from the consumer. In addition, they can be located onshore or offshore and their capacities have increased to the gigawatt (GW) levels. Oh yes, the consumers aren’t pleased with the aesthetics of old-school high-voltage transmission lines.

A New Era

That’s where HVDC technology shines with its voltage source converter (VSC) application. Developers and grid operators have selected VSC-based HVDC as the technology of choice

for speeding up bulk power transmission projects. VSC-based HVDC is designed to transmit enormous amounts of power extreme distances via overhead, underground, and submarine technologies, or a combination of them. Plus VSC-based converter stations are compact, requiring a smaller land area than other methods. This now-you-see-it, now-you-don’t approach of switching from overhead conductor to out-of-sight cable systems has proven to be an extremely valuable characteristic in congested urban areas.

An ideal example of this tactic is seen in the Champlain Hudson Power Express project. It uses a combination of both underground cables and submarine cables for its entire length, bringing 1,250 MW into New York City. VSC’s adaptability has proved to be the ideal method for bringing bulk power directly into a densely populated city landscape. These are areas where overhead transmission lines are not be welcomed. VSC-based HVDC’s invisible power line has the aesthetic appeal needed to overcome the “not-in-my-backyard” mind set. That is why it’s being utilized by so many utilities and grid operators worldwide.

Technology of Choice

According to the latest report from Research and Markets, the HVDC transmission market is projected to reach US$ 14.9 billion by 2028 up from US$ 11.4 billion in 2023. This is a CAGR (compound annual growth rate) of 5.4% for the 2023-2028 time frame. They went on to say, “The increasing number of VSC-based HVDC projects, the growing number of renewable energy projects globally, surging demand for reliable power supplies, and supportive government initiatives for power transmission are the major factors driving the market growth globally.”

In other words, VSC-based HVDC is becoming the global technology of choice, which is illustrated by the VSC-based HVDC activity in Europe these days. In the next decade there’s going to be a great deal of wind power capacity added by both onshore and offshore facilities to the European power grid and it needs to be accomplished quickly. The expectations are that somewhere between 80 GWs and 260 GWs are going to be added between 2030 and 2040. That’s a lot of electricity to move to market.

The European Union continues research on developing power hubs and a meshed HVDC grid needed to manage the increasing cross-border

VSC-based Viking HVDC link. Courtesy of Siemens Electric.

power capacities. There is a great deal of actual work taking place with PCI (projects of common interest), which are expected to bridge gaps in the European power system. They are transmission expansion projects like SuedOstLink, SuedLink, Ultranet, and A-Nord to name a few. These VSCbased HVDC links are expected to be the beginnings of multi-terminals leading to that meshed HVDC grid that will eventually be constructed.

Supply Chain Alarms

With all of the VSC-based HVDC projects underway there’s beginning to be a worldwide strain on the supply chain. It’s affecting everything associated with the VSC-based HVDC links from personnel to material. After all, factory space is a finite resource as is the workforce. As the numbers of these projects grow, what’s the impact it’s having on suppliers? It’s time for “Charging Ahead” to get some inside information from an expert.

If you remember, we talked with Hauke Jürgensen, senior vice president Grid Solutions at Siemens Energy back in the April 2023 edition of T&D World, which resulted in the article “Extending The Power Grid’s Boundaries With HVDC-VSC.” This would be a good time to update that discussion with Jürgensen’s latest insights on how this influx of VSC-HVDC projects are affecting suppliers and what is being done to meet the growing demand.

Jürgensen began the discussion saying, “The HVDC market has been expanding as never before. Siemens Energy has HVDC projects in every stage of development, from designing, manufacturing and into construction. At the same time, worldwide the number of proposals have been increasing at an unprecedented pace. This situation has been encouraging manufacturers to take a different approach to address this upswing. It’s literally requiring that outside-the-box thinking and it’s encouraging suppliers to consider crossing boundaries that surprise many within the industry.”

Jürgensen explained, “Meeting increased customer demand has suppliers suggesting customers replace customized specifications with functional specifications. Functional specifications will highlight the need for the standardization of HVDC equipment. The key element

CHARGING AHEAD

for interoperability is standardization, and that is necessary for an industry that has finite resources when it comes to factory space, equipment, skilled personal, etc. A broader supply base to meet the increasing demand for HVDC transmission links. Moving away from proprietary systems to open architecture increases supply chain resources and that speeds up everyone’s HVDC projects, which improves the resilience of the power grid.”

Jürgensen continued, “Interoperability is also an essential element for developing multi-terminal HVDC technology needed for a meshed HVDC grid. Another crucial element

B N O S

CHARGING AHEAD

is the HVDC-breaker. Recently Siemens Energy announced they signed a joint development agreement (JDA) with Mitsubishi Electric. We are cooperating with Mitsubishi Electric in the development of an HVDC-breaker. Siemens Energy and Mitsubishi Electric are committed to the development of a HVDC-breaker, which is a crucial element for the future meshed grids. We expect to have the HVDC-breaker tested and operational by 2027 or 2028.”

Jürgensen said, “The JDA HVDC-breaker marks the first time that two HVDC suppliers are working together to commonly develop solutions for multi-terminal and multi-vendor HVDC grids. By working together, Siemens Energy and Mitsubishi Electric are accelerating both the interoperability process and the future development of advanced grids in Europe and worldwide. There is still a lot of work to be accomplished, like the development and installation of meshed grids for example, but Siemens Energy and Mitsubishi Electric are committed to make that happen. It’s a race against time, but the energy transition of the power grid requires it.”

Novel Strategies

It’s all about expanding the power gird’s capacity and doing it quickly. That’s exactly what European transmission operators are doing. The transmission operators are faced with moving large blocks of offshore wind power from the North Sea inland to load centers to the south and they’re come up with a noteworthy approach. They have defined corridors or “super-

highways” as they have been called (see “Superhighways Are Supercharging the Transmission Grid” in the October 2023 T&D World issue for details).

A benefit of this effort has been moving suppliers toward standardization. As shown with the adoption of ±525 kilovolt (kV) as the standard voltage for these projects. With so many facilities being designed, suppliers are offering common equipment, which is avoiding customization and speeding up deliveries. It’s also cutting costs while giving equipment standardization a boost.

One example of this approach is the Target Grid. It’s the Dutch-German transmission operator, TenneT’s stratagem. Target Grid is basically a gameplan for a future grid able to quickly meet the growing demands for electricity. TenneT has implemented the power corridor concept for moving bulk energy from offshore to customers in the Netherlands and Germany. At last count, TenneT had a framework agreement with their partners for ten ±525 kV, 2.0 GW, VSC-based HVDC facilities and cable systems and there are more in the pipeline.

The steady advancement of VSC-based HVDC applications are taking the technology to its next level. The growing acceptance is building the framework for interoperability and multivendor projects, while laying the groundwork for advancing multi-terminal VSC-based networks to meshed grids. It’s happening faster than anyone anticipated. Yes, we’re living in a very interesting time to be part of the power delivery industry!

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EVERSOURCE CUTS CONNECTICUT CAPEX, CITING PURA CLIMATE

At odds with Connecticut leaders and regulators’ energy policies, Eversource Energy Inc. executives Joe Nolan and John Moreira are cutting $100 million from their 2024 capex budget in the state and plan to do the same each of the next four years.

Nolan, who is chairman, president and CEO of Eversource, and Moreira, the company’s CFO, outlined their plans after reporting first-quarter results. They took aim in their commentary at decisions by the Connecticut Public Utilities Regulatory Authority (PURA) that they say don’t give the utility a “secure and predictable” path to recover its investments.

“Regulatory decisions over the past few years are misaligned with the law and the state policy,” Nolan said on a May 2 conference call with analysts. “And without a secure and predictable cost recovery path, we cannot continue to put additional capital resources on the table.”

PURA has, under the leadership of Chair Marissa Gillett, in recent years sought to bring more performance-based considerations into its work with utilities. Backed by state legislation passed in 2020, the agency has sought to reform revenue mechanisms for energy providers to “more accurately reflect their performance in achieving financial and public policy outcomes that provide a public

benefit to ratepayers, and Connecticut as a whole.”

That push hasn’t landed well at Eversource and Avangrid, the parent of United Illuminating Co., both of which have been on the receiving end of rate decisions they didn’t like. Hence the decision to cut capex, which will not compromise safety investments but focus on reliability projects.

“We are expecting to reduce capital investment in Connecticut by $500 million over the next five years until we see Connecticut’s regulatory decisions come back into alignment with law and state policy,” Moreira said on the conference call. “Our decisions on the deployment of our valuable capital resources have to be based on our current experience with regulatory outcomes for utility investment.”

Nolan noted that the capex budget for Eversource as a whole isn’t being cut but that the company’s holdings in Massachusetts and New Hampshire will instead get larger shares. The Eversource team is planning to spend a total of $23.1 billion through 2028.

“We have ample opportunities for capital deployment on our system,” Nolan said. “We feel very, very good about that.”

TRYING TO SPEED UP POWER GRID PERMITS, DOE ISSUES FINAL TRANSMISSION RULE

The U.S. Department of Energy has released its finalized transmission permitting reform rule along with $331 million in funding to add new power grid capacity to the U.S. West.

The aim is to streamline the permitting process for new transmission lines and invest money in power grid build-out and upgrades while maintaining stringent environmental impact reviews, according to a DOE release.

New power transmission projects often take decades to come to fruition, and some are canceled due to how costly (in time and resources) the permitting process can be.

The DOE’s own transmission needs studies routinely show that more transmission capacity is needed now and in the future — particularly lines that reach across regions.

Issuing this rule will establish the Coordinated Interagency Transmission

Authorizations and Permits program, which the DOE says will help qualifying projects consolidate their reviews and permitting processes to a two-year schedule. The program will maintain the engagement of the various stakeholders who are affected by the construction, including Indigenous people, state governments, local communities and others. The CITAP will provide sustained integrity in environmental review and transparency in permitting.

If Nolan’s words and actions were a poke at Connecticut Gov. Ned Lamont to replace Gillett — which is how many in the Constitution State saw Thursday’s call as well as previous complaints — it didn’t work. The Connecticut Mirror later on May 2 reported that Lamont committed to naming Gillett to a second four-year term.

The $331 million investment, funded through the infrastructure law, will go toward a new power line from Idaho to Nevada. The administration is earmarking $30 billion toward power grid infrastructure and improvements. According to the DOE, transmission lines in the United States have been built at half the rate of the previous three decades, often due to permitting and financing challenges. —Jeff Postelwait

Eversource earned net profits of nearly $522 million in the first three months of this year on operating revenues of $3.33 billion. A year earlier, those numbers were $491 million and $3.80 billion, respectively. The company’s electric transmission business grew its earnings to $177 million from $155 million in early 2023 — and its natural gas distribution profits rose by a similar amount — but earnings from electric distribution rose only slightly. Shares of Eversource (Ticker: ES) closed at $59.71 May 6, down slightly from the prior Friday and about 3% lower than the day before Nolan and his team reported earnings. They’ve risen about 5% over the past six months, growing the company’s market capitalization to roughly $21 billion.

—Geert de Lombaerde

Photo 312211567 © Jittawit Tachakanjanapong | Dreamstime.com

DOE RELEASES REPORT TO FOCUS ON DEPLOYMENT OF ADVANCED GRID SOLUTIONS

The U.S. Department of Energy has released its Pathways to Commercial Liftoff report focused on releasing the potential of advanced grid solutions. The report demonstrates the role of commercially available advanced grid solutions, such as advanced conductors, dynamic line rating, and energy storage, in increasing the existing grid’s capacity to support upwards of 20–100 GW peak demand growth.

The technologies are meant to improve grid reliability, resilience, and affordability. Near-term deployment of commercially available but underutilized advanced grid solutions are expected to strengthen the resilience of domestic energy systems and support the Biden-Harris Administration’s target of a net-zero emissions economy by 2050.

Key findings from the report include:

• Near-term solutions are available: Multiple advanced grid solutions are commercially available to help utilities and regulators respond to grid pressures in the near-term. These include advanced transmission (e.g., advanced conductors) and grid enhancing technologies (e.g., dynamic line rating, advanced power flow control, energy storage) as well as system automation and situational awareness solutions (e.g., advanced distribution management systems, distributed energy resource management systems).

These solutions can serve as a bridge while new grid infrastructure capacity continues to be built out long-term.

• The existing grid has untapped value: Deploying these technologies is expected to increase the capacity of the existing grid to support 20–100 GW of incremental peak demand when installed individually, while improving system reliability, resilience, and affordability. This capacity impact is on the order of magnitude of the 91 GW of peak demand growth that NERC projects for the next decade (as of December 2023).

• Solutions are low cost and quick to deploy: Most of these solutions are less than a quarter of the cost of conventional alternatives and can be relatively quick to deploy since they make use of existing infrastructure.

• Liftoff within three to five years is possible: Liftoff will be implemented when utilities and regulators value and integrate advanced solutions as part of core grid investment, planning, and operations. Pursuing six to 12 large operational, no regrets deployments across a diverse set of utility contexts will help derisk adoption at scale and build repeatable operational and investment models.

These projects will leverage both public and private capital to de-risk efficient and equitable deployment and catalyze future private investment of advanced grid solutions.

DOE ANNOUNCES INITIAL LIST OF HIGH-PRIORITY AREAS FOR ACCELERATED TRANSMISSION EXPANSION

The U.S. Department of Energy (DOE) has released a preliminary list of 10 potential National Interest Electric Transmission Corridors (NIETCs) to accelerate the development of transmission projects in areas requiring an urgent expanded transmission.

DOE also announced minimum eligibility criteria for direct loans under the Transmission Facility Financing (TFF) program. The TFF program helps finance the development of transmission projects in designated NIETCs and is supported by President Biden’s Investing in America agenda.

Currently, DOE is looking for public input on both the preliminary list of potential NIETCs and the TFF program application and evaluation process. A NIETC designation offers critical federal financing and permitting tools for transmission development, including direct loans through the TFF program, public-private partnerships through the Transmission Facilitation Program, and Federal siting and permitting authority of the Federal Energy Regulatory Commission (FERC) in certain limited circumstances.

Developers and state and local siting authorities may also be able to leverage the environmental analysis conducted by DOE as part of the NIETC designation process to complete local siting and permitting processes, which are expected to accelerate siting and permitting for transmission projects in these targeted, high-priority areas.

DOE released final guidance on NIETC designation in December 2023 and initiated a four-phase process by inviting interested parties to suggest specific geographic areas where a NIETC designation may be helpful in advancing transmission to meet the regional need. DOE’s preliminary list of potential NIETCs included 10 narrow geographic areas covering nine of the regions identified by DOE’s 2023 National Transmission Needs Study.

The potential NIETCs:

• Include one or more potential transmission projects currently under development whose deployment could be accelerated by the tools unlocked by NIETC designation.

• Range in width from less than one mile to near 100 miles and in length from 12 to 780 miles.

• Often parallel existing rights of way such as state highways and high-voltage transmission lines.

• Have the potential to facilitate the integration of renewable energy resources such as wind and solar, including offshore wind generation in the Atlantic Ocean.

• Present the opportunity to increase transmission capacity between the Eastern and Western Interconnections--two otherwise largely disconnected grids.

• The preliminary list includes maps of each potential NIETC. The maps should be viewed as rough approximations. The geographic boundaries of any potential NIETC that continues in the designation process may ultimately differ from what is presented in the preliminary list. Today’s announcement is not designating any final NIETC.

The announcement starts Phase 2 of the NIETC designation process, including opening a 45-day window for public comments on the geographic boundaries and potential impacts of NIETC designation on environmental, community, and other resources.

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Following Phase 2, DOE will prioritize the potential NIETCs to move from the preliminary list to Phase 3, during which the agency will draft NIETC designation reports, conduct environmental reviews, proceed with government-to-government consultation with any impacted Tribal Nations as appropriate, and engage in robust public engagement.

DOE anticipates announcing the narrowed list of potential NIETCs and initiating Phase 3 in the fall of 2024. DOE is currently looking for public input on the scope of eligible projects and project financing requirements, including feedback from utilities and project developers interested in receiving direct loan support through the TFF program for a specific project in or near one of the potential NIETCs.

XCEL BOOKS $215M CHARGE TO BEGIN ACCOUNTING FOR TEXAS WILDFIRE DAMAGES

Xcel Energy Inc. executives say they have set aside $215 million to cover the losses they say they’re likely to incur as a result of the Smokehouse Creek Fire that burned more than 1 million across in Texas’ Panhandle and adjacent areas in late February and early March.

Shortly after the Smokehouse Creek blaze started, a law firm asked Xcel to preserve a fallen pole belonging to its Southwestern Public Service Co. unit.

Soon after, utility leaders said it was likely that that pole helped start the fire but denied that Xcel had been negligent in maintaining its equipment. (A Texas A&M Forest Service incident report says the failure of another SPS pole caused another fire that merged into the Smokehouse Creek blaze.) About 15 plaintiffs have since filed suit against SPS and other Xcel entities to be compensated for losses of their homes and farms.

In announcing the $215 million pre-tax to Xcel’s first-quarter earnings, Chairman, President and CEO Bob Frenzel and his team said that figure doesn’t include possible government fines, potential punitive damages or other damage claims (to infrastructure and trees, among other things) that the company may end up facing. They also noted that the $215 million is likely to be the floor of a range for which they can’t yet quantify the upper end

“I’ve been to the Panhandle and I’ve witnessed the impacted areas,”

Frenzel said on a conference call April 25. “I can speak for the entire Xcel Energy team when I say that we are saddened by the losses and we will stand with the Panhandle community as we recover, rebuild and renew that area as we have for over 100 years.”

