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Duke Prepares CEO Change This Spring
Lynn Good will retire after 11 years at the helm and nearly two decades with the company. A former Edison International CEO will take over as chair of the utility’s board. https://tdworld. com/55260703
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Engineering the Edge of the Grid
The same week I attended IEEE PES Grid edge in San Diego in January, wildfires were still raging in L.A. and even in San Diego County; and Donald Trump was being sworn in as the next U.S. president. Considering the location of the event and considering that the host utility SDG&E was dealing with wildfires in its own territory, wildfire mitigation was one of the main topics of discussion. The new administration was mentioned, but the flurry of activity that he set off when he took office had not yet happened. So, the discussions were more vague as far as federal policy was concerned.
The focus of this event was the ‘edge of the grid.’ Policy is crucial, of course, but this conference tended to center around what Wood Mackenzie defines as “an umbrella term to cover all the distributed hardware, software and business innovations that exist in proximity to the end user, rather than at the center of a traditional generation network. The grid edge can be leveraged by both customers and utilities to help decarbonize the grid and unlock new value streams while maintaining and enhancing reliability.” AI, electrification, sustainability and resiliency, and distributed energy resources took center stage (literally), as IEEE PES featured technology stages on the exhibit floor dedicated to these discussions.
Pacific Gas and Electric Company VP of T&D Engineering, stressed the dire need to attract the next generation of energy engineers.
All this discussion on energy innovation, security, reliability and sustainability is not going to do us any good if we don’t have the engineers to fulfill those needs.
Shay practices what she preaches: She mentioned PG&E’s programs that support high schools with scholarships, career exploration and financial education. PG&E’s Power Pathway program is a nationally recognized workforce development model that works through public-private collaborations.
And IEEE PES is one of the best organizations out there for recruiting and mentoring young engineers. IEEE’s TryEngineering that supports educators, engineers, technical professionals, and parents in inspiring the next generation of technology innovators. The goal is to provide high-quality lesson plans, resources, and programs that engage and motivate school-aged kids to explore engineering.
IEEE PES has also been good about hosting student poster competition sessions and catering to young engineers at all of its events. IEEE PES YP (Young Professionals), a subgroup of PES, publishes its own newsletter and holds special events throughout the year for new engineers.
San Diego Gas & Electric CEO Caroline Winn kicked off the event by acknowledging the California wildfires and utility response. She also discussed some of SDG&E’s innovative programs and mentioned that one huge challenge is keeping customer costs low while managing energy transition and reliability. SDG&E has been a leader in mitigating wildfires after battling them in 2007. After those fires destroyed 1,738 homes and consumed more than 368,316 acres (149,052 hectares), SDG&E started thinking about how best to design, engineer, construct and maintain the utility’s infrastructure against the threat of increasingly violent fires.
The utility upgraded over 18,000 wooden poles to steel and ramped up vegetation management, with expert arborists trimming and evaluating nearly half a million trees each year. To enhance fire risk decision-making, SDG&E developed a specialized tool called the Vegetation Risk Index and created a Wildfire Safety Community Advisory Council. And one of the most recent, cool initiatives was a state-of-the-art Fire Science and Innovation Lab.
The Next Generation of Engineers
One of the most dynamic and interesting conversations at the event was during the first super session covering change in the energy industry. Shay Bahramirad, IEEE PES president and
Shay also mentioned the trust that the public puts in engineers, which I thought was interesting since I am married to an electrical engineer. And to think about it, I trust him pretty well, not just because I am married to him. There is that but also considering his strong commitment to ethics and ability to solve problems.
She cited a nationwide survey that IEEE PES conducted at the end of last year that found two out of three people have positive opinions of power and electrical engineers; and three out of four people feel that power and electrical engineers are influential in addressing climate change. They trust engineers over energy companies or government agencies.
Energy affordability was the no. 1 energy-related concern with climate change or more extreme weather events coming in a very close second. This seemed to reflect the discussions at IEEE PES Grid Edge as well, with customer affordability while meeting reliability and decarbonization goals as one of the toughest issues facing utilities.
The conversations at IEEE PES Grid Edge made it clear that the energy industry is at a critical crossroads. With wildfires, climate change, and energy affordability weighing heavily on utilities and customers alike, innovation is essential—but so is the talent to drive it forward. After all, the best technology means little without the people who bring it to life.