Frenzel and CFO Brian Van Abel told analysts and investors last week that Xcel has $500 million of wildfire insurance coverage, adding that they can’t say when SPS might be able to recover the $215 million now set aside as well as possible future losses. Van Abel noted that Texas has no cap on noneconomic damages but that punitive damages are capped at two times economic damages plus up to $750,000 in noneconomic damages.

The company last month set up claims process for people who have incurred property or livestock loss in the Smokehouse Creek fire. Nearly 50 people have filed claims and Van Abel said “a couple” of cases have already been settled.

Shares of Xcel (Ticker: XEL) fell slightly on the earnings news and commentary April 25 and were changing hands around $54.30 midday April 26. They are down about 10% over the past six months—mostly because of a drop in the wake of the Texas wildfire news—which has shrunk its market capitalization to about $30 billion. —Geert De Lombaerde

Southwestern Public Service Co.’s market stretches from the Texas Panhandle into southeastern New Mexico. Xcel Energy

Planning for

the Extreme

Con Edison’s resilience plan is meant to prevent and mitigate outages, protect public safety, and reduce customer impacts and inconvenience.

By NELSON YIP, Con Edison, and JUDSEN BRUZGUL, ICF

Extreme weather events set some unwanted records in 2023: It was the hottest year on record and brought 20 named storms to the Atlantic Ocean — the most in a year since 1950. The Canadian wildfires affected life in New York City and other parts of the U.S., shutting down outdoor work and forcing the cancellation of recreational events.

Once the calendar turned, extreme winter storms plagued the country throughout January 2024. For example, high winds led to power outages for more than 500,000 East Coasters, raising concerns about how the electric grid would fare against more frequent, severe conditions. These extreme conditions will likely worsen, meaning utilities should take action on climate resilience planning to protect their equipment and customers.

Increasing severe weather is a frequent reminder of the need to storm harden grid assets. Photo by Con Edison.

Consolidated Edison Co. of New York, alongside ICF learned some best practices for climate resilience and put together a comprehensive climate change resiliency plan. These practices include prioritizing community engagement, considerations of equity in disadvantaged communities, and an emphasis on public safety and reliability. At its core, plans need to take specific action but remain flexible, given the rapidly changing environment. As climate change continues to disrupt the lives of customers by causing outages, now is the time for utilities to build robust resilience plans.

Rules and Funding

Major institutions — such as the U.S. military, U.S. Chamber of Commerce and the Vatican — agree climate change is real and an existential threat is prevalent. The U.S. federal government is taking action. The Securities and Exchange Commission has announced rules (which have been stayed by a court) requiring publicly traded companies to disclose climate-related information, including physical risks. Major climate legislation, like the Infrastructure Investment and Jobs Act, has become law, supporting billions of dollars of grid resilience investments.

In late 2023, New York state’s electric utilities filed climate resilience plans with the state, requesting up to US$8.7 billion over the next 20 years to improve the electric systems. Across the country, state and federal government regulators will need to approve hundreds of billions of dollars to equip utilities with the funds necessary to enact resilience actions over the next 20 years.

Engage the Community

To build a strong climate resilience plan, it is crucial to proactively engage with regulators and community stakeholders

throughout the process. This enables regulators to get on board early and have an appreciation for the utility’s strategic approach to this complex challenge. It creates a plan that is inclusive of the community and provides an opportunity for feedback from neighboring entities regarding their own adaptation goals. Con Edison incorporated community perspectives into its plan by creating a stakeholder working group to start a discussion. Such a group should consist of representatives from local municipalities, regulatory staff and community groups — especially those giving voice to disadvantaged communities. It also is important to include other infrastructure owners in the region.

Local stakeholders can help to identify robust community benefits, which are key to an inclusive resilience plan. These benefits can include pursuing funding for resilience hubs together — New York City is already prioritizing resilience hubs — partnering on facilities that support residents during outages, aligning on communicating issues to customers, and taking a collaborative approach to reducing carbon pollution and enhancing the community’s quality of life. The plan should focus on the benefits for all stakeholders.

Utilities’ climate resilience plans should reflect the realities of the communities they serve. Equity should be a key consideration. The impacts of climate change can affect some populations more than others, often making inequities in those areas worse. When utilities consider equity in their plans, they should focus on the distribution of climate impacts, the help that most vulnerable areas need, the factors that shape their vulnerability and how to offset those vulnerabilities.

A significant portion of Con Edison’s area is classified as disadvantaged

A Con Edison worker with insulated tools approaches a downed distribution pole on a Yonkers street after a storm in March 2018. Photo by Con Edison.

A media tour of a Con Edison control room. The utility says community engagement is an important part of its disaster readiness strategy. Photo by Con Edison.

communities that are especially vulnerable to the impacts of climate change. Extreme storms, heat waves and inland flooding leave people in these areas at more risk than those in other areas. For instance, residents of disadvantaged communities may have difficulty accessing transportation for safety. They also may face issues receiving health care if they are injured or become ill from a severe weather event. Con Edison will look to track the number of outages in disadvantaged communities and factor that data into future iterations of its resilience plan.

Utilities should identify which parts of their service area are most vulnerable to the impacts of climate change and consider additional resources or priorities for those areas. It is important to prioritize critical facilities like hospitals and transportation facilities, as they are vital safety hubs during extreme weather events. Keeping them online during critical periods should be a top goal for any climate change resilience plan.

Con Edison has also formed an internal environmental justice working group and released a corporate policy statement to apply an equity lens to its operations and programs. The company will apply these principles going forward as it learns from the effects investments may have on disadvantaged communities.

For robust resilience plans, utilities should seek partnerships with organizations that bring broader expertise on climate change, grid resilience, and modeling to help the utility think through key pillars of its strategy. For instance, Con Edison relied on ICF and Columbia University experts to translate the latest climate science into engineering needs for the company to make decisions, such as explaining pathway scenarios and temperature

Workers position equipment at a switchyard. Utilities should identify which parts of their service area are most vulnerable to the impacts of climate change and consider additional resources or priorities for those areas. Photo by Con Edison.

projections. This helped the company create its plan while bringing credibility that helped build trust with local stakeholders.

Be Transparent

Costs will always be among a community’s biggest concerns about changes in utility planning. Utilities should find the most costefficient solutions by using all the tools at their disposal to provide the best resilience value. For Con Edison, this is a multipronged strategy to address climate risks:

• Prevent by elevating sensitive equipment to avoid flood damage and taking other hardening measures

• Mitigate by reducing the impact through grid automation using devices like switches, autoloop circuits, reclosers and other measures

• Respond by using advanced metering infrastructure, storm response technology and other measures to enable faster restoration. Through stakeholder engagement, utilities can develop a conversation about the potential costs, wide range of solutions and cost of inaction. An unfortified grid will be more susceptible to outages. Fortifying infrastructure to prevent or shorten outages of critical facilities like hospitals,

shelters and nursing homes is a matter of public safety. This explanation may not be enough for lower-income communities where customers struggle to pay their bills. Utilities should continue to engage customers on their needs and work to raise awareness of applicable energy affordability programs. Options also exist to help make these necessary changes more

Damage to a Con Edison power pole on Staten Island’s Midland Beach area. Photo by Con Edison.

affordable for everyone. Utilities can offer flexible payment options to help customers who are struggling. For example, Con Edison’s approach includes payment assistance tools as well as programs focusing on customers in disadvantaged communities and energy-efficiency programs for eligible owners.

With the federal government investing in climate resilience, utilities have a great opportunity to fund measures that will make their systems more resilient to the impacts of climate change without their customers carrying the entire cost burden. This is the time for building robust climate resilience plans that are safe and transparent, and to communicate the value of the resilience investments while also emphasizing equity.

Maintain Flexibility

Climate resilience planning is not a one-time activity. Utilities will need to continue to evaluate changing hazard conditions and the effectiveness of their investments and actions, as well as evolving customer needs and technologies. Con Edison’s resilience framework is flexible and will be adaptable as conditions change.

A flexible resilience plan should include near-term strategies while also accounting for future programs based on projected climate conditions 10 years and 20 years into the future. Having a long-term outlook can reduce the cost of inaction, as resilience measures can be both proactive and adaptive to respond

Resilience planning should leave room to consider new climate science and lessons learned from previous efforts. Con Edison’s plan identifies solutions that protect against near-term climate change impacts while also leaving options open to protect against changes emerging down

As extreme weather events continue to happen at a higher rate and intensity, time and action are of the essence to implement quality resilience plans.

is director of strategic planning at Con Edison. Yip has 20 years of experience in utility operations, engineering, planning and energy policy. He is shaping Con Edison’s climate resiliency plans and clean energy strategy. As director of Strategic Planning, he advises senior leaders and their teams on building safe, reliable, clean and resilient infrastructure. He fosters innovative, sustainable and industry-leading solutions, while enabling effective decision-making and considering equity. Yip has a master’s degree in electrical engineering from Cornell University and

an MBA in Law & Business and Change Management from the New York University School of Business.

JUDSEN BRUZGUL, PHD, is Vice President of Climate Resilience at ICF. He partners with U.S. electric utilities to assess risks and build resilience to extreme weather and increasingly worsened climate change. He has provided expertise related to the technical, strategic, and policy challenges posed by climate risks for clients including Con Edison, San Diego Gas and Electric, U.S. Department of Energy, U.S. Department of Defense, New York City, and other major infrastructure owners - since 2000. Before joining ICF, he worked at the White House Council on Environmental Quality, developing and implementing resilience policy recommendations.

Defense-In-Depth Cybersecurity

This strategy combines technology with best practice security management to create protective layers that reduce the risk of attacks and intrusions.

By JUSTIN EISFELLER, Unitil Corp.

The rise of ransomware and malicious cyberattacks in the past decade has driven the criticality for all businesses to expand their cyber programs to provide better, layered defenses. According to a 2024 cyber threat report by SonicWall, ransomware attacks saw a 105% increase worldwide in 2023 — and there is no sign of slowing down. As attack vectors continuously evolve in complexity and quantity, utilities’ defenses must do the same.

Ransomware attacks on utilities have increased by 50% in the last two years, according to NextGov.com. Bad actors recognize energy is a core business product, and without it, people’s lives

are greatly impacted. As critical infrastructure with a target on them, utilities know every network, application and device must be configured with cybersecurity in mind.

In today’s tech-savvy workplace, the challenge lies in balancing new capabilities that improve productivity (for example, data sharing, interconnected systems and cloud computing) with mitigating the risks associated with those activities. To meet the modern demand, many organizations, including Unitil Corp., have adopted a defense-in-depth security program.

Defense-in-depth security combines technology components with best practice security management to create protective

Unitil Corp. is an electrical and natural gas utility providing services for customers in Maine, Massachusetts and New Hampshire. Photo by Unitil.

layers that reduce the risk of attacks and intrusions. There is an expansive amount of detail and effort that goes into a strong defense-in-depth strategy, but these efforts can be distilled into four main components: technology, people, monitoring and response, and program management for continuous improvement.

Technology Backbone

Strong technology is the backbone of a solid defense-in-depth strategy. Cybersecurity software and systems are built around protecting a utility’s critical assets: financial systems, operation systems, proprietary assets and confidential data, among others. A defense-in-depth strategy layers those protections on top of one another. Think of it like locking all the doors in your house; even if the bad guys get in, they will be trapped in the mudroom without a key into any other room in the house.

The layered protections safeguarding an organization’s critical assets can be broken down into five categories:

1. Perimeter protections

2. Network protections

3. Endpoint protections

4. Application protections

5. Data protections.

An immense amount of thought and intricacy goes into each of these layers, and organizations should ensure they are putting ample consideration into bolstering defenses and mitigating risk in each category.

The goal is to prevent an attack from happening, but if malicious activity does sneak through a utility’s defenses, layered protections and network segmentation help to ensure any impact is limited to the smallest element possible. As the core of any cybersecurity program, strong technology is a necessary investment.

The Human Aspect

Humans are and perhaps always will be the easiest attack vector for cybercriminals. In fact, human error is the main cause of 95% of security breaches. But, there is hope for the future; although employees often have seen cybersecurity as a hindrance to their job productivity, that mindset is shifting as cyberattacks become the subject of more headlines. With increased efforts to combat cyber threats, a wider spectrum of employees has developed a greater understanding of the fundamentals of cybersecurity. While some would have been more likely to resist such efforts five years ago, more employees now recognize they play a role in the success of their company’s cybersecurity program.

Organizations need to foster cultures where cybersecurity is at the forefront of daily operations. That means cultivating employee cyber knowledge and then testing that knowledge with drills. Beneficial strategies include cybersecurity awareness training, simulated phishes, and additional training and resources for high-risk employees.

For example, Unitil has implemented a rigorous training program that regularly tests the ability of its employees to spot

Unitil server room. Unitil has implemented a training program to test the ability of its employees to spot potential cybercrimes like phishing, which has become one of the most popular forms of attack Photo by Unitil.

A server room at Unitil. Network protections are an important safeguard for a cyber-secure organization. Photo by Unitil.

potential cybercrimes like phishing, which has become one of the most popular forms of attack and typically involves employees receiving emails or text messages with malware embedded in the message. Employees can be tricked into sharing credentials that could allow a hacker to invade the utility’s system. Therefore, as part of its monthly exercises, the utility uses mock phishing attempts to try to catch an unsuspecting employee off guard with the overall goal of ensuring they know what to look for to prevent an attack.

For high-risk employees, it is important to focus on education rather than punishment. Sometimes, however, intervention and restricted access are needed to alleviate risk.

Additionally, a strong cybersecurity culture needs execu -

Monitoring And Response

Cyber criminals do not sleep, so it is critical businesses have the ability to monitor their systems 24/7 to identify vulnerabilities, emerging attack vectors and areas for improvement.

Security operations centers (SOCs) can provide constant threat monitoring for organizations. Whether external or in-house, SOCs ingest everything from firewall data to endpoint data, combining advanced analytics and threat intelligence for immediate identification of suspicious activity along with the ability to take immediate actions. If the SOC sees malicious activity that has snuck through layers of defenses and started to proliferate, it can react and isolate the threat. SOCs also can craft vulnerability assessments and risk scores that provide organizations with situational awareness regarding their threat landscape.

If all else fails, utilities should be prepared to respond and isolate any damage to restore systems in an expeditious and organized fashion. Unitil has a Cyber Incident Response Plan it reviews and runs drills on every year with the help of external assistance, its cyber insurance vendor, and other internal stakeholders to ensure readiness. It is important to have additional resources available that could be called on to expand the response in the event of a cyber incident. The utility has even participated in drills with the National Guard and other utilities, which have additional trained cyber experts that can assist if needed.

New threats will always be lurking within or on the perimeter of a utility’s systems, so constant monitoring, threat intelligence gathering and response activities are a necessary part of daily operations.

Continuous Improvement

A good cybersecurity program is built on a foundation of continuous improvement — and that perpetual fine-tuning needs to be self-aware, strategic and built into the organization in order to be worthwhile. By constantly evaluating every aspect of processes and policies, organizations can identify opportunities for refinement and ensure they are doing what they set out to do.

There are several ways to accomplish this review. Utilities can leverage an external expert to assess their cybersecurity programs against industry benchmarks and identify areas of improvement or gap reports. From there, organizations can develop action plans to address these gaps on a prioritized basis. Penetration

Smart meters offer many benefits to customers and utilities with two-way communication, but from a cyber-attacker’s point of view, they represent a single point of failure. Photo by Unitil.

testing and simulated red-team cyber drills also present opportunities for improvement.

Businesses also can implement means to self-audit their cyber programs. Assessing company practices is critical, which is why Unitil has an external assessment performed annually to determine the effectiveness of its cybersecurity measures. The assessments force utilities to continuously work to strengthen their layers of protection.

Unitil has adopted the Center for Internet Security’s (CIS’s) compliance model, which is essentially an audit model that assesses how it is performing on a broad range of security controls. By providing evidence on its quality of execution, it achieves a higher level of assurance that is adhering to its cybersecurity requirements and goals. With cyberattacks against utilities a constant threat, Unitil envisions a day in the future when cyber programs at all utilities are audited by an external entity, much like audits for accounting and other business practices, to ensure protections are followed.

The Bottom Line

Another resource available to utilities to enhance security posture is the Cybersecurity and Infrastructure Security Agency (CISA), the federal government’s cyber defense agency. CISA can help organizations of all sizes to better prepare for and respond to cyberattacks while also lessening the impacts if they fall victim to an attack.

In its effort to raise awareness, CISA has launched the Shields Up campaign, which provides a comprehensive cybersecurity business practice guide. While companies may not meet 100% of the recommendations outlined, the guidance is a helpful self-assessment tool to pinpoint areas where improvements can be made to enhance online security.

CISA also encourages companies and others to voluntarily share information about cybersecurity threats to critical infrastructure. The reporting of any cyber-related incident can prompt warnings that may protect other companies from an attack.

Most companies cannot deploy every protection or security measure available, so consideration should be given to balancing a company’s risk tolerance and operational needs — creating a best-fit cyber protection plan.

A defense-in-depth cybersecurity program is about fortifying protection and driving improvement from every angle and at every level. Through an emphasis on systems, people, monitoring and policy assessment, a secure cybersecurity program safeguards an organization’s critical assets without overly burdening its productivity.

It is likely more sectors will be audited for their cyber programs in the near future, so utilities that have not already done so should prioritize a cyber program that will keep critical business operations running and ensure data is protected.

JUSTIN EISFELLER, (eisfeller@unitil.com) is chief technology officer and vice president of Information Technology at Unitil Corp. and is responsible for Unitil’s information technology infrastructure, software development, cybersecurity and software systems support. Eisfeller has over 30 years of professional experience in the utility industry and has been heavily involved in recent deployments of Unitil’s advanced metering infrastructure, meter data management system, customer information system, gas and electric dispatching systems and outage management system. Eisfeller holds an MBA degree from the University of New Hampshire, a BSEE and power option degree from Northeastern University, and holds an Information Technology Infrastructure Library Foundation certificate in IT service management.

A Unitil field worker using a mobile tablet. Unitil performs regular cyber threat assessments throughout the year. Photo by Unitil.

Tulalip Tribes Plans Microgrid for Resiliency

Snohomish PUD provides design and engineering support as the Tulalip Tribes of Washington plan its own microgrid, looking to create a resiliency zone in the long term.

By AARON SWANEY, Snohomish County Public Utility District

Located on Puget Sound in the northwest corner of the state of Washington, the Tulalip Tribes Reservation juts out into Port Susan and faces westward, toward Whidbey and Camano islands. With more than 15 miles (24 km) of coastline, it boasts 22,000 acres (8903 hectares) of rich natural resources, including tidelands, wetlands, forests and marine waters. For generations, elders of the Salish Sea tribe built beautiful cedar canoes by hand to ply the waters from Canada to Oregon and fish for abundant salmon.

In today’s world, the forests of towering old growth combined with the open seas means something entirely different. Regularly during the winter months, brazen winds curl off the Pacific Ocean and smash into the tribal land and surrounding communities, causing trees and limbs to come crashing down. That often means extended power outages.

In November 2022, most of the residents and businesses on the reservation, including critical infrastructure, lost power for multiple days after a significant windstorm pounded the region. During the outage, the main circuit board for one of the tribes’ diesel generators blew, making it unusable and plunging multiple buildings that provide critical community support into cold and darkness.

“That was a real eye-opener for us,” said Angel Cortez, Tulalip Tribes’ emergency management preparedness manager.

Powering Emergencies

Designed to look like a traditional longhouse, the Tulalip Tribes’ gathering hall is a magnificent structure that stretches out nearly the length of a football field and stands as tall as a three-story building, with vaulted ceilings and a spacious

Snohomish Public Utility District is leveraging knowledge it learned on its own microgrid to assist the Tulalip Tribes future phases of its own microgrid. Photo by Snohomish Public Utility District.

interior. It regularly houses hundreds of visitors and is designed to host communal ceremonies, from celebratory dances to funerals.

The Tulalip Tribes prides itself on being innovative. Built in 2019, the gathering hall was built to not only host large events and bring tribal members together but also be a place where the community could shelter during an emergency. The hall includes a giant, commercial-grade kitchen, full bathroom facilities with showers, meeting rooms, underground storage and more, making it ideal for housing many people for an extended period.

“The gathering hall plays a critical role in our emergency response for our community,” said Cortez. “It is situated close to other critical facilities, like our health clinic and learning academy, so that it can be that centralized place where we point people to.”

What is a Microgrid?

A microgrid is a collection of locally grouped electricity sources that can feed the main electrical grid or be disconnected to serve a specific location.

Part of Snohomish Public Utility District’s assistance to the Tulalip Tribes is helping to plan for the development of future phases of the microgrid. The possibility of a second phase could island not just the gathering hall but also a medical facility, an elementary school, the Boys & Girls Club and a wing of the Northwest Indian College.

The installation of a smart recloser could isolate the small area serving the Tulalipowned buildings from the main grid. The few buildings would be tied together through the existing electric distribution system, powered by solar, batteries and diesel generators, and could act as a resiliency zone during extended outages.

A possible third phase is truly dreaming big. Starting at the Tulalip administration building, located approximately 1.2 miles (1.9 km) from the gathering hall, a larger microgrid zone could be developed to create a huge swath of linked residential, commercial and industrial areas.

Once isolated by strategically located smart reclosers, the area would be powered by 6 MW to 10 MW of battery energy storage and 2 MW to 3 MW of solar power. The area includes 250 homes, a fire station, a data center and critical community buildings that could all operate under a cohesive microgrid.

Powering a building like the gathering hall through an outage becomes that much more important as the number of people sheltering there increases. For years, diesel generators have been the answer to keeping lights on for critical infrastructure. But

recently, microgrids have started to supplant diesel power as a cleaner, more reliable option.

Tulalip Tribes leadership did not have to look far to learn more about a successful microgrid. Snohomish County Public

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Utility District (PUD), which is the tribe’s electric provider, built its innovative Arlington microgrid in 2020. Made up of a 500-kW solar array, 1-MW/1.4-MWh Lithium-ion battery energy storage system and a pair of vehicle-to-grid electric vehicle chargers, the Arlington microgrid has given PUD engineers expertise on how microgrids work in the real world.

“I refer to our microgrid as a clean energy backup generator

with a day job,” said Scott Gibson, Snohomish PUD manager of battery storage and emerging technologies. “Day-to-day, it will be connected to the grid and help integrate renewable energy. But in an emergency, the microgrid will be able to keep PUD buildings on-site powered and available for our workers.”

The idea of building a microgrid on the tribe’s land truly began to take shape when a group of electrical engineering students from Washington State University approached the Tulalip Tribes and PUD about conducting a feasibility study on how microgrids could help the tribe’s gathering hall and administration building.

The yearlong study used a solar-plusbattery design and found a microgrid would increase the tribe’s resiliency and energy security, while also providing opportunities for younger generations to learn about clean, renewable energy.

“A project like this could help not only the Tulalip Tribe and the PUD, but the entire region,” said Steve Hinton, a project manager and conservation scientist with the Tulalip Tribes.

The PUD’s microgrid delpoys multiple modes of battery storage, including vehicle-to-grid electric vehicle charging. The Tulalip Tribes was recently awarded $2 million in funding from the Washington state Department of Commerce’s Clean Energy Fund 5 to build their own microgrid. Photo by Snohomish Public Utility District.

The Tulalip Tribes’ gathering hall is designed to look like a traditional longhouse. It regularly houses hundreds of visitors and is designed to host communal ceremonies, from celebratory dances to funerals. (Inset) Wooden post and lintel supporting a photovoltaic array. In an emergency, the microgrid will be able to keep PUD buildings on-site powered and available for workers. Photos by Snohomish Public Utility District.

Sharing Knowledge

Now is a great time for tribes across the U.S. to invest in clean energy projects. Through the Inflation Reduction Act, as much as US$14 billion in subsidies and incentives, some in the form of direct payments, are available for tribes to put toward building clean energy projects.

The Tulalip Tribes was recently awarded $2 million in funding from the Washington state Department of Commerce’s Clean Energy Fund 5 to build a microgrid that would help to keep the gathering hall and associated buildings powered during an emergency.

The Tulalip Tribes is also the lead applicant on a U.S. Department of Energy grant and was recently awarded $600,000 as part of the department’s Grid Resiliency and Innovation Partnerships program. Funds from the latter grant will go to the installation of smart reclosers and other communication equipment that enables a microgrid to connect and disconnect from the PUD’s main grid.

One of the stumbling blocks for tribes that receive clean energy funding is navigating how to interconnect these clean energy projects into the grid and secure agreements with local electric utilities like Snohomish PUD. That is where the PUD’s proactive help came in, including guidance and support in building projects and integrating tribal-owned distributed energy resources (DERs) onto the larger grid.

That was part of the motivation for the PUD when Tulalip Tribes first pitched the idea of building its own microgrid in 2018.

“We wanted to develop the expertise and know-how that could be passed on to future partners hoping to build their own systems,” Gibson said. “Tulalip has been a great partner throughout this process, and our ability to partner with them early will help everyone realize full benefits.”

The PUD provided design and engineering help as the Tulalip Tribes planned its own microgrid.

“The PUD has been fantastic in sharing their depth of experience and knowledge,” Hinton noted. “It truly feels like an equal partnership.”

With the help of the PUD, the Tulalip Tribes settled on a microgrid made up of a 100-kW rooftop solar array, 1-MW/2MWh Lithium-ion battery energy storage system and an existing 1.5-MW diesel generator. The plan is for the microgrid to be disconnected from the PUD’s grid to power the gathering hall and create an energy oasis during an extended power outage.

A Resiliency Zone

But what if the microgrid was just the first phase? The PUD’s assistance has resulted in not only a microgrid for the gathering hall and administration building but also the larger idea of an entire resiliency zone to aid more of the Tulalip community.

“If similar microgrids could be constructed at more of the tribe’s facilities, it could create a network of resilient microgrids that would operate independently from the grid and provide increased resiliency for even more people,” said Alex Chorey, PUD energy storage and emerging technologies engineer.

Building these types of microgrids could be a learning opportunity for the PUD, as well. Helping to develop a microgrid not operated by the utility but connected to its system would help the PUD to better understand how to best integrate complex DERs onto its grid.

The idea of protecting natural resources and partnering with others to share information is not new to the Tulalip Tribes.

“In our culture it is important to be good neighbors and help those around us,” Cortez said. “We want to help not only our community members but all of our neighbors. We’re all in this together.”

AARON SWANEY (ajswaney@snopud.com) is a lead communications specialist for Snohomish County PUD. Swaney is a 2001 graduate of the University of Washington. Before joining Snohomish PUD, he was a reporter and editor for The Daily Herald in Everett, Washington, for more than a decade.

A yearlong study used a solar-plus-battery design and found a microgrid would increase the tribe’s resiliency and energy security.

Map by Snohomish Public Utility District.

Layers of Protection

PG&E deploys a remotely operated controlled-burn system, next-gen drones, wireless remote grids and more to enable layers of protection.

By PAUL DOHERTY, Pacific Gas & Electric Co.

Pacific Gas & Electric Co. (PG&E) is deploying innovative and emerging technologies, including a remotely operated controlled-burn system, next-generation drones and wireless remote grids, building on the proven layers of protection that reduced wildfire risk from its equipment by 94%, based on established methodologies, to help keep its customers and hometowns safe.

“Our system has never been safer, and we continue to make it safer every day. We’re prepared with multiple layers of protection and innovative new technologies to mitigate catastrophic wildfires in our hometowns. We want a future where our customers don’t have to choose between safety and reliability — we want both and we are working every day to make that possible,” said Sumeet Singh, PG&E executive vice president and chief operating officer.

Neither Overhead, Nor Underground

With ground-level distribution systems (GLDS), power lines are neither suspended from utility poles nor buried underground. Instead, lines are placed inside protected and resilient conduits

that rest on the ground. PG&E is exploring moving overhead power lines to ground level to eliminate ignition risk and enhance grid resilience. GLDS packages electric cable in conduit in a specially molded tray, tied in with a basalt rebar, then sealed with a special geopolymer cement, placed at ground level and capped in thermoplastic.

PG&E reached a significant milestone as a half mile (0.8 km) of GLDS circuit was energized in November 2023 in San Mateo County, California, U.S., as the first-in-the-world installation and energization. The utility anticipates this innovative approach could provide comparable risk reduction to undergrounding.

Fighting Fire with Fire

PG&E is testing BurnBot as an alternative to traditional land management techniques (such as using herbicides or mowers) around its facilities to clear vegetation, explore potential environmental and safety benefits, and determine opportunities to scale. BurnBot offers a remotely operated, controlled-burn technology to manage landscapes and burn woody materials

PG&E conducted multiple BurnBot tests in varied terrain in 2023 and plans to expand its testing in additional settings in 2024. Photo by PG&E.

on-site to reduce environmental and safety issues associated with controlled burns.

PG&E conducted multiple BurnBot tests in varied terrain in 2023 and plans to expand its testing in additional settings in 2024.

Next-Gen Drones

Automated and beyond visual line-of-sight drone operations in collaboration with Skydio are helping to augment manually operated drone asset inspections and provide a fast, safe and effective solution for field validation of a range of sensor alerts.

PG&E first began using drones in detailed electric transmission infrastructure inspections in 2015, but significantly ramped up its usage by 2020, after finding drone-based inspections to be more efficient and productive.

In 2022, the utility began using unmanned aircraft systems (UAS) technology to perform gas pipeline leak surveys on 16 miles (26 km) of water crossings traditionally done by boat.

Then in 2023, working with Skydio, PG&E became the first utility in California to begin conducting fully remote drone operations for electric system inspections after receiving a waiver from the Federal Aviation Administration to operate drones beyond the visual line of sight for a variety of inspections, providing a threefold advantage of increased system, operator and community safety; reduced time and resources; and cost savings.

PG&E recently expanded its UAS applications beyond inspections, becoming the first utility in North America to string power

lines with drones, working with Infravision. The utility began using Infravision’s TX UAV stringing system to string power lines in 2022 and has used the system more than 20 times, largely to repair sections of its overhead electric distribution grid damaged by winter storms but also to proactively reconductor higher-voltage transmission lines.

The TX system can be deployed in areas and conditions where helicopters cannot fly, including for service restoration in difficult terrain during and after storms and for reconductoring projects in highly complex urban and suburban environments.

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Brad Koelling, PG&E Senior Manager, Grid Design, explains the ground-level distribution system, which packages cable in conduit in a specially molded tray. Photo by PG&E.

Wireless Remote Microgrids

In November 2023, leaders from PG&E, Pepperwood Foundation, BoxPower Inc., Sonoma Clean Power, Franklin Energy and the California Public Utilities Commission gathered with regional, state and federal stakeholders at Pepperwood Preserve in Sonoma County to commemorate the first fully renewable remote grid deployed in PG&E’s growing fleet of stand-alone power systems.

Throughout PG&E’s 70,000-sq-mile (181,299-sq km) service area, remote customers are served via long electric distribution lines that traverse high-risk fire areas. Replacing these distribution lines with a remote grid is an innovative option that can cost-effectively meet customer needs and reduce fire ignition risk.

The fully renewable remote grid at Pepperwood replaces 0.7 miles (1.1 km) of overhead distribution line, eliminating the associated wildfire risk. The remote grid at Pepperwood will be PG&E’s fifth operational remote grid since 2021.

Collectively, PG&E’s five remote grids enable 10 customers to continue receiving safe, reliable, affordable and low-carbon energy while removing approximately 5 miles (8 km) of overhead distribution electric lines at the grid edge in high fire-threat districts. The utility has identified many locations where remote grids may be the most effective way of reducing wildfire risk and improving electric reliability, with additional sites either in development or being assessed in Madera, Shasta and Tehama counties, among others.

PG&E plans to scale its remote grid fleet to dozens of systems over the next several years, leveraging New Sun Road’s Stellar

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Ground-level distribution systems (GLDS), power lines are neither suspended from utility poles nor buried underground. Instead, lines are placed inside protected and resilient conduits that rest on the ground. Photo by PG&E.

Microgrid OS as the remote monitoring and control platform. The Stellar platform enables the utility to monitor and control remote grids via satellite and cellular connectivity, with capabilities for remote performance management, safety diagnostics, alarms, reporting and automated refueling notifications. Remote grids also feature an integrated fire-suppression system to protect the hardware and facility.

Easy-Connect Backup Power

PG&E has successfully developed a first-of-its-kind personal backup power transfer meter device for customers that fully integrates into the utility’s existing electric SmartMeter system. The device provides customers with a safe, easy-to-use and more reliable solution for interconnecting backup power sources, such as portable generators, batteries and qualified electric vehicles, to power essential devices and appliances during a power outage.

The utility has installed more than 1,500 backup power transfer meters for customers in high-risk fire areas since 2022 and plans to install thousands more through 2025. PG&E demonstrated using the onboard generator of an all-electric Ford F-150 Lightning to power devices through the backup power transfer meter.

Detect a Fault, Cut Off Power

test of enhanced power line safety settings, which shuts power off

detect potential threats to the electric grid and rapidly reduce or shut off power to help mitigate wildfire ignitions.

PG&E’s enhanced power line safety settings (EPSS), which shut power off in one-tenth of a second or less when contact with a foreign object or a fault occurs on a power line, reduced ignitions by 68% in 2023 in the utility high-risk fire areas. Building on the operational mitigations of EPSS, PG&E is also deploying additional layers of operational mitigations, including new downed conductor and partial voltage detection technology, to

Downed conductor detection (DCD) technology improves PG&E’s ability to detect and isolate high-impedance faults — lower-current fault conditions that may not be mitigated reliably by EPSS — before an ignition occurs. The utility is engineering, programming and installing the DCD algorithm on equipment in high-risk fire areas.

Partial voltage detection capabilities use SmartMeters to alert PG&E’s control center when voltage conditions that could present an increased ignition risk are detected. This technology helps the utility to detect and locate wire-down conditions for lower-current fault conditions — which may not be mitigated reliably by EPSS — within minutes, so the line can be deenergized remotely from the control center for faster mitigation and to reduce the amount of time a line is energized while down.

A Moonshot for Detection

Detect and suppress a high-risk wildfire in 10 minutes or less. Pinpoint all fire ignitions across multiple states or countries from space within 60 seconds. These are the challenges for innovators of XPRIZE Wildfire, a four-year, US$11 million competition aimed at developing innovative technologies to improve the detection and suppression of destructive wildfires. As co-title sponsor, PG&E believes this competition will be a game changer.