Overlooking the Simplest Solution
There’s a great deal of attention on the need for more transmission lines worldwide, but the U.S. seems to be in the target’s center lately. My inbox has been getting a steady stream of emails about the dismal situation. The current interest stems from dismal predictions that hyperscale datacenters are sucking up all the available electricity. That’s usually followed by references to the simple fact that not many miles of high-voltage transmission lines have been built over the past decade and the datapoints supplied support it.
During my early years as a young engineer, I rubbed shoulders with many seasoned transmission engineers. They were strong advocates of that old saying, “There’s no substitute for wire in the air,” and it was usually possible to build needed power lines within a few years. Today, however, that simple solution
time ago, but the dialogue has expanded beyond the power delivery industry. It’s still a major topic on our industry’s websites and trade publications, but now it’s being covered in the mainstream mass-media.
Unexpected Support
Publications like Forbes, the Washington Post, the New York Times and others are talking about building new high-voltage transmission line along with reconductoring existing lines. This simple fix could double the capacity of the U.S. electricity grid in a relatively short period of time. One story pointed out most of our transmission lines were built using a conductor technology that dates back to the early 1900s and suggests it’s time to modernize.
Another brought up several compelling arguments supporting both new and reconducting transmission projects. Increased power transfer improvements lead the group. They emphasized reconductoring could be accomplished quickly because of the reduction in time required for construction and in many cases only a simple maintenance permit was required. It was also stated that typically there was less public input into a reconducting project. Afterall it’s an existing power line and wire is wire in the public’s eye.
has become a lot more complicated. With all permitting and regulatory requirements, it can take over ten years for that process, but what if there is a really simple solution?
Ingeniously Simple
There is, it’s called reconductoring. If done with modern advanced conductor technologies, significant capacity can be added to the transmission system using a simple method. Reconductoring with innovative wires is ingeniously simple –take down the old conductor, install the new advanced wires, and take advantage of the increased power capacity.
These modern wires are lighter and stronger than those they replace, and they operate at higher temperatures with less sag. Depending on the situation, the reconductored power line can be operated at two to four times the power capacity of the old line. There is one caveat that is hard to meet in some circumstances. The utility has to be able to take the heavily loaded existing line out of service long enough for the replacement of its conductor.
We discussed advanced conductors to some extent in last August’s “Charging Ahead” (see “Don’t Understand Wire Technology”). Since that chat, there have been some developments that warrant revisiting the topic. It seems like such a short
With all this positive coverage, I have noticed an increase in regulatory activity in the area of advanced conductor technology, you might say it’s having a positive impact with federal and state policy makers too. Heck, I saw one news report about a bipartisan bill that was introduced in congress supporting advanced conductors to improve grid capacity. Another surprising story was about the National Association of Regulatory Utility Commissioners. They went on record approving a resolution recognizing the importance advanced conductors and grid-enhancing technologies. They also urged Congress to fund advanced transmission technologies.
There are also positive things to report grid wise. CTC Global reports their ACCC (aluminum conductor composite cores) advanced conductor has been installed in 67 countries with roughly 124,000 miles of the conductor in the air. Another interesting announcement came from BloombergNEF.
They announced their 2024 Pioneers Award was conferred on TS Conductor. Its AECC (aluminum encapsulated carbon core) won based on its advanced conductor’s ability to relieve bottlenecks in the deployment of clean power. TS Conductor noted its AECC is a direct substitute for ACSR using the same tools and installation procedures.
Advanced conductor technologies are gaining acceptance with utilities and grid operators. Reconductoring with advanced conductors can put a huge dent in the transmission capacity shortage, but some say it’s too risky. Is it riskier than not using them?
Gene Wolf
Smarter Tech = Smarter Grid
Integrating AMI with AI is moving AMI technology forward to its next generation.
Are we getting accustomed to the smart equipment and apparatuses that make up the smart grid? Are we indifferent about amazing systems that monitor, control and manage the power delivery system? It’s easy to be either way. Digital technology has been with us for decades. Each generation of these smart grid systems and schemes have brought improvements and increased capabilities. Smart grid technology has been modernizing the power grid’s infrastructure with a virtual infrastructure.
This virtual infrastructure is powered by equipment with sensors, transducers, monitors and lots of other digital electronics. They generate big-data that has brought about asset management systems, load management systems, demand management systems, etc., which has led to an infrastructure with awareness. Smart grid technology has matured and advanced. With each advancement, the technology has been revised and upgraded, and new applications have been able to leapfrog established technologies.