PAUL DOHERTY ( paul.doherty@pge.com) is a principal communications representative at Pacific Gas & Electric Co. Doherty leads PG&E’s public relations strategy around innovation and emerging technologies including microgrids, battery energy storage, drones, artificial intelligence, data analytics, vehicle-grid-integration, virtual power plants, technology partnerships and R&D, which are all key to building a stronger, more resilient and more sustainable energy grid.

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in one-tenth of a second or less when contact with a foreign object or a fault occurs on a power line. Photo by PG&E.

PG&E is testing BurnBot as an alternative to traditional land management techniques (such as using herbicides or mowers) around its facilities to clear vegetation, explore potential environmental and safety benefits, and determine opportunities to scale. Photo by PG&E.

Coding Better Microgrids

In the pursuit of a self-healing grid, scientists, engineers and utilities work together on tying grid assets together in more efficient ways.

By JEFF POSTELWAIT, Managing Editor

Like the words alchemy, alkali, alcohol and algebra, the word algorithm has its roots in the Islamic Golden Age and the work of Muhammad ibn Musa al-Khwarizmi, an astronomer, geographer and mathematician who is known as the father of algebra — a word that means “completion” or “rejoining” in Arabic. Algorithm is thought to be the Latinization of al-Khwarizmi’s name.

Throughout history, algorithms were used to encrypt and decode secret messages, as well as to predict the movement of bodies in space. It wasn’t until the 19th century and Ada Lovelace and Charles Babbage’s proto computers and Alan Turing’s 20th century computers that algorithms took on a form we are more familiar with, thereby making the great leaps in computer science we have seen in our lifetimes possible.

For the power grid, computer scientists are devising ever more sophisticated algorithms. The National Renewable Energy Laboratory developed algorithms to process signals from distributed generation sources like rooftop solar and

wind turbines so their generation can be more predictable for grid operators. Researchers at Princeton’s Department of Electrical Engineering wrote algorithms to protect against botnet-style cyberattacks on the power grid from high-wattage, internet-enabled devices. There are further applications in load demand prediction, fault detection, power grid monitoring, outage restoration and, broadly, helping grid operators distill the ocean of data pouring in from the meters, sensors and other smart devices now being deployed across service territories.

There are also a host of applications for microgrids. A platform developed by Irvine, California-based Veritone employed decades of pricing, demand and solar power resource data to figure out the right size energy storage batteries to use for solar power systems in Texas’ ERCOT grid.

As a part of one of the Department of Energy’s Earthshot research programs for clean energy R&D, NREL and several National Laboratories are developing new algorithms to study long-term wind resource availability the hopes of lowering the

Sandia National Laboratories electrical engineers Rachid Darbali-Zamora, front, and Lee Raskin test out an algorithm on a hardware-in-the-loop set-up at the Distributed Energy Technologies Laboratory. Photo by Rebecca Gustaf, Sandia National Laboratory.

levelized cost of electricity for floating offshore wind power projects. Another Earthshot NREL is participating in is studying the problem of long-term degradation in thermal energy storage materials, which is a barrier to their use in long-duration energy storage projects.

R&D on what algorithms can do for microgrids — and therefore energy resilience and decarbonization — has matured to the point where it is leaving the laboratory and being put into use by utilities.

Writing New Libraries

At Sandia National Laboratory, located inside Kirtland Air Force Base in Albuquerque, New Mexico, researchers study more advanced algorithms for an array of purposes and industries. Alongside scientists from New Mexico State University, they create libraries of algorithms they hope could one day lead to a self-healing power grid.

Fog rises from an electrical substation in Albuquerque. Sandia computer scientists have created a computer algorithm to determine the best way to restore power to a grid after a disruption, such as a complete blackout caused by extreme weather.

Michael Ropp, the project lead, told T&D World this could mean for getting power restored automatically to critical locations such as government buildings, hospitals or grocery stores before utilities or grid operators could conduct damage reports or deploy workers for repairs.

“The technology set we’re working with here is primarily intended to improve resilience during severe events, at the distribution-system level. This technology is designed to automate the process of enabling the power system to self-assemble into a configuration that powers as many customers as possible, using whatever sources are available, over whatever paths are

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Photo by Craig Fitz, Sandia National Laboratory.

still intact, after the power system has suffered a major insult,” Ropp said via email.

These black sky technologies could be useful even under blue sky conditions, leading to greater efficiencies under any conditions.

“Basically, we are looking at two types of system element: Line relays, which sectionalize and reconfigure the system, and load relays, which control local loads. Our technology set aims to allow these elements to discern what’s going on with the power system using only the voltages and currents they measure themselves, without relying on data being sent over a high-speed, ‘real-time’ communications channel that a) is cost-prohibitive in many cases and b) often becomes unreliable under the types of contingencies we’re talking about here,” he said.

When grid operators are forced to use only local measurements, this creates certain technical challenges, he said. Selfhealing using only these data is necessarily slower than selfhealing with two-way, real-time communication. On the other hand, the reliance on local measurement is leading to self-healing systems that can be highly effective at making power grids more resilient and reliable at a modest cost.

A particular area of interest is microgrids. The technology developed at Sandia is meant to work with microgrids with distributed inverter-level resources at the distribution level that are operating in their off-grid mode.

“Let’s say that we have a microgrid of this type operating offgrid. A fault occurs in which we have a circuit shorted to ground somewhere. The technology we’ve developed allows the system first to isolate and locate the fault, then bring the rest of the system back online,” he said.

For power engineers, the techniques used will probably sound familiar — concepts like undervoltage and underfrequency load shedding, undervoltage-supervised overcurrent and segmented black start.

Researchers strove intentionally to set systems up so they can be used with only existing, widely used equipment without the need to install new hardware platforms or expensive communications

networks. Such systems can become unreliable in black sky conditions, and may introduce vulnerability to cyber attacks.

“If isolating the fault caused us to lose one of our generators, so that now we can’t carry as much load as we could before, we have a means for making the loads aware of this, so that we connect only the amount of load that the sources can handle,” he said.

Avoiding the Microgrid Loop

Because of the way electric distribution systems are designed in North America, system designers need to avoid forming closed loops when designing microgrids.

“The loop we’re talking about is a literal loop — a situation in which we’ve closed certain switches so that we have a closed, continuous circle of wire. If the system is designed to operate with closed loops like this, then that can actually be a good thing that significantly improves reliability,” he said.

Sandia’s research partners developed a way to allow the controller at each switch to determine, using only local measurements, when closing its switch would create a closed loop. The method relies on a statistical comparison of the frequencies seen on either side of the switch to be closed.

From Theory to Reality

These new algorithm libraries need at-scale testing before getting deployed on any customer-facing power grid. So, researchers are looking for partners to assist with the next step. Sandia has two manufacturers working with them.

“We are presently seeking follow-on funding to do some further technical development, solve some remaining challenges, and expand the applicability of this suite of techniques to more situations,” Ropp said.

Last year, T&D World talked to EPB, the municipal utility for Chattanooga, Tennessee, about a microgrid designed to keep their central city functions operational during a blackout. These included surveillance cameras, radio control centers, a fire station and other critical communications infrastructure used by the city.

The Red Sky/Red Mesa supercomputing platform at Sandia National Laboratory. Working together, the two supercomputers have a total speed of 500 teraflops, making them the 10th fastest computer in the world. Photo by Sandia National Laboratory.

Jim Glass, Manager of Smart Grid Operations for EPB, said his utility collects waveform data from some 1200 automated switches with fault-sensing capability to automatically classify power grid events, which helps them address outages, solve equipment problems and test functionality.

The advanced algorithms currently being written provide evidence to help industrial customers optimize their equipment and settings to avoid disruption in voltage drops, Glass said.

“For residential customers, we can address outage frequency and duration more precisely and identify issues that may lead to future outages,” Glass said.

The utility uses an application with Fault Location, Isolation and Service Restoration (FLISR) capability, which springs into action automatically.

“When a fault occurs, the automated switches closest to the fault will sense it and open. It will communicate with the switch downstream and tell it to open. When both switches are open, the fault becomes isolated to a small section of the circuit. Once faults are isolated through this mechanism, the system communicates to normally open switches at the back end of feeders to close, which restores service to the back end of the circuit. The entire process takes just seconds and is entirely automated by the smart grid,” he said.

An Idea Taking Flight

At Kirtland AFB, Sandia scientists worked with Emera Technologies on a microgrid demonstration project intended to show how DC microgrids could work seamlessly with AC electrical systems to provide power. The hybrid DC/AC system was a “grid of grids,” linking several microgrids together for greater safety and efficiency.

The purpose of the project was to demonstrate and deploy a load-serving DC microgrid where every node had co-located generation and storage with interconnection via power electronics, as well as to do this in a modular system that could be easily deployed to microgrids of many different designs, Sandia electrical engineer Jack Flicker said.

“This allows for freedom on how power is delivered to the load. This is essentially changing the power system, where every electron required by the load has to be delivered to that load over wires at every given point of time, to an energy system where we can supply the electronics whenever is convenient,” Flicker said.

Besides the design and construction of the microgrid, there was quite a bit of work done on modeling and determining how big all the assets need to be as well as making sure the system is stable in all sorts of conditions. This included a cyber threat analysis on the communications infrastructure, he said.

Designing New Grids

The project used a few different design concepts, he said, one of which is a DC microgrid. These deliver safety, simplicity and efficiency advantages. Another concept is what Flicker calls the hierarchical microgrid, where different assets can operate

independently or cooperatively as needed to increase resiliency and meet load demands.

“I like the term hierarchical microgrid, but ‘fractal’ is more commonly used,” he said. “The concept of a hierarchical microgrid is that you have various layers that can either operate independently or in a coordinated sense.”

Finally, another concept under exploration is the idea of modular power electronics blocks at each node which can integrate generation, storage, control, and the grid interface at each node.

“All of these concepts are demonstrated, but they are not all required. Each piece can be utilized without the others. For example, you can create a hierarchical microgrid with an AC system rather than a DC system and have all the benefits of that,” he said.

Glass said EPB is enhancing its energy mix by expanding the number of microgrids in the area, tying them together and designing them with islanding capacity if it is needed.

“However, they are not designed to automatically island because we use every opportunity available to us for distribution automation technology through the smart grid first,” Glass said. “We will only operate microgrids in island mode when there isn’t an alternate power source.”

Before EPB system operators initiate microgrid operations, they try to fully understand where problems are using locally available information so as not to compound any issues.

“First, we exhaust all available options through automated switches and manual system operator switching to restore as many customers as possible,” he said.

EPB’s microgrid plans focus on remote areas at the end of service lines because of lack of redundancy. In such cases, we will likely install energy storage in these locations to provide reliability for customers.

Technologies that network grid assets more efficiently are of great benefit to the community, he said. EPB’s combination of smart grid and fiber optic networking resulted in 55% fewer outage minutes and saved customers more than $26 million by avoiding spoilage, lost productivity and other power outage impacts.

Researchers are developing algorithms to process signals from distributed generation sources like rooftop solar and wind turbines so their generation can be more predictable for grid operators. Photo by Randy Montoya, Sandia National Laboratory.

Extend Asset Lifespan, Embrace Sustainability

Utilities can improve the use of their existing asset capacity by following an all-encompassing and predictive servicing approach.

Utilities face a confluence of challenges as they look to preserve grid reliability — rising costs, output capacity and a workforce shortage are just some of the forces at work — while adding new energy resources and modernizing their networks. In the U.S., the government is prioritizing grid resilience like never before. With 70% of the nation’s grid more than 25 years old, Congress is making historic investments through the Inflation Reduction Act (IRA) that will strengthen the transmission network to drive down energy costs, generate good-paying jobs and help to keep the lights on during extreme weather events.

The Department of Energy estimates that outages alone cost the U.S. economy $70 billion annually, and this is only set to worsen if the domestic power grid is not modernized and expanded.

Continued turbulence in the geopolitical environment — impacting energy security and ongoing inflationary pressures — is forcing utilities to rethink how they structure their spending. Rather than investing substantial sums in new power distribution equipment, utilities are taking a more preemptive and circular approach that includes extending the life cycle of their networks. Leveraging the assets utilities already have can help them to future-proof the grid against recessionary pressures,

while reducing operational expenses and preventing costly substation shutdowns.

Sustainable Business Model

It is not just about building bigger and better to resolve the issue of energy security and reliability. The lead time on commissioning new electrical equipment puts time constraints on the pressing need to update infrastructure. Plus, it also is not a sustainable business model. For example, consider the additional mining of iron ore and copper along with the carbon footprint to manufacture and deliver such equipment.

So, what value adds can U.S. utilities learn from their European counterparts? They are actively implementing more sustainable solutions by adopting the 3Rs: repair, refurbish and retrofit. For them, it makes economic and corporate sense to optimize assets — because the most sustainable and cost-effective solution is assessing existing equipment.

Smarter and well-planned investments improve distribution security. They also enable utilities to achieve much more with much less, while continuing to use the existing power grid infrastructure and simultaneously transitioning to a new one. Upgrading outdated components can reduce the cost of

operating equipment by one-third and extend its life cycle by as much as 30 years, as well as resulting in considerable energy savings for utilities.

By replacing older, non-digital circuit breakers with more intelligent breakers, linked up to an advanced monitoring system, substations can improve their energy capacity by up to 20% and reduce their operational costs by up to 30%.

Minimal Disruption

Another key benefit of a speedy retrofit is the lack of downtime during the upgrade. At a time when every minute of output

counts, taking a retrofit approach means minimal disruption that lasts mere hours rather than weeks.

For example, when one of Europe’s leading energy suppliers ENGIE was looking to safeguard and extend the safe operating life of its switchgear systems across five of its combined heat and power (CHP) plants in Belgium, it quickly became apparent a retrofit upgrade was the most far-reaching solution.

Its innovative CHP plants harness the waste heat created during electricity generation and convert it to usable power for the local infrastructure, so their continuous and safe operation during any improvement works is essential.

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The retrofit was carried out in three stages with customized solutions required for each of the switchgear cabinets, including replacing aging circuit breakers with more advanced, smarter Emax2 models as well as relay protection and energy metering. Photo by ABB.

Save Resources, Costs, Time

Likewise, as part of its efforts to achieve net-zero fossil carbon dioxide emissions, Swedish electricity supplier Mälarenergi has just upgraded its switchgear with retrofit solutions at its cogeneration plant, one of the largest in the country. Only renewable and recycled fuels (made up of waste from society and spills from the forestry industry) are used in this district heating plant, which produces 1800 GWh of heat and 700 GWh of electricity annually and provides heat to 98% of all properties in the locality.

The retrofit — carried out in three stages with customized solutions required for each of the switchgear cabinets, including replacing aging circuit breakers with more advanced, smarter Emax2 models as well as relay protection and energy metering — has resulted in operational benefits for the plant. Rolf Bäckström, maintenance engineer at Mälarenergi, said that by modernizing its electricity system, the utility can avoid unplanned downtime, maintain predictable delivery to customers, and increase safety for both personnel and equipment.

It also means most of the critical infrastructure has had its lifespan extended, avoiding the carbon footprint implications associated with manufacturing an entire new system, as well as additional transportation costs and inevitable emissions.

What is more, with regular maintenance and monitoring of the new components, the life of the plant’s switchgear can now be multiplied indefinitely without the need for replacement, which is tangibly maximizing the utility’s investment and reducing total cost of ownership.

In fact, 50% of electrical equipment like metal cabinets, steel plates and bus bars — products with high embedded carbon and material footprints — can be used perpetually without being replaced if outdated components such as circuit breakers, electrical switches, fuses and contactors are regularly monitored, maintained and upgraded.

Collaboration Pays Off

Additionally, two of Finland’s biggest hydropower plants, located in the Arctic Circle and operated by Kemijoki Oy, benefitted from a retrofit solution that upgraded its dated circuit breakers. The plants avoided having to replace the entire switchgear operation.

With an 11-MW output and powering over 10,000 family homes between them, the plants were running on their original SF6based HPA circuit breakers. Despite being technically competent, they were no longer in line with Kemijoki’s strict environmental diversification program.

Lack of available spare parts also was becoming an issue for breakers that had been in commission for around 30 years. Another consideration was the key part Kemijoki hydropower plays in the country’s energy security and production, meaning downtime had to be kept to a minimum.

A customized 12-kV version of the medium-voltage VD4G vacuum circuit breaker family was specified, which clears business critical short-circuit faults in tens of milliseconds, in a heavy-duty utility where even a brief blackout can result in severe output disruption, with devastating knock-on impacts on revenue and reputation. Again, this retrofit solution meant downtime took just a matter of hours, ensuring the power was kept on without any disruption.

Jarkko Virtanen, vice president of electrical and machinery technology at Kemijoki Oy, said that good operational preconditions at the river are a prerequisite for cost-effective hydropower production, and ABB Ltd. made it very easy for the utility with a plug and play model that saved valuable time, money and resources. He added that they also have a far more reliable operational procedure now, because it handles the currents much better.