The result has been advancements that are astounding, and now that artificial intelligence (AI) has arrived the whole process has quickened, but there is a downside. How do we justify replacing the existing technologies that are no longer suited for their role in an industry that’s risk-averse and highly regulated? There are many smart grid applications that fall into this category, but let’s look at one in particular, smart meter technology.
A Valuable Tool for the Smart Grid
It really started becoming important to the power delivery industry as we prepared for the twenty-first century. Many of us began learning about advanced metering infrastructure
(AMI) technology shortly after the millennium happening. Initially, it seemed like just another electronic meter, but the integration of ICT (information and communication technology) made AMI 1.0 unique.
It allowed two-way communication between smart meters and a central system. It also improved the quality of power consumption data. About the same time AMI had our attention, smart electronic devices were being adopted by our customers. IoT (Internet of Things) technology was also on the scene, and the behind-the-meter (BTM) world was getting wired. This connectivity started changing things beyond the edge of the grid by giving customers remote control and monitoring abilities. Residential, businesses, and industries took advantage of the applications. AMI 1.0 gave the utilities access to the BTM environment, which changed both sides of the meter for the better.
About twenty years later AMI 1.0 was showing its age, its internal battery was at the end of its life and its error rates were climbing. Other issues suggested it was time to upgrade the application. Vendors quickly pointed out that AMI’s next generation was available for deployment, AMI 2.0 had new features and more capabilities that made the smart meter smarter.
It was time to trade up and start installing AMI 2.0. In a world where big-data was abundant, AMI 2.0 would better fit, with superior accuracy, It was also able to utilize what the customer had implemented. AMI 2.0’s networking offered utilities much needed advancements like high resolution data, peer to peer communications, edge computing, embedded computing power, etc. The industry listened and AMI metering became indispensable for modernizing the power grid.
Yevhen Prozhyrko / Shutterstock
By the end of 2023 (last figures available), smart electric meter penetrations had reached a 43% of the global electric meter market. That was somewhat over 1.06 billion units installed according to reports. Current projections indicate this technology has continued growing with higher penetrations and large numbers of installations, but there is a small hitch. Those 1.06 billion smart meters represent a jumble of technological metering arrays.
Some are pre-AM (i.e., electronic meters), others are AMI 1.0, and the rest are AMI 2.0. Adding to the challenge, vendors offered a wide selection of models ranging from economy budget deals to top of the line versions. That means many of those in-service smart meter systems offer limited value to utilities and grid operators, but they’re still using them. Many utilities are aware of the situation and are planning replacements, but that has started discussions about which ones will be replaced. There’s also the question, is there another choice?
Foggy Crystal Ball
Obviously the AMI 1.0 vintage are the chief candidates for replacements, but also under discussion is what to replace them with and when to do it. The AMI 2.0 systems of today have improved their performance and operability over those that were initially deployed. Various manufactures are discussing the next generation of AMI. A few have implied their systems incorporate features consistent with the next-gen’s, AMI 3.0, functionality.
CULTIVATING SUSTAINABILITY
AMI 2.0 evolution has been progressing since its initial implementation. The latest AMI 2.0 has improved its metering accuracy, its edge computing capabilities within the meters have been upgraded. The real-time interaction between customers and the utility has been advancing. In addition, AMI 2.0’s ability to push out updates for its software and firmware gives it an advantage. Could it be that AMI 3.0’s much anticipated appearance is already happening?
It certainly appears that the shift toward AMI 3.0 is underway. It’s not hard to find vendors advertising that their latest AMI platforms are enhanced by AI, which implies the AI feature is a minor upgrade. Nor is it unusual to find news releases saying their AMI systems incorporate AI as an integral part of its design, which fits the next level or AI-powered applications. That’s the heart of defining what AMI 3.0 is and how it works. It’s only natural for suppliers to say their AMI systems have next-gen features, and these statements are all valid. This is the usual progression as one technology evolves into the next.
Bear in mind, however, there are degrees of AI immersion into the next-gen AMI, which leads to discussions about potential improvements and additional features for AMI. Understanding AI will be crucial in shaping the future of AMI technology, just as it has been for many other fields. The combination of AI and AMI is improving AMI’s operational efficiency by being able to handle more data and datasets than previous AMI versions. It can also take advantage of AI’s ability
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CHARGING AHEAD
to identify patterns, helping utilities recognize network issues, problems, and difficulties when the data is coming from an assortment of sources.