The project also demonstrates the integral role a strong servicing collaboration can play in helping utilities to achieve

Swedish electricity supplier Mälarenergi has just upgraded its switchgear with retrofit solutions at its cogeneration plant, one of the largest in the country. Running a piece of critical equipment to the point of failure could cost up to 10 times more than investing in a program of regular maintenance to extend the life cycle and productivity of electrical assets and by replacing older, non-digital circuit breakers with more intelligent breakers, linked up to an advanced monitoring system, substations can improve their energy capacity by up to 20% and reduce their operational costs by up to 30%. Photo by ABB.

their sustainability goals, because Kemijoki Oy saw the value of bringing in an expert servicing partner to inspect, analyze and evaluate the health of its electrical equipment, before suggesting a bespoke solution.

Running a piece of critical equipment to the point of failure could cost up to 10 times more than investing in a program of regular maintenance to extend the life cycle and productivity of electrical assets, in addition to avoiding the environmental impact of buying new equipment.

Greater Flexibility

To operate in an ever-changing and volatile environment, utilities must develop effective resilience strategies, with greater system flexibility, delivered through digital and emerging technology. Electric grids need to become more robust and allow a quicker response to outages through better use of fault detection, isolation and restoration.

Digital circuit breakers can be integrated further with a combined energy and asset management cloud and edge-based solution (which calculates user-defined energy consumption metrics per piece or equipment) to give full remote system visibility via a single dashboard — and a more complete understanding of how to drive energy efficiencies, reduce capital costs and provide optimal grid efficiency.

In this way, utilities can now accurately measure the real-time status of their equipment, telling them a lot more about the setup they already have with minimal interference to operations. The system can quickly identify when any operating parameter is outside the proper range, from current to voltages and temperature to vibration, meaning they can address any issues before they become failures.

Utilities need to shift from traditional and often reactive crisis management to more proactive resiliency planning — preparing the grid ahead of time to prevent a crisis. This starts by improving the use of existing asset capacity through an all-encompassing and predictive servicing approach.

Improved Grid Resilience

By leveraging new technologies and retrofitting dated components with digital upgrades, utilities can achieve improved grid resilience with greater ease, speed and regularity, as well as helping to deliver performance improvements, investment optimization and new levels of sustainable efficiency.

The future will require even greater innovation and ingenuity to achieve much more with much less. But, at a time when the utility industry is being compelled to raise safety standards and take tangible action on climate change, the question is not how can utilities afford to prioritize retrofitting but rather how can they afford not to?

STUART THOMPSON is ABB Electrification Service division president and leads a $1 billion revenue business of more than 2500 global service professionals across 51 countries. Established as a stand-alone business area in 2022, Thompson was promoted to head up the new Electrification Service division, having held previous roles as global product group service leader for ABB Electrification and Electrification Distribution Solutions.

FACES OF THE FUTURE

BY AMY FISCHBACH, FIELD EDITOR

Melissa Dawe

Connect Atlantic Utility Services

Melissa Dawe, a fourth-year apprentice with Connect Atlantic Utility Services, re-insulates a 345 kV line.

• 4th Year Apprentice.

• Born and raised in Florence, Nova Scotia, Canada, and has two children: Ethan, 11, and Alexander, 8.

• Completed the Utility Line Work—Construction and Maintenance course at Nova Scotia Community College.

• Serves as a volunteer firefighter outside of work.

• Can’t live without lineman pliers, a knife and tape.

• Trained in both distribution and transmission, which has helped her to build her experience and shape her as a powerline technician.

Inspiration to Work in the Trade

I first observed the professionalism and skills of powerline workers during both routine and storm restoration work when I was a traffic controller. I did a lot of flagging for them during their daily work and on storms. I then noticed RaeLynn Hawco on Instagram, and she became such a big inspiration to me in this industry.

Getting Her Start

I had a big struggle to get a job in the power line industry after school. Many companies turned me down, saying they

couldn’t put me on a truck because it would cause too much tension in homes. It definitely hit hard sometimes, but I did not let it stop me. I never gave up trying. For my first job working for a utility, I worked as a cable line technician for a cable line company. I ran new fiber and did some underground cable work.

Joining an Apprenticeship Program

In January 2022, Tri-wire took me on for storm response and indentured me into the apprenticeship program so I could get started. I then joined my home IBEW 1928 Union and got myself on a hiring list. I connected with a representative, started to pay my non-working dues and as time went by, my name moved further up the list. Now I am on the next gen committee in our union. I started to get my name out there and applying everywhere. I was starting to lose a bit of hope that I would get on anywhere, but then one day, Connect Atlantic Utility Services called me and offered me a job to do my apprenticeship with them. My heart started racing with excitement. At that moment, my life changed. All I could think was, “finally I am going to do what I dream of doing.” I could not turn down the chance to work with them. It is such a great opportunity, and I get to stay in my home province. My company gave me a chance at being a powerline technician. I am forever grateful for the opportunity they have given me. They gave me a chance when no one else would.

Working in the Field

I am currently on a reno crew, so I do a lot of disconnects and reconnects for houses getting upgrades to their panels. Because I work for a contractor, I can be anywhere on any job depending on where they need people. When we are being trained on a project, we do tend to stay on those crews throughout our training so we can get the proper skill, knowledge and experience to do the job safely. My main responsibilities are upgrading and maintenance to the powerline infrastructure. I hope to get into make-ready projects and line rebuilds and be able to obtain my hours needed to be certified for rubber glove work here for live line.

Advice to Apprentices

Stay focused and don’t allow yourself to become complacent. Be patient and have a passion for the job. Take all the experience you can where you can, work hard and ask questions. My foreman told me there is no stupid question. You can ask a question that maybe someone else may be too nervous to ask. It’s a brotherhood and sisterhood here. They don’t set you up to fail.

Plans for the Future

I see myself becoming a journey line technician. I would like to be part of helping to train other lineworkers coming into the trade, and I see more women coming into the line work. I am going to work hard. With the passion I have for this industry, I know I can get the experience needed to help train new lineworkers 10 years from now.

Taking the Next Step in Your Utility Career

If you’re considering a consulting career after retirement, here’s what you should know.

By MIKE ZAPPONE, Tempest Utility Consulting

Utility professionals who are looking to work as consultants or trade allies after retiring should start planning now, according to several former executives who have made the transition successfully. They have opportunities in their current roles to get the training and credentials that will help position them for the future, and to network with other utility professionals to learn what to look for in potential partners and clients, including pitfalls to avoid.

According to recent data, ample post-retirement work oppor tunities are available. The U.S. Bureau of Labor Statistics reports that people aged 55 years old and over are expected to become a larger part of the workforce over the next decade, and the Center for Energy Workforce development says the utility industry will need to replace some 44,000 lineworkers, technicians, plant and field operators and engineers over the next five years. Consultants and contractors have been filling the gap. But retirees, in particu lar, bring a unique set of experiences and skills; they understand the utility culture and how the companies operate and are able to deliver immediate value.

Preparation is Key

For example, Anthony Hurley began working as a consultant in 2017, after retiring as vice president of operations for FirstEnergy’s Jersey Central Power & Light. He readied himself for a postretirement career by establishing a “60-month flight plan,” during which he obtained a number of professional certifications in the

Anthony Hurley presents at a monthly meeting of the ASIS International Austin Chapter, where he serves as chair person. in Kentucky.

Beyond education and training, utility professionals would benefit from networking, including with contractors they know,

Finding the Right Fit

Another priority is to identify clients and contractors who are a good fit, including in terms of operating style and values. In many cases, these turn out to be companies that have similar cultures to where the retiree previously worked, and contracting firms that are run just like their utility clients. A key test for these firms is determining whether they already work with retirees, and then reaching out to ask about their experiences.

Consultant Carlos Torres (at far right) speaks to points of contact for the lead agencies restoring power in Puerto Rico after Hurricane Maria in 2017.

Anthony Hurley presents at a recent meeting of the American Water Works Association.

At the same time, it’s important for future retirees to identify opportunities that fit the lifestyle they plan to pursue. Said Wright, “This was a passion of mine to do some other work I wanted to take on and do it at my own pace.”

Carlos Torres, who retired as vice president of emergency preparedness and business resilience from Consolidated Edison in 2017, saw consulting as a chance to expand his horizons and have a greater impact on the industry. He built on the reputation he had already established when the governor of Puerto Rico appointed him the overall incident commander

for the power restoration effort after Hurricane Maria hit the island. This followed the upfront work he and others had done to evaluate the hurricane’s impact on Puerto Rico’s electric system. Just prior to taking on that effort, he even participated in an initial industry conference call during his retirement party. Though challenging, that situation aligned with what Torres had hoped to accomplish: “Sharing your experiences and knowledge to help other companies is the exact formula I had when I decided to retire.”

Beware Potential Pitfalls

In transitioning to consulting, it’s critical that retirees define and stick to their operating standards, including understanding the value of their experience and being compensated appropriately. However, issues arise beyond compensation, such as working with clients and contractors who are upfront during negotiations, and are hiring the consultant for substantive work, and not just to use their resumes. Cautions Hurley, “Make sure their ethics are in the right place and, from a moral perspective, that you’re being assigned the job you were hired to do.”

In the case of contractors, one important watch-out is when the consultant or sub-contractor will be paid; some contracting firms wait until they receive payment from their utility clients.

•

•

According to current retirees, a good practice is to conduct due diligence on potential clients and contracting firms by searching for news coverage, lawsuits or financial issues (such as liens), and asking questions.

While pursuing a consulting career after retirement isn’t for everyone, Hurley quips that he could “only fish so much and I’m absolutely terrible at golf.” More than that, each of the utility consultants interviewed agreed that it is worthwhile work. For Torres, the opportunity to impart knowledge makes the critical difference because, “As a team, no one of us is as smart as all of us, and the happiness you get from being part of a team that accomplishes great things is very fulfilling.”

MIKE ZAPPONE is chief operations officer for Tempest Utility Consulting (TUC), which helps utilities efficiently manage key aspects of their operations, including project and safety programs, construction and field services and emergency storm support. TUC is part of the Tempest family of companies.

PARTING SHOT

Replacing a broken pole can be a labor-intensive process that can take up to 12 hours to complete. Following a recent nor’easter, Eversource crews worked across New Hampshire to replace 260 broken poles. The lineworkers teamed up with local contractors and leveraged new technology to expedite restoration.

Meet Jolene Cicci

West Penn Power

Jolene Cicci, a troubleshooter for West Penn Power, has 35 years of experience in the line trade.

• Born in Waynesburg, Pennsylvania, as the youngest of five children.

• Mom of two grown daughters, Jackie and Jill, and has four grandchildren: Caitlin, 25; Jacob, 24; Ashton, 16 and Kingston, 12. She also has three great-grandchildren, Mason, 5; Avarie, 1 and Zayden, seven months.

• Enjoys vintage and modern cars and attends car shows that raise money for a variety of different charities in Pittsburgh, Pennsylvania, and the surrounding areas.

• Only one in her family to work in the utility industry.

Early Years

I started in the utility industry on the coal-fired generation side of the business as a laborer at Hatfield’s Ferry Power Station. After a little over a year, I transferred into a lineworker position. Since then, I have remained in the line trade and worked as a journeyman lineworker and lead lineworker for many years.

Day in the Life

I am currently a line troubleshooter for West Penn Power, a FirstEnergy company. In this role, I respond to outages and trouble calls. I make the repairs myself, if possible, but if I need help, I request a crew and share all the information they need to get the job done. I work in a very busy shop, so most of my day is running trouble. We work 10-hour shifts, and the day goes by rather quickly.

Challenges and Rewards

The major rewards of my job are helping the customer with any issues they are facing and, as always, restoration of service. In the early years, being a female in a male-dominated field always presented challenges. For the most part, you had to prove yourself daily. I am fortunate to work in a line shop where I am considered a valuable employee.

Tools and Technology

I started in the work-harder-not-smarter generation, and the struggle was real. It was even a tougher job 35 years ago, and it was a different era when I came up through the ranks. There was no Buck Squeeze to make climbing poles safer, and no fall protection for tower work. We had old-school tools not the battery-operated tools like the presses and cutters that are used today. The introduction of these tools was a game changer for the longevity of lineworkers.

Safety Lesson

I was called to a pole fire on a three-phase line where the next pole had solid blades to disconnect the power. The pole had severe damage and was ready to fall over with the facilities still energized. I had responders and safety forces stand back far enough out of the zone to ensure their safety. I called dispatch to open the circuit at the substation and while they were in the process of doing that, the pole burned off in front of all of us and went phase- to-phase. It was a real wake-up call to all involved.

Memorable Storm

My most memorable storm moment was Superstorm Sandy in New Jersey where we were stationed for one month. The devastation was unimaginable, and I have been on many storms over my career.

Making a Difference

Right now, I am a speaker for my company at various levels about diversity, equity and inclusion for FirstEnergy. I have mentored young females in the Female Leaders in Energy (FLIE) program through the United States Energy Association in Washington, D.C. I was also a guest speaker at the APEC 2023 summit in Seattle, Washington, to speak about gender equality in the energy sector.

Plans for the Future

I would absolutely do it all over again. This work is so rewarding and has put in a financial situation that I could never have imagined as single mom in the early 1990s. For me, retirement will be in the near future. I hope to give back to the energy sector and mostly try to get more women involved in line work.

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Diana Smith

Email: dsmith@endeavorb2b.com

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Phone: 708-542-5648

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Evolution in New Meter Technology Brings Equity and Affordability While Empowering Customers

During my 30 years in the power industry, including as a state public service commissioner, five years as a FERC commissioner, president of NARUC, and chair of PG&E’s board, I’ve recognized the value and importance of data, and how the need for it has grown over those three decades with increasing stress on our grid from growing demand and a transition to a decarbonized energy system. While society has increasingly digitized — giving people data-driven tools that support making decisions that are better for themselves, their finances, and their health — the grid remains without any true sense of real-time performance or safety metrics.

The energy transition is accelerating globally in response to a warming planet. Beyond just adopting more renewable energy sources, however, there’s also a clear need to better monitor and manage the overall consumption of electricity and natural gas. In the age of increasing electrification we need more and better data to support customer-centric load flexibility. Whether capturing time-of-use data from the surging demand of new EV owners, understanding what the impact will be of heating electrification on both the electric and gas systems, or accessing real-time peak usage data to support load flexibility, timely and granular consumption data is more essential than ever. On the customer side, it’s also time to finally ensure that everyone is equitably empowered with timely information and insights to make more effective choices and have increased certainty about their utility use and what it’s costing them.

To enable improved demand management and more deeply engage utility customers as partners in a transformation to a cleaner, more efficient world, electric and gas utilities need timely access to granular consumption data. To that end, and to streamline operations, utilities have collectively invested billions of dollars in replacing traditional analog meters with automated meter reading (AMR) and advanced meter infrastructure (AMI) meters that transmit granular usage data directly to the utility. The scale of this upgrade has been enormous: According to the U.S. Energy Information Administration, U.S. electric utilities reached roughly 119 million AMI installations as of 2022, equal to about 72% of all electric meters (or 88% of residential customers). However, while we’ve seen remarkable progress with a broad array of consumer technology, utility meters simply haven’t advanced as quickly as the challenges confronting utilities. AMI and AMR cannot deliver the data we need in real time, nor can the tech deploy affordable solutions rapidly. In fact, although these installations have helped utilities reduce their operating costs and risks by eliminating the need for manual meter reading and

reducing the number of truck rolls required for service calls, the costs of meter upgrades (as well as subsequent maintenance of the network used to transmit meter data to the utility) have typically fallen on customers, contributing to higher rates and resulting monthly bills. While seeing a utility employee walking through one’s yard to the meter on the side of the house may be a thing of the past, the majority of customers today are comfortable with — and in fact are demanding — a much more interactive, digital and mobile experience with their utilities.

Unfortunately, meter technology has historically been stuck in an outdated framework where utilities sold essential services to “ratepayers” with a focus on one-way communications. Customer-facing benefits were not seen as missioncritical, particularly when compared with more-streamlined utility operations. As a result, despite efforts like Green Button and a growing focus from many utilities on rolling out new time-of-use rate structures, most consumers across the U.S. still lack basic access to timely consumption data that would help them make more informed decisions about their consumption.

The latest generation of smart meters — sometimes called AMI 2.0 — aims to solve some of the problems typically associated with the technology, particularly with regards to customer engagement and management of distributed energy resources (DERs). The problem is that they still often use proprietary elements in their communications networks that can effectively lock utilities into single-vendor ecosystems, and the new meters are adding a tremendous amount of computing power into each meter for the nominal goal of providing “grid-edge” analysis. And while some customers may potentially be able to access more timely data, utilities in many cases still won’t be able to access data across their territory until the next day.

There is a better way: AMx, a strategic approach to utility consumption data that uses modern technology to quickly unlock new insight and value from existing infrastructure investments (whether AMR or AMI). This approach enables utilities to take a more moderate, technology-agnostic approach to meter replacements while deploying whatever technology or vendor is best able to meet their goals, and it prioritizes analyzing data in the cloud rather than in the meter to keep costs down and support continuous innovation. Perhaps more importantly, it allows customers to finally get the long-touted benefits of timely, granular consumption data without having to wait for years as new hardware is deployed.

NORA MEAD BROWNELL is the co-founder of ESPY Energy Solutions, LLC. She is a former FERC Commissioner, former Pennsylvania Public Utility Commissioner, and was chair of the board at Pacific Gas & Electric.

Navigating Trends and Challenges in UVM

In the dynamic field of utility vegetation management, staying informed of emerging trends and overcoming evolving challenges are essential for ensuring the reliability and safety of power distribution systems.

UVM is a critical component of the utility sector, encompassing activities such as tree pruning, brush clearing and vegetation con trol. The primary goal of UVM is to mitigate vegetation-related risks to power infrastruc ture, thereby reducing the likelihood of ser vice disruptions and ensuring the uninter rupted delivery of power to consumers. With utilities expanding their operations and the demand for sustainable energy solutions on the rise, the UVM industry has seen significant growth and evolution in recent years.

Trends in UVM

One of the most notable trends in UVM is the adoption of advanced technologies to enhance vegetation management practices. Innovations such as LiDAR, satellite mapping, drones and remote sensing tools have revolutionized how UVM professionals assess vegetation risks, plan maintenance activities and monitor vegetation encroachments near power lines. These technologies enable more precise and efficient vegetation management, leading to improved reliability and cost-effectiveness for utilities.

Utilities are also placing a growing emphasis on environmental stewardship, which is a core value of the UVM industry and the Utility Arborist Association by striving to minimize their ecological footprint and preserve natural resources. By implementing sustainable vegetation management practices, such as selective pruning, habitat preservation and integrated pest management, utilities can mitigate environmental impacts while maintaining the reliability and integrity of power infrastructure.

In addition, utilities are increasingly exploring eco-friendly alternatives to traditional vegetation management methods. Bio-based selective herbicides, biodiversity monitoring and integrated vegetation management (IVM) approaches are gaining traction. By embracing sustainable practices, utilities can mitigate vegetation-related risks and contribute to the preservation of ecosystems and biodiversity.

Overcoming Challenges

Despite the progress made in UVM practices and technologies, the industry continues to face several challenges requiring innovative solutions. One of the most pressing challenges is regulatory compliance, with utilities required to adhere to stringent vegetation management standards set forth by federal and state agencies. Navigating complex regulatory frameworks and ensuring compliance with environmental regulations can be daunting tasks for UVM professionals, requiring ongoing training and investment in specialized resources.

Workforce shortages and skill gaps represent another significant challenge. As experienced UVM professionals retire and the demand for skilled workers continues to rise, utilities are grappling with recruiting and retaining talent in a competitive labor market. Addressing workforce shortages requires strategic initiatives, such as recruitment drives, training programs and partnerships with educational institutions, to attract and develop the next generation of UVM professionals. Check out the “Cool Jobs” video series in the UAA video library.

Staying Safe in the Field

Safety is core value of the UAA and paramount in UVM operations, with utilities placing a strong emphasis on protecting the health and safety of workers, contractors and the public. Rigorous safety protocols, such as wearing personal protective equipment, conducting job hazard analyses and adhering to industry best practices, are integral to minimizing the risk of accidents and injuries in the field. Utilities must contend with the inherent risks associated with vegetation management activities, including worker safety hazards, equipment failures and natural disasters. Implementing robust safety protocols, conducting regular inspections and providing comprehensive training are essential for mitigating these risks and ensuring the well-being of UVM personnel.

Looking to the Future

As the UVM industry continues to evolve, it is poised for further innovation and growth in the years to come. Advancements in technology, regulatory requirements and customer expectations will drive the adoption of new approaches to vegetation management, necessitating ongoing adaptation and innovation.

The increasing focus on sustainability and climate resilience will shape the future of UVM, with utilities exploring innovative solutions to mitigate vegetation-related risks while promoting environmental stewardship. By embracing emerging technologies, fostering collaboration across industry sectors and prioritizing safety and sustainability, the UVM industry can navigate the challenges and opportunities of the future, ensuring the reliable and resilient delivery of electricity for generations to come. By staying informed about emerging developments and adopting innovative solutions, UVM professionals can effectively address the evolving needs of the industry while upholding safety, reliability and environmental stewardship. Collaboration, innovation and a commitment to sustainability will be drivers of success in the dynamic landscape of UVM.

BRANDON HUGHSON (bhughson@protecterrallc.com) is the president of the Utility Arborist Association.

Cover photo: Arcata Marsh & Wildlife Sanctuary, Arcata, Calif., by Crystal Neuenschwander

Forecasting for Fast, Effective Storm Response

Avista builds on satellite-driven vegetation management to predict storms.

By ANDREW BARRINGTON, Avista

What if there was a way to better understand how storms could impact an electric utility’s service territory 72 hours — three days — in advance?

Avista asked that question as it was experiencing increasingly intense and disruptive storms in its Eastern Washington and Northern Idaho electric service areas, which

include regions where it also supplies natural gas. The utility determined that it needed to move beyond basic vegetation management and wildfire mitigation to better predict storms and storm-related incidents and their impacts.

With a model built on a satellite and AI solution for vegetation management, Avista was better able to plan and prepare

for each storm — getting the right resources to the right places at the right time.

Forecasting Storms with Satellite Data

Avista had been working with AiDash Intelligent Vegetation Management System (IVMS) since 2021 and was already familiar with the capabilities of satellite and AI technology. IVMS helps to collect imagery of utility infrastructure and vegetation for insights to support mature grid hardening and fire management efforts.

The “lightbulb moment” came when the utility recognized that it could take advantage of satellite imagery of existing vegetation and infrastructure to address storm issues. By merging satellite, historical and forecasted weather data, Avista could create a predictive model capable of providing severe weather and incident forecasts.

Addressing Issues

Before Avista made the move to develop a forecasting system, the utility had to identify major pain points to address to justify the effort. To determine significant issues, the team analyzed customer outage calls and historical performance during past events, reviewed best practices, surveyed 450 residential and business customers and interviewed employees. Major findings included:

• Customers reported slow response to restore power after large storms and lack of communication before, during and after weather events.

• Internally, Avista was relying on individuals to monitor weather and use gut instincts to direct preparation and response. The utility was also depending upon open-source weather forecasting. With these pain points in mind, the Avista team fleshed out the parameters

of what capabilities the outage and incident forecasting tool should provide:

• Determine outage risk categories — and assign each of Avista’s 12 offices in the region a risk level for an approaching storm.

• Estimate a range of incidents and customers affected — how the system and customers would be affected within a 72-hour window.

• Send automated notifications to stakeholders when specific triggers are met.

• Determine that minimum thresholds are met — for outage risk, estimated or predicted outages, and estimated or predicted customer impact.

• Provide a “dashboard-like” user interface — allowing stakeholders to view information related to outage forecasting.

• Predict high-level “storm response duration” — estimating how long restoration efforts will take — and provide status, such as “two to three days for Avista to restore all customers,” for example.

Overall, expectations were set to improve customer experience with prediction, planning and response. The forecasting tool would aid efforts by reliably upping channel resources to avoid overwhelming the response team. This would include planning staffing needs for crews and the call center prior to the event hitting the area.

Creating and Testing the Model

• Avista worked with AiDash on a pilot that set up a minimal viable product (MVP) “Weather and Incident Forecasting Tool,” to predict storm impact and estimate storm-related incidents within 12 primary office areas

At a glance, Avista’s team can see criticality zones and alert areas and scroll to view incident predictions and criticality levels for each office. Courtesy of Avista and AiDash.

The forecasting tool also provides details on expected wind gust intensity, storm peak time, number of customers potentially impacted and time to restore outages after the storm—specific to each office area. Courtesy of Avista and AiDash.

A LEGACY OF SERVICE, A FUTURE OF INNOVATION

Davey partners with utility companies and communities to navigate today’s challenges and seize tomorrow’s opportunities Our steadfast commitment to forward-thinking solutions ensures a sustainable future in our ever-evolving world Scan the QR code to access a new video series designed to assist utilities in leveraging these opportunities.

in its Eastern Washington and Northern Idaho service regions. The intention was to look at storm predictions at 72, 48, 24, 18, 12 and six hours prior to any storms during the pilot period.

Other goals of the MVP pilot were to:

• Allow for a more significant and consistent window of planning and preparation.

• Remove the need to have a staff member or members monitor weather.

• Reduce the risk that a weather event will be missed or that preparation for it will be insufficient due to staffing, vacation or holiday challenges.

To enable the forecasting tool, the team built an overlay to provide weather information on top of its current satellite and AI solution for vegetation management (IVMS). The system ingested and analyzed satellite imagery, existing infrastructure, new assets and historical storm data as well as the current weather data.

The tool then analyzed results to predict weather and create models of potential customer incidents and outages around 12 regional offices.

By assembling more than 15 years of storm outage data, the pilot program could set storm intensity thresholds. Identifying these thresholds helped the team to evaluate the collective outage risk within the network and in the vicinity of the offices. The effort also enabled a clear view of a storm’s intensity and communicated risk by assigning risk levels to each office area: small, medium, large or extreme.

Severe Weather Testing

Avista tested the proof of concept for storm forecasting in a series of 10 severe weather incidents throughout 2022. The forecasting tool made predictions regarding eight out of the

10 storms, showing 80% accuracy. A look at several storm cases shows increasing benefits from the tool’s capabilities:

Severe Storm Event — November 2022: The tool proved its effectiveness and prediction accuracy when storms punctuated with strong wind gusts hit the area at the beginning of the month. Predicted incidents throughout the storm period showed high accuracy against the 709 actual reported incidents.

With a large sum of the tools’ alerts occurring at least 72 hours ahead of time, Avista had time to assign resources and make sure crews were in place to respond to issues, as well as to notify customers to prepare for an outage, where needed.

The pilot tool’s success in this event prompted Avista to adopt the full AiDash technology behind the tool: AiDash Climate Risk Intelligence System (CRIS).

36-Hour Windstorm — January 2024: Early in the month, Avista’s service area experienced a severe windstorm, which hit some office areas harder than others. The forecasting tool analyzed satellite imagery regarding vegetation data as well as weather reports and noted that the area had experienced five similar storms. It was able to predict that there would be about 163 incidents that would need attention. The actual total reached 177, which meant the solution delivered 92% accuracy.

Dueling Incidents — Gas Pipeline and Electric Utility — November 2023: One of Avista’s natural gas pipelines was damaged in a serious dig incident. Gas service had to be shut off while the utility deployed large numbers of staff and resources to ensure safety and repair.

As the utility focused on the emergency operations plan (EOP) for the gas line, a storm was building that could threaten electric lines in other locations. While focusing on the EOP, Avista could have missed the approaching severe weather event.

Utilities, like Avista, need to determine how to plan and prepare for each storm, and get the right resources to the right places at the right time.

Courtesy of Avista and AiDash.

However, the forecasting tool provided advance predictions. With enough early warning, the team could assess resources and divert some to address what turned out to be 50 storm incidents, reducing customer impact.

Improving Efficiency

Outcomes, including predictions and results, have been successfully validated for the Avista and AiDash “Weather and Incident Forecasting Tool” MVP/pilot. The forecasting model was able to predict and capture all storm events and storm related outages across the utility’s network in 2022 with an accuracy of > 80%. And subsequent results reached 92% accuracy.

Features and capabilities of this technology improve its operational efficiencies:

• Monitoring. With the technology monitoring weather, there is no need for Avista to have a dedicated person watching for severe weather 24/7. And with alerts starting 72 hours in advance, the decisionmakers have time to consider their options and actions.

• Historical record. The utility can now easily call up the historical record of previous storms with similar criticalities and learn from past restoration efforts to better address current scenarios and reduce restoration times.

• I nternal dashboard. Teams throughout Avista, from crew foremen and corporate communications to customer services and account managers, can use the tool’s storm forecasting data for improved planning and preparation in their areas of the business.

• Scope and focus. The model not only assesses the utility’s full territory, but also adds precision to predictions: It identifies specific office regions that will be affected instead of providing only blanket full-grid alerts. Its ability to accelerate forecasting and reporting and to increase advance alert times is proving its effectiveness, storm by storm.

Because more critical storm information is now easily accessible, Avista has experienced improved corporate awareness and better communication across teams. This, in turn, has boosted customer satisfaction, as the utility has been able to alert customers in advance of storms and possible or probable outages, and speed their response to incidents.

As Avista continues to use this technology, which is now implemented in AiDash CRIS, the utility looks forward to reduced costs as well as improvements in both incident response and customer alert time, and, ultimately, in SAIDI and SAIFI.

ANDREW BARRINGTON (andrew.barrington@avistacorp.com) is the products and services manager for Avista. He uses advanced analytics and creative tools, creates and maintains models, and onboards new ideas. His competency areas comprise leadership, product management and change management, and include 10 years of experience in customer success.

Managing Undesirable and Invasive Species on ROWs

The UAA created guidance on how utilities can handle species that are structurally compatible yet non-native and noxious.

By JOHN W. GOODFELLOW, BioCompliance Consulting

The principles of Integrated Vegetation Management (IVM) have gained industry-wide acceptance as best management practices. Three references (ANSI A300 Part 7, ISA BMP - Integrated Vegetation Management, and ROWSC Accreditation Requirements) have codified IVM and aid practitioners in applying the core principles and practices to their organization’s vegetation management programs.

One of the foundational concepts is differentiation between “compatible” and “incompatible” species, formally referred to as desirable and undesirable species. Structurally compatible species are plant forms that are consistent with and do not conflict with the management objectives for the site. In the case of a transmission line, tall growing trees are incompatible and low- growing plant communities are considered compatible.

As adoption of IVM has expanded, many vegetation managers are beginning to explore what “compatible” means on their systems. Traditionally compatible species and plant communities are favored because they can suppress establishment and development of incompatible plants on a site. This strategy focuses on reducing the likelihood of encroachment of structurally incompatible vegetation to maintain Minimum Vegetation Clearance Distances.

More recently, vegetation managers are broadening their focus to include managing structurally compatible plant communities that can provide a wider range of benefits beyond reliability and safety. This also leads to another question: can a species that is structurally compatible also be problematic in terms of degrading habitat or adversely impacting land adjacent to the ROW? Said another way, can undesirable non-native, noxious or

Autumn Olive is structurally compatible but is an aggressive invasive. At low density, it is easily controlled. Photo by IVM Partners.

invasive species really be compatible in terms of managing the site? Technically speaking the short answer is yes, but should they be?

Creating the UAA Guidance Document

The Utility Arborist Association (UAA) has developed guidance on how to select vegetation that is structurally compatible and does not represent a threat to the compatible plant communities, ROW habitats or neighboring land use. This is an emerging issue in IVM and utility vegetation management (UVM). The concepts being introduced will evolve with time and experience. It is also important to acknowledge that IVM programs are established by vegetation managers and stakeholders and are specific to each utility’s program.

Adoption of the concepts being introduced in the guidance document are, of course, voluntary. The document is intended to provide some structure to the decision-making process for evaluating maintenance practices applicable to management of non-native, noxious or invasive plants. This is important as a company’s management objectives broaden to consider these plants incompatible for reasons other than conductor clearance.

ANSI A300 (Part 7) defines compatible vegetation as “plant forms consistent with management objectives.” The standard provides potential management objectives for which these considerations may be significant. Some management objectives

Promoting Environmental Stewardship

The members of UAA’s Environmental Stewardship Committee that created the new guidance document on what is a compatible species. The traditional definition of incompatible is based on whether a plant has to height growth capability to present a risk overhead conductors. The issue being addressed in the document is whether a low-growing invasive or noxious plant can be compatible. The members of the committee who drafted the document include:

• Marie Maiuro, First Energy

• Andrew Mertz, Duke Energy

• Hans Straight, First Energy

• Phil Chen, Overstory

• Stan Vera Art, Grow With Trees

• John Goodfellow, BioCompliance Consulting, Inc

that may consider species makeup outside of structural compatibility include, but are not limited to, the following:

• Controlling noxious weeds and invasive species

• Improving aesthetics

• Managing pollinator and wildlife habitat

• Reducing the risk of wildfire (e.g. some invasive weeds that are a high-fire threat)

• Restoring ecological and environmental benefits If a program’s objectives include consideration of more than structural compatibility, the new UAA guidance document can help frame the decision-making process. Understand that, as tolerance levels and action thresholds are established, incompatible plant pressure will need to consider species, density, location and other criteria—not just height.

The Right-of-Way Stewardship Council IVM Accreditation Requirements provides a guidepost to recognize IVM excellence using 10 principles. Principle 8, Accounting for economic and ecological effects of treatment, includes a criterion (8.2) that focuses on environmental viability. That section addresses situations in which a UVM program manager is considering the full environmental costs and requirements of vegetation management activities.

There are many species of invasive bamboo that may be structurally compatible with overhead lines. Photo by Duke Energy.

Japanese knotweed is relatively low growing (structurally compatible) but is exceptionally invasive. Photo by FirstEnergy.

Purple loosestrife is a low-growing herbaceous plant that out competes native wetland vegetation. Photo by New York Power Authority.

Treatment choices must be made with full consideration of direct and indirect effects, including an array of positive (e.g. ecosystem services) and negative environmental impacts. This means that invasive plants should be managed with adequate planning and appropriate maintenance practices to prevent their spread whenever practical.

Developing a Decision Tree

A decision tree for IVM-based programs can be used to assess species that are structurally compatible with the intended use of the site. At the same time, they have the potential to be

problematic due to being a non-native or invasive species or a noxious weed. Four overarching questions are addressed in the decision tree:

1. Is the species structurally compatible with the intended use of the site?

2. Is the structurally compatible species a noxious weed?

3. Is the structurally compatible species an invasive species?

4. Is the structurally compatible species a non-native or alien species?

The UAA guidance document provides complete definitions and cites the authoritative source for classification of species. The following table presents simplified definitions. The decision tree is intended to help guide a vegetation manager through the decisionmaking process to determine when it is practical to consider the management of invasive plants and other species that, though structurally compatible, may not be consistent with the management objectives of the site.