AMI with AI Upgrades
The simplest level of AI upgrades are the AI-enhanced applications, which primarily expand the overall system. The meters’ ability to communicate with each other can create innovative ways with a little help from AI improving the management of distribution networks in addition to improved operations and maintenance. Using AI-enhanced edge computing can send pre-processed data to the centralized cloud-based data analytics system instead of raw data, saving critical time.
Another AI-enhanced AMI 3.0 application assists the peer-topeer functions to be more efficient. One example is automatic outage detection that can recognize distribution network problems in real-time. Many AMI meters have GPS (global positioning system) abilities and AI-powered AMI 3.0 uses it to establish exact location of problems, isolate them, and dispatch a crew without any human intervention.
The second level of AI upgrades is the AI-powered AMI 3.0 application. It uses AI as a key component of the partnership. Imagine a utility having thousands of meters transmitting bigdata to utilities daily. AI-powered AMI 3.0 integrates real-time
The third level of AI upgrades is the AI-driven AMI 3.0 application, which uses AI as the predominant force behind the AMI’s functionality. AI-driven AMI 3.0 is the perfect application for addressing the growing issues associated with bidirectional power flows produced from an assortment of distributed energy resources BTM. This application combines big-data from multiple databases and datasets to better control these bidirectional power flows, balancing sources with loads more efficiently.
An exciting AI-driven AMI 3.0 application being discussed can identify where vegetation is hitting power lines. Without going into a lot of detail, it uses the meter’s peer-to-peer function as well as GPS. By analyzing small variations in voltage and current waveforms it’s possible to determine that arcing is taking place when the vegetation hits the power line and GPS gives its location. This could be extremely valuable in preventing conditions that lead to wildfires.
The potential for AI upgrades to AMI are limitless and it’s a pretty good bet AMI 3.0 isn’t too far in the future. Looking at the examples above, there is a good argument that AMI 3.0 it’s already here, but there’s so much taking place that it hasn’t been labeled yet. The more we look into AI the harder it is not to see what a positive force it is when it comes to modernizing the power delivery system. Technological advancements are going to be uncomfortable and disruptive, but after using them, would you really want to go back? It’s the future, heck Wendy’s is using AI in their drive thru and both sides of the speaker
MISO Selects Ameren to Build Critical Grid Infrastructure Projects in Missouri, Illinois and Several Midwest States
The Midcontinent Independent System Operator (MISO) has selected Ameren to build multiple critical energy infrastructure projects worth approximately $1.3 billion to transmit clean, reliable energy to distribution grids in Missouri, Illinois and several Midwest states.
The projects are part of a portfolio of energy infrastructure investments under MISO’s Long-Range Transmission Plan.
The energy corridors identified in MISO’s Tranche 2.1 portfolio will work along with Ameren’s current transmission system to enhance reliability and resiliency for customers while supporting economic development. Increasing access to diverse energy resources across the MISO footprint will ensure customer affordability and access to clean energy for many people.
Ameren plans to bid on other infrastructure projects in Tranche 2.1 where the company’s capabilities and current resources are expected to improve reliability, resiliency and affordability for customers.
“As demand for reliable energy increases, it is imperative that we strengthen the transmission system to utilize diverse energy resources across the Midwest to support the needs of our residents and businesses,” said Shawn Schukar, chairman and president of Ameren Transmission Company of Illinois, a subsidiary of Ameren Corporation. “The energy delivered by these projects will boost reliability and enable the bi-state region to compete for economic development opportunities, including the expansion and relocation of energy-intensive industries.”
Entergy Louisiana Invests $10 Billion to Power Meta’s Data Center in Richland Parish
Entergy Louisiana plans to invest in modern, efficient generation facilities and robust transmission infrastructure to support the region and Meta’s data center, featuring a $10 billion investment in Richland Parish.
The project intends to regenerate Northeast Louisiana’s economy, creating jobs, strengthening infrastructure and driving significant economic growth in the region, based on this project and other following projects.
Meta’s data center will be built on the Franklin Farm mega site, a more than 1,400-acre certified site, in Richland Parish, Louisiana, having proximity to existing utility infrastructure and
robust transportation routes. Entergy Louisiana marketed the site through its Site Selection Center and GoEntergy platforms, highlighting its potential for large-scale developments.