Table 2: Non-native or alien species aggression and

Table 1: Classification of species that may occur on a ROW.

Reviewing Practical Considerations

The new guidance document is a first attempt to characterize the decision process involved in applying an expanded definition of the concept of what is compatible and incompatible in the context of IVM. The concept will likely be refined as the industry gains experience.

One of the challenges will be how to strike the right balance between the formal decision process presented in the decision tree and practical application on the ground. For example, what can and should be done if the ROW traverses a site with a large population of “undesirable” (non-native, invasive, and/or noxious) plants? Some examples would include sites with high populations of phragmites, Japanese knot weed, multiflora rose and kudzu. Each of these species does not have the height growth potential to create a direct conflict with overhead T&D conductors, yet each can have an adverse impact on local native plant communities. Active management of invasive and noxious plants on ROW calls for a degree of pragmatism.

One approach worth consideration is to borrow a concept from tree risk management, that being “As Low As Reasonably Practical” (ALARP). Applying this to the concept of compatible species and IVM would help frame an appropriate management intervention. The intensity of a vegetation maintenance action would be at a level that was effective in reducing plant pressure without the

For more than 75 years, Townsend Tree Service has been helping customers across the country meet their IVM goals by providing world-class service in the following areas:

• Utility, pipeline and transportation line clearing, maintenance and growth control.

• Drainage and right-of-way clearing, maintenance and growth control.

• Storm and disaster emergency response.

• Chemical and herbicide applications.

The tall grass-like cane of phragmites is structurally compatible with overhead lines but will spread aggressively. Photo by New York Power Authority.

expenditure of cost, time and/or effort that is disproportionate to the benefit gained or where the solution is impractical to implement. It is also important to recognize the need for economically efficient allocation of vegetation maintenance

resources, focusing on sites with the highest likelihood of suppressing or eliminating an undesirable species.

A committee of subject matter experts created this guidance document to raise awareness of vegetation management industry professionals and to promote shared learning. The practices described may not be appropriat e for use in all situations.

The hope is that the new guidance document will stimulate thinking and discussion. It’s also possible that as the concepts are refined, they may be included in an annex to the next edition ANSI A300 Part 7 and an appendix in a future edition of the ISA IVM BMP.

JOHN GOODFELLOW ( jwgoodfellow@msn.com) has 45 years of experience in the utility industry and is a leading authority on utility vegetation management and reliability. He currently manages an active portfolio of vegetation management-related research projects and serves as Chair of the Right of Way Steward Council’s Technical Advisory Committee, which established accreditation requirements for IVM on electric transmission and pipeline systems in North America. He is the lead author of the new ISA BMP Utility Tree Risk Assessment.

WORTH,TX | SEPT 10-12

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WHAT’S HAPPENING THIS YEAR?

In addition to networking opportunities and trade shows, get to know the latest in: utility arboriculture research, best management practices, environmental concerns, vegetation management trends, and continuing education credits.

HELP YOUR PROGRAM BE THE BEST IT CAN BE. Join your friends, colleagues, and industry experts working at the intersections of technology, safety, and leadership to keep your practice growing

There are many species of invasive tamarick/Russion Olive that may be structurally compatible with overhead lines. Photo by IVM Partners.

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Corridor Management with Satellite Analytics

By adopting intelligent corridor management, E.ON optimized operations and enhanced reliability for its 80,000 km grid.

By Sven Mögling, E.ON Group

The global energy landscape is undergoing a significant transformation, spurred by several key trends driving an unprecedented surge in electricity demand worldwide.

One major trend is the electrification of various sectors, including transportation and heating, where the rapid adoption of electric vehicles (EVs) and electric heating systems are driving up electricity consumption. Additionally, the proliferation of digital technologies and the Internet of Things (IoT) is increasing the reliance on electronic devices, further propelling the demand for electricity. Moreover, the ongoing industrialization and urbanization in developing economies are fostering a growing need for electricity to power factories, infrastructure and urban amenities.

For electric transmission and distribution companies, these trends pose both challenges and opportunities. On one hand, the increasing demand for electricity necessitates significant investments in upgrading and expanding infrastructure to accommodate higher loads and ensure reliable supply. On the other hand, it opens avenues for innovation and modernization, such as the deployment of smart grid technologies and renewable energy integration. Electric utilities must navigate regulatory frameworks, manage operational complexities and strike a balance between traditional and renewable energy sources to meet the evolving demands of consumers.

The implications of the rising demand for electricity on grid reliability and resilience are profound. Aging infrastructure, coupled with the need for more robust systems to handle increased loads, presents a formidable challenge. Extreme weather events brought about by climate change further underscore the importance of fortifying grid infrastructure against disruptions. Ensuring the stability of the grid is paramount to prevent outages that could have far-reaching economic and societal impacts.

Managing Corridors

In light of these challenges, corridor management has become increasingly critical. These corridors, which host vital infrastructure such as power lines and substations, demand vigilant attention to risks to prevent potential hazards and disruptions. In particular, vegetation risks, such as overgrown trees and vegetation encroachment, pose a significant threat to the reliability of transmission and distribution lines. Overhanging branches or fallen trees can cause outages, fires and other safety hazards. Hence, effective corridor management, which involves regular vegetation monitoring, pruning and removal to maintain safe distances between power lines and vegetation within the Rightsof-Way (ROW), is essential to mitigate these risks and ensure the reliability and resilience of the grid.

A screen capture from the app shows the regions where E.ON gets near real-time intelligence of grow-in and fall-in risks along its medium- and high-voltage overhead lines. Graphic courtesy of E.ON.

E.ON, a European utility company, confronts these challenges with technology and digitalization. Its networks are not only evolving into intelligent systems but so too are its internal processes, including the monitoring and management of vegetation along its utility corridors.

Challenges with the Conventional Approach

As one of Europe’s operators of energy networks and infrastructure, E.ON is catering to about 48 million customers with innovative energy solutions. Spanning across three regional markets—Germany, Sweden, and East-Central Europe/Turkey —E.ON operates an expansive power network. In Germany alone, its nine regional companies oversee about 800,000 km of electricity and gas grids, primarily comprising distribution lines. Managing vegetation risks along such extensive corridors poses a multitude of challenges.

Traditionally, like many electric utilities, E.ON delegates this task to service providers or subcontractors. These subcontractors typically operate under five-year contracts, assuming complete responsibility for keeping the routes clear. Under the conventional approach, the subcontractors would manually inspect the entire route before submitting the offer, and subsequent planning was based on the results of these inspections.

Throughout the term of the contract, the subcontractors would perform further manual inspections on a regular basis and adjust their plans accordingly based on risks identified. They would then carry out pruning twice a year, with E.ON conducting quality assurance (QA) using random

samples on site. The entire process would take place partly analogously (e.g., planning and creating route plans) or only via Excel or email.

However, this approach posed significant limitations. E.ON’s Distribution System Operators (DSOs) lacked comprehensive visibility over the state of vegetation along the networks as well as the existing risks, as information remained confined within the subcontractors. The QA process was complex, relying on conducting a few random samples, leading to quality deficiencies surfacing only when things became critical. Moreover, reliance on analog and disjointed digital tools made planning, resource allocation and reporting cumbersome and inefficient. Given the vast expanse of the network, not all risks were invariably identified, resulting in power disruptions caused by vegetation coming into contact with power lines.

A screen capture from the app shows the regions where E.ON gets near real-time intelligence of grow-in and fall-in risks along its medium- and high-voltage overhead lines. Graphic courtesy of E.ON.

Effectively managing corridors across E.ON’s vast distribution network is integral

grid resilience strategy. Photo courtesy of E.ON.

At this point, the company realized that the traditional manual approach just wouldn’t cut it anymore. It recognized the pressing need for a more efficient and intelligent way of managing the vegetation risks around its infrastructure.

Shifting to Intelligent Corridor Management

E.ON is a traditionally innovation-friendly company. For some time, it has been exploring new technologies such as augmented reality and IoT, as well as drones for inspecting power lines. Thus, embracing the rapidly advancing satellite technology was a natural progression for the company.

E.ON’s foray into space-based technologies started in 2020 when it partnered with LiveEO for a pilot project involving its subsidiary E.DIS, followed by another successful pilot with Bayernwerk in 2021. Encouraged by the positive outcomes of these initiatives, E.ON made the strategic decision to make LiveEO’s Treeline the standard solution for satellite-based vegetation management starting in 2023.

The comprehensive rollout involves monitoring more than 80,000 km of medium-voltage and high-voltage overhead lines in Germany, with potential expansion into Hungary. The overarching objective is two-fold: to enhance vegetation risk management along power line corridors, and to improve internal operations, subcontractor collaboration and stakeholder management. LiveEO employs satellite imagery with a horizontal resolution of 3 m and performs 3D vegetation classification on this data within a corridor of at least 80 m wide along the network. Vegetation classification is based on machine learning models trained by LiveEO on local training datasets, where individual trees, dense trees and forests are identified. The location of the vegetation is then combined with a catenary curve model of grid systems to determine horizontal and vertical grow-in encroachment risk and fall-in risk along the ROW. The insights derived are accessible via LiveEO’s web and mobile applications.

E.ON DSOs integrate these insights into its utility vegetation management (UVM) program, covering every stage from pre-planning to execution to close-out:

• Subcontractors receive the analytics prior to submitting their offer, enabling them to accurately estimate the expected effort or scope of work. This allows them to submit a more tailored offer accordingly, facilitating more efficient resource allocation. Once the contract has been awarded, the subcontractors receive the route information via the LiveEO app, replacing the analog method. The use of the LiveEO app, which is mandatory for subcontractors, helps ensure the seamless flow of critical insights among relevant stakeholders, thereby streamlining the process.

• Based on the analytics, the annual planning and scheduling of the operations are carried out in the LiveEO app. All pertinent data such as risk classification, risk type, location and even cadastral information are recorded in the tool. This allows risk prioritization, data-driven decision-making and effective stakeholder management.

E.ON’s subcontractors rely on the LiveEO app throughout the entire process, from planning to on-site execution to reporting, ensuring a streamlined and efficient approach. Photo by E.ON.

• After planning, tasks are assigned to the appropriate employees or work teams via the LiveEO app for the actual on-ground execution. Having accurate data on risks, the field crew can do precise treatment and cutting prescriptions, reducing operational costs.

• After pruning, the work carried out is logged in the LiveEO app, enhancing reporting and documentation.

• Following the pruning period, subcontractor work undergoes quality control via the LiveEO app, employing protocols and a before-and-after comparison.

In essence, LiveEO’s Treeline solution serves as a comprehensive platform for mapping and managing the entire vegetation management process of E.ON, enabling the company to effectively address risks across its infrastructure.

Transformative Results

In just a few months since the start of the rollout, E.ON’s adoption of this intelligent approach has yielded the following results:

• Enhanced situational awareness: By gaining comprehensive insights into potential vegetation encroachment, E.ON can proactively manage grow-in and fall-in threats, enhancing grid resilience and reliability.

• Streamlined workflows: Using intuitive apps for planning work packages and dispatching work orders has streamlined operations, optimizing resource allocation and improving efficiency.

• Effective stakeholder management: Access to cadastral information facilitates better management of external stakeholders, including landowners, leading to smoother interactions and negotiations.

• Cost savings: By optimizing operations and reducing downtime due to vegetation damage or contact, E.ON expects to achieve a significant reduction in vegetation management costs. With these outcomes, E.ON anticipates further improvements in operational efficiency, as well as system reliability, poised to yield a reduction in SAIDI and consequently, elevate customer satisfaction.

E.ON’s adoption of satellite data and AI technology represents a paradigm shift in corridor management, offering insights and efficiencies elevating grid resilience and reliability in the face of growing energy demands and environmental

challenges. As the energy sector continues to evolve, such innovative approaches will play a pivotal role in shaping a sustainable and resilient energy future.

SVEN MÖGLING (sven.moegling@e-dis.de ) is the innovation manager at E.DIS Netz GmbH (E.ON Group), focusing on new technologies for energy networks. He earned his master’s degree in business management from Otto-Guericke University in Magdeburg, Germany, in 2005. He then joined Regiocom GmbH as a team leader and project manager before transitioning to an advisory for processes and projects role at e.kundenservice Netz GmbH (E.ON Group) in 2015.

OUR ONE ASPLUNDH APPROACH PROVIDES A SINGLE POINT OF CONTACT TO THE ASPLUNDH FAMILY OF COMPANIES. WITH ONE PHONE CALL, OUR TEAM IS READY TO RESPOND WITH BEST-IN-CLASS EQUIPMENT, RESOURCES, AND COMPREHENSIVE SOLUTIONS TO HELP OUR UTILITY PARTNERS TAKE ON THE TOUGHEST VEGETATION AND INFRASTRUCTURE CHALLENGES.

Boosting Biodiversity in ROW Managed with IVM

In an age of rising human population and natural ecosystem disturbances, here is a look at the past and future of biodiversity.

By STEPHEN HILBERT, Asplundh Tree Experts, LLC

Electric utilities nationwide face the challenges of climate change and natural ecosystem disturbances. Case in point: About 10,000 thunderstorms occur each year in the United States, according to the National Weather Service. Additionally, paleoclimatologists have found evidence of hurricanes impacting North America thousands of years in the past. These scientists study clues in earth’s geologic history

through core samples taken from coastal areas where tropical storms and cyclones strike.

This type of severe weather has consistently contributed to massive disturbances of the status quo ecosystem where they occurred. In pre-human history in North America, thunderstorms and fire went hand in hand shaping the Great Plains, according to the National Park Service. By examining coastal core samples,

State Game Lands 33 is shown during the fall season as an example of an early successional habitat.

paleotempestologists are finding charcoal layers immediately after sand layers. This indicates that after major hurricanes strike, the toppled trees and brush burned, drastically altering the existing ecosystem, according to AmericanScientist.org.

“The pollen above the sand layers also shows that following these hurricanes, salttolerant plants increased in abundance, presumably because of an influx of saltwater from the storm surge. What’s more, we found indications that the local pines took considerable time to recover from the damage that storm and fire inflicted on them.”

Tracing the Ecological Progression

Following these disturbances, a clear ecological progression of plants and animals occurs. The severity of a disturbance dictates which plant species will be the first to take advantage of these new ecosystem conditions. The most extreme example would be a rock with bare ground. In that case, lichens and mosses would be the first to colonize, followed by annual weeds, perennial grasses and weeds, shrubs, trees like aspens and pine trees and finally the hardwood forest. All this would take hundreds if not thousands of years to reach the final climax forest.

All the while, in each stage of succession many different plants grow producing uncountable numbers of seeds. These seeds lie dormant in the soil waiting for correct conditions for germination,

An Emerald Ash Borer Beetle is an invasive insect that feeds on Ash trees. Photo 238652801 © Heather Mcardle | Dreamstime.com

An Emerald Ash Borer treatment sign is posted with a number on an Ash tree trunk. The New Jersey Department of Parks and Forestry project tags forest trees in danger of being killed by the insecta pest beetle.

Photo 238652801 © Heather Mcardle | Dreamstime.com

dedicated crews deliver integrated solutions throughout North America every day.

according to the Weed Science Society of America. If a disturbance occurs, for example, in the shrub phase of succession, the seeds of the annual weeds and perennial seeds would sprout arresting the ecological succession for a period of time until the shrubs can take back over. This cycle of disturbance has been occurring for millions of years according to geologists.

The geologic time scale is a concept that divides the earth’s age to describe the timing and relationships of events in geologic history. For example, during the Jurassic Era, dinosaurs ruled the Earth and the flora and fauna were much different than they are today. The dinosaurs’ reign ended with an asteroid impact some 66 million years ago, causing a mass extinction event for many other animals as well, which is an extreme example of an ecological disturbance.

any other species that existed prior. The human impact of biodiversity is one of the major markers of the Anthropocene. Most experts agree that humans have accelerated the rates of extinction. The exact rate remains up for debate, but ranges are estimated between 100 to 1,000 times the normal background extinction rates.

“biodiversity is declining faster than at any time in human history”

Analyzing Humans’ Impact on the Environment

Now let’s fast forward through the many different eras between then and about 11,500 years ago, when the glacier ice melted away and the Earth entered the Holocene Epoch. This time period gave rise to modern humans, who built great civilizations and huge technological advancements. Scientists have debated that a new epoch started at the rise of the Industrial Revolution in the 1800s. It is dubbed the Anthropocene, meaning human (anthropo) and new (cene).

Although no clear consensus exists about when the Anthropocene started, it has been agreed upon that humans have had huge impacts on the environment, more so than

According to the 2021 Economics of Biodiversity review, written by Partha Dasgupta and published by the UK government, “biodiversity is declining faster than at any time in human history” and is labeled as the sixth mass extinction event. A 2023 study published in Biological Reviews found some 48% of 70,000 monitored species are experiencing population declines from human activity, whereas only 3% have increasing populations.

The exact cause of this biodiversity loss is debated among scientists. Some credit human overpopulation and excessive consumption, others point to climate change and habitat destruction.

Additionally, with a global economy, the introduction of invasive species has had a significant impact on ecosystems. One such invasive insect that many utility vegetation managers are familiar with is the Emerald Ash Borer. This beetle has killed millions and millions of ash trees in North America causing drastic changes in forest cover types, particularly east of the Mississippi River. This is one such example of the human impact on biodiversity. Additionally, utilities have had to mitigate the dead ash trees that could potentially strike utility equipment causing damage and outages.

This figure shows an ecological succession ranging from exposed rocks to forests.

Annual Mean Thunderstorm Days

(1993-2018)

Making the Case for Biodiversity

A rise in human population leads to an increased need for housing, food, recreation space and essential utilities such as water and electricity. All these needs require an altering of the existing environment and can create fragmented ecosystems and lead to biodiversity decline. According to conservation.org, many reasons exist to maintain biodiversity, such as:

• Wildlife supports healthy ecosystems that we rely upon. Ecosystems provide fresh water, pollination, soil fertility and stability, food and medicine. Weakened ecosystems are less likely to deliver those services.

• Keeping biodiverse ecosystems intact helps humans stay healthy. Research indicates a close link between disease outbreaks and the degradation of nature. We have seen the damage that diseases can do not only to human health, but also to the global economy. By protecting biodiversity in Earth’s ecosystems, countries could save lives and money, while helping to prevent future pandemics.

• Biodiversity is an essential part of the solution to climate change. A group of researchers led by Bronson Griscom from Conservation International discovered that nature can deliver at least 30 percent of the emissions reductions needed by 2030 to prevent climate catastrophe.

Protecting biodiversity plays a crucial part in achieving these emissions reductions.

• Biodiversity is good for the economy. At least 40 percent of the world’s economy and 80 percent of the needs of the poor are derived from biological

This map shows the annual number of thunderstorm days in the United States.

Early Successional Species in Decline

Common name

Red-cockaded woodpecker

Northern bobwhite

Common yellowthroat

Rose-breasted grosbeak

Veery

American woodcock

Eastern loggerhead shrike

Yellow-breasted chat

Summer tanager

Yellow-bellied sapsucker

Prairie sarbler

Ruffed grouse

New England cottontail

Bobcat

Least shrew

Appalachian cottontails

Edwards’s hairstreak

Morthern cloudy-wing

Swarth skipper

Frosted elfin butterfly

Kramer blue butterfly

Easter hognose smake

Black racer

Bog turtle

Gopher tortoise

Indigo snake

Pine snake

Scientific name

Birds

Picoides borealis

Colinus virginianus

Geothlypis trichas

Pheucticus ludovicianus

Catharus fuscescens

Scolopax minor

Lanius ludovicianus migrans

Icteria virens

Piranga rubra

Sphyrapicus varius

Dendroica discolor

Bonasa umbellus

Mammals

Sylvilagus transitionalis

Fetis rufus

Cryptotis parva

Sylvilagus obscurus

Invertebrates

Satyrium edwardsii

Thorybes pylades

Nastra Iherminier

Callophrys irus

Lycaeides melissa samuelis

Amphibians and reptiles

Heterodon platyrhinas

Coluber constrictor

Clemmys muhlembergii

Gopherus polyphemus

Drymarchon couperi

Pituophis melanoleucus

resources. Up to 35 percent of the world’s food is pollinated by insects.

• Biodiversity is an integral part of culture and identity. Species are frequently integral to religious, cultural and national identities.Ecosystems such as parks and other protected areas also provide recreation and a knowledge resource for visitors, and biodiversity is a frequent source of inspiration for artists and designers.

Creating Early Successional Habitats

Through the loss of habitat, it becomes obvious that the opportunity for natural disturbances to create early successional habitat becomes less. This places strain on the insects and animals requiring these habitats to complete their life cycle.

Pollinators have been highlighted in recent years due to their decline and their importance to the food supply chain. The Center for Biological Diversity discovered that 24% of native bees are imperiled, and population declines are occurring in 52% of native bees. In addition to pollinators, according to America’s Longleaf Restoration Initiative, other early successional species are on the decline.

Integrated Vegetation Management (IVM) techniques on rights of way (ROW) can create the critical early successional habitat necessary for a healthy ecosystem through promoting lower growing grasses, forbs and shrubs. Not only does this promote biodiverse areas and species-rich ecosystems but is compatible with vegetation management plans on electric utility ROW, according to “Powerline Right-of-Way Management and FlowerVisiting Insects: How vegetation management can promote pollinator diversity” by Laura RussoI, Hannah Stout, Dana Roberts, Bradley D. Ross and Carolyn G. Mahan. By creating a system of arrested successional development, IVM mimics those critical disturbances that many species rely upon.

Powerful weather events like thunderstorms, hurricanes and ice storms topple over trees and have historically created early successional biodiverse habitats that many species rely on to survive, including humans. As humans expand into previously undeveloped areas, they have tremendous opportunity to develop critical early successional, biodiverse habitats on utility ROW by using proven IVM techniques. As stewards of the lands that the utilities cross, we have a a certain responsibility to maximize the biodiversity potential.

STEPHEN HILBERT (shilbert@asplundh.com) is a manager in the technical services department at Asplundh Tree Experts, LLC providing education and training to Asplundh’s field employees on utility vegetation management and is Asplundh’s voting member on the ANSI A300 Committee. He has a long-held passion for tree care.

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Fleet Electrification in the Tree-Care Industry

The Davey Tree Expert Company is discovering the benefits and drawbacks of EVs during a pilot project.

By JILL GOLDEN, The Davey Tree Expert Company

In less than 10 years, consumers have broken electric vehicle (EV) sales records with no signs of EV sales slowing down. In fact, a Pew Research Center article, “How Americans view electric vehicles,” stated that four out of every 10 Americans are considering or will consider an EV when they purchase their next new vehicle.

But what about commercial fleets? Where are they in the transition to cost-effective, zero-emission horsepower? The race is on that front, too, with fleet electrification powering up across all major markets, including the tree-care industry.

Why Fleet Electrification?

Without a doubt, electrification will continue as the United States strives to reach its net-zero emissions targets in the coming decades. And clean transportation is key to making it happen. It may seem that nearly everyone is adding electric trucks to their fleet and here’s why: Commercial trucks (and buses) are among the biggest contributors to greenhouse gases (GHGs), accounting for 25 percent of transportation-sector GHGs, stated the Environmental Defense Fund report, “The Road to Zero Emission Trucks,” — and that’s despite the fact that trucks and buses account for only 4 percent of on-the-road vehicles.

While accelerating the conversion of a transportation fleet from

gasoline-powered to electric is good environmentally, successfully making the transition requires more than a commitment to sustainability; it requires a forward-looking business model and a smart strategy for implementation.

Testing EVs in a Pilot Project

Throughout its 140-year history, Davey Tree has been synonymous with environmental awareness and stewardship. To hold itself accountable in managing and mitigating impacts on the environment — and helping its clients do likewise — Davey is working hard to stay ahead of the EV curve. Here’s a look at how the company is applying innovation and problem-solving to achieve greater efficiencies and fewer emissions.

Challenge: “We didn’t want to wait for mandates requiring the use of EV and electric tools to drive our transition,” says Paul Milano, Davey’s vice president, fleet services and procurement, “so we’ve been continually looking for ways to get the best of both worlds: high fuel economy and reduced reliance on fossil fuels.”

Solution: In addition to including Tesla Model Y electric cars in its vegetation management fleet, Davey recently added a mini fleet of Ford F-150 Lightnings. These all-electric trucks, which are part of a pilot program to assess the value of incorporating more EV trucks into the company’s business operations,

Davey Tree employees drive Ford F-150 Lightning trucks.

Six Fleet Electrification Do’s and Don’ts

As one of the top 25 of green fleets of all commercial fleets in the United States, Davey has learned a thing or two about transitioning to electric vehicles. Here are some of Davey’s top tips based on the successes the organization has in electrifying its commercial fleet.

1. DO set goals. The transition to electric is a significant one that’s not without an investment of time, energy and budget. In addition to determining a strategy, organizations will also want definitive metrics, milestone and outcomes so they can monitor their progress and measure their outcomes. As an example, in 2017, Davey established a bold goal to reduce its global fleet fuel consumption by 35 percent per labor hour by 2023 from a 2017 baseline. Through 2022, Davey reduced its fuel use per labor hour by 21%, thanks to a consolidated increase in labor hours and innovative solutions, such as the introduction and expansion of battery-operated tools, EV/hybrid technologies and the right sizing of the fleet.

2. DON’T be afraid to go slow. Rather than revamping the entire fleet in one fell swoop, smart managers will test different variables on a small scale. For Davey, this meant introducing just a few EVs into the fleet and measuring their performance across different service lines and climates.

are being used in all Davey service lines. For example, Davey Resource Group, a subsidiary of Davey, and a Utility Vegetation Management (UVM) services team are using these EV trucks for tree growth regulators (TGR).

Results: Although the results of this pilot program won’t be available until late 2024, Davey is already using preliminary data to determine the best way to incorporate more EVs into its fleet. In addition to the all-electric trucks, Davey’s fleet also includes more than 1,000 hybrid and alternative fuel vehicles, such as the Toyota Rav4 LE Hybrid SUV and Ford F-150 Flex Fuel vehicles. This mix of hybrid, electric and alternative fuel vehicles comprise about one-eighth of Davey’s total fleet and is already helping the organization reduce reliance on fuel while also lowering the company’s carbon footprint.

Weighing the Pros and Cons of EVs

Like all early adoption technologies, Davey has uncovered both the pros and cons of EVs in a commercial fleet. Here’s a high-level look at what the company has discovered.

Pros

• EVs can help reduce carbon footprints. According to the U.S. Department of Energy report, “Emissions from Electric Vehicles,” all-electric vehicles, hybrid vehicles and hybrid-electric vehicles produce lower tail pipe emissions than gasoline-powered vehicles and zero emissions when operating exclusively on electricity.

• EVs can be more cost effective. In addition to the obvious fuel savings, EV maintenance costs are typically lower too.

3. DO develop a custom fleet electrification strategy. Every organization is unique so it’s important for organizations to assess where they are before deciding where they want to go. Davey’s conversion plan takes into consideration not only field operations but also need and potential impact.

4. DON’T forget there’s a learning curve. “Nobody has it all figured out,” says Milano. “We’re still in the learning curve stage, but we’re being aggressive, knowing that we’re helping shape and influence the future of electrification in our industry.” With that in mind, Milano encourages others to learn all they can about electrification, as well as follow current best practices.

5. DO plan ahead. Because one of the cons of EVs is the time it takes to charge the vehicle, it’s essential to think ahead on how to maximize the workday. The solution is to designate “admin time” for phone calls and computer work while parked at a charging station.

6. DON’T neglect ancillary sustainability reporting. While most organizations regularly document their progress toward environmental, social and governance (ESG) goals, Milano urges them to tie their environmental goals to their vendors’ efforts. For example, Davey’s fleet electrification efforts are reported by both Davey and its utility customers. If you’re not familiar with your vendor’s ESG goals and outcomes, just ask.

• EVs and electric-battery powered tools reduce noise pollution. Without a gas-powered motor, EVs and battery-powered tools, such as electric mowers and trimmers, don’t generate the buzz, whine and noise of traditional vehicles and equipment. Even better, having fewer noise emissions is a happy byproduct for residents, owners, visitors and tenants of commercial grounds properties, including hospitals, college campuses, military bases and Homeowners Associations (HOAs).

• EVs can help reduce fire hazards. Unlike traditional combustion engines, which have many hot points of contact that can become a fire hazard, EVs and electric

UVM Lead Specialists Dan Defelice, pictured using a TGR backpack sprayer,and Chris Fleming operate the Ford F-150 Lightning, in San Diego, California.

equipment don’t have those issues. Also, during certain weather events, such as red flag warnings, clean energy can still be used, whereas the use of traditional fuel-powered vehicles and equipment may be restricted.

Cons

• EV charging infrastructure is insufficient. Although EV charging stations are popping up in more and more locations, the lack of adequate charging stations is a major challenge. According to consulting firm Deloitte, in its article titled, “Climbing the electric vehicle transformation mountain,” the United States continues to lack “an efficient, affordable, and reliable EV charging network” with only 32,000 available public DC fast chargers. “Charging is the biggest hurdle for us right now,” explains Milano. “We have to be strategic in how we manage the charging issue. Our crews don’t want to sit for hours at a time without being productive, so we scout out fast-charge locations and do typical work-in-the-truck tasks to make the most of it.”

of doing what’s needed when it’s needed?” Charging an EV can take anywhere from 30 minutes on a fast charge to several hours or even overnight. For fleet managers and EV operators, this means optimizing the route, includingknowing where and what kinds of charging stations are available.

Are You Doing the Right Thing?

• Cold weather may negatively affect EV performance. While no conclusive studies prove that EVs are useless when subjected to severe temperatures, enough anecdotal evidence suggests that lower temperatures are likely to affect EV battery performance, including capacity, range and charging times. “Our Teslas have been flawless through the cold weather, but winter 2023 was the first season with our all-electric Ford Lightnings. We’re optimistic, of course, but we’ll have to see what they can do in the cold,” says Milano.

• Planning ahead is a must. Charging an electric vehicle takes longer than pumping gasoline into a vehicle’s tank, which begs the question, “Is the vehicle capable

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While the transition from a gas-powered fleet to an electric fleet is neither simple nor easy, it is the right thing to do. The key is being thoughtful and strategic about the transition. In addition to using what you’ve learned here, start by assessing your own sustainability goals. Talk to others about what their sustainability programs look like and look for ways to partner and mutually support your vendors and service providers in their sustainability goals. Because, in the end, it’s going to take a village to reach our national goal of net zero emissions by 2050 — but it will be worth it.

JILL

GOLDEN (Jill.Golden@davey.com) is a project manager, corporate communications, for The Davey Tree Expert Company.

Davey’s fleet includes Tesla Model Y long range electric cars.

Research Advancements in UVM

Research in the utility vegetation management (UVM) space has al ways been pragmatic, economically frugal and conducted as the need arises over time. Historically, several classical studies exist, some longer term, that have helped the industry build prescriptive approaches. However, as we embrace the nuances of climate change, worker chal lenges, economics and a growing need to work smarter, research will benefit from direct assessments that deliver stricter return on investment requirements and solution-driven deliverables.

Adaptive research, in close collabora tion with utilities, seems beneficial in this respect. More and more questions are now being answered by the utilities themselves as partnerships grow. One reason is the rise of new tools that can give utilities opportunities to develop solutions in a relatively short time frame and in-house with the help of external partners and consultants alike.

Examples of these advancements in UVM research and the growing need to work smarter with more targeted resources can be found in workflow software, LiDAR and satellite analytics, biodiversity assessments and safety programs. Additionally, technological advances do offer some answers in the shorter term and may prove to help in the effort to guide our industry forward as we embrace change and the need to improve our return on investments as we continue to face growth and an uptick in the electrification needs of our industry.

and care of canopies — especially in areas where utilities UVM and UF canopy merge.

Sharing Knowledge with Other Sectors

As sectors such as urban development, housing and energy infrastructure continue to expand, there is a growing opportunity to leverage research from one sector to benefit another. This need is becoming increasingly essential with the development and construction of new corridors, solar farms, improved distribution infrastructure and energy storage — all of which are becoming more interconnected with the growing urban development

Opportunities for integrating UVM research into mainstream practices include enhancing software for better tree inventory tracking, developing risk models and implementing effective arboricultural techniques. This includes diverse tree plantings, proper planting care and pruning to enhance canopy initiatives.

Our adaptive research efforts also benefit from global perspectives, and many North American utilities have partnerships in other geographies, including frontline areas and island states. The ability for North American utilities to invest in other regions in Central and South America is possible with technological advancements so we can deploy tools efficiently with minimal use of manpower and assist in UVM in these more tropical areas.

Focusing on Biodiversity and Sustainability

As we advance our industry and engage with the nuances of our times, some considerations such as biodiversity levels on our rights-of-way (ROWs), and in some cases, immediately adjacent land areas, are important to greening initiatives, including our corporate sustainability efforts. These are important as we grow relationships with the communities we serve.

The message of biodiversity also extends into mainstream operations as we pay greater attention to ROWs in ecologically important areas, conserve and recognize rare and threatened plant populations and engage with other sensitive sites. The use of technological innovation to engage with other entities (state and federal agencies), will improve collaboration and opportunity to identify and maintain required protocols. Collaborating with these regulatory agencies will also aid in the development of proactive solutions and relations amongst cross-agency and multidisciplinary teams.

Emerging, too, is the importance of areas of intersection of urban forests and ROWs. Research gains in the utility sector and tools that are refined with UVM intent are also being able to be deployed into the urban forestry (UF) sector. Helping this along is the need to understand the benefits of canopies

Indeed, our advancements in UVM research will not be kept within utilities and ROWs but benefit other industries and natural areas that can use them. For example, we can share information about enhanced IVM, strategic herbicide usage and sound environmental stewardship.

Overall, as we embrace modern UVM management and a more and more dynamic future, it is apparent that we as managers, practitioners and researchers need to improve multidisciplinary collaboration and continue to build on our research, science and innovation efforts.

By continuing to advance UVM and IVM along with implementing newer technology, our industry can be the incubator for biodiversity gains in vegetation, land stewardship and healthier communities.

DR. ANAND PERSAD is the director of the Research, Science, and Innovation (RSI) team at ACRT Services. He has an extensive background in arboriculture, invasive species, tree biomechanics, pollinator health, wetland restoration, avian studies and more. He is the research committee chair for the Utility Arborist Association (UAA), chair of the International Society of Arboriculture (ISA) Science and Research Committee and actively works with city, state and federal organizations in taking innovation and technology from development to implementation.