Meta has announced their significant investment and associated impacts for their new artificial intelligence-optimized data center.
During construction, Entergy Louisiana projects will provide economic benefits and create:
• 1,500 to 1,800 construction jobs for the new advanced generation units being constructed
• 3,500 to 5,000 construction jobs for substation and transmission investment
Private-Equity Firm Invests in Utility Services Venture East Coast Power
A private-equity investment firm has acquired a majority stake in a young utility services company aiming to become a national player.
Terms of the investment by Alvarez & Marsal Capital Partners in East Coast Power LLC—which markets maintenance, repair, upgrade, restoration and emergency response work—aren’t being disclosed and company representatives said they aren’t yet ready to discuss their plans in detail. But they did they are aiming to grow East Coast Power, which was founded in 2023 by Darren Donohue and is based in Albany, both organically and through acquisitions, including in parts of Canada.
“We are excited to take this next step in bringing Darren and his team into our portfolio,” Ryan McCarthy, an Alvarez & Marsal partner, said in a statement. “The
• 44 permanent jobs
Richland Parish will also benefit from this development. To support the Richland Parish Data Center, as well as broader economic development in the state and growing its customer base, Entergy Louisiana will:
• Build three combined-cycle combustion turbines with a combined capacity of 2,260 MW, two of which will be in Richland Parish
• Construct two Entergy-owned substations and six customer-owned substations
• Install nearly 100 miles of 500kV transmission lines and eight new 230kV transmission lines
• Upgrade existing infrastructure, including a substation near Sterlington
The new generators are expected to
company is addressing the mission-critical issue of North America’s power grids, which require significant infrastructure investments and reliable services from companies like ECP to effectively address ever increasing power demands.”
Before starting East Coast Power, Donohue was president and CEO of D&D Power Inc., an electrical contractor that was acquired in 2018 by BHI Energy. Donohue stayed with BHI until mid-2023.
be operational between 2028 and 2029 depending on regulatory approval.
Revenue from Meta will offset the costs associated to make service available to the company’s data center and the region. Meta will also share in the future cost of providing service like other customers including Formula Rate Plan costs, securitized storm costs and resiliency costs, this is expected to reduce costs that existing customers would otherwise pay by more than $300 million.
Additionally, Meta will contribute to Entergy’s The Power to Care program, matching $1 million in shareholder contributions to assist older adults and individuals with disabilities in paying utility bills.
Initially, the new generators will support the ability to utilize 30% hydrogen
The utility infrastructure services market East Coast Power is looking to help consolidate is huge and growing: Analysts at S&P Global recently said that U.S. utilities’ capital budgets will grow to nearly $200 billion annually in the next three years compared to “only” $144 billion in 2022. And Goldman Sachs researchers say global spending on net-zero energy transition projects is roughly $3 trillion annually.
The market also is very fragmented: In the prospectus for its initial public offering last year, Centuri Holdings Inc. executives cited ENR and S&P Global research stating that the five largest utility service providers—which include Quanta Services Inc. and Centuri—claimed only 18% of the industry’s revenues in 2022.
— Geert de Lombaerde
co-firing and, through future upgrades, the ability to transition to 100% hydrogen and incorporate carbon capture and sequestration technology.
Meta will also help fund CCS technology at an Entergy power plant in Lake Charles as well as 1,500 MW of new solar and storage resources, supporting Entergy Louisiana’s efforts to add 3 GW of solar energy.
The companies will also explore nuclear energy as a future power supply option alongside renewable sources like solar and wind. The effort includes researching conventional nuclear technologies, supporting small modular reactors and potential upgrades to enhance the output of existing nuclear plants in Southeast Louisiana.
PG&E Provides Assistance to Southern California Utilities in Response to Devastating Wildfires
Pacific Gas and Electric Company (PG&E) has deployed more than 100 employees to Southern California to assist the Los Angeles Department of Water and Power (LADWP), Southern California Edison (SCE), and Southern California Gas Company (SoCalGas) in addressing the impacts of destructive wildfires.
Two PG&E Blackhawk helicopters are supporting CAL FIRE’s aerial firefighting operations, dropping hundreds of gallons of water to help control the flames. On the ground, PG&E’s Safety and Infrastructure Protection Teams (SIPT) are working to protect critical electric infrastructure by clearing vegetation and treating utility poles with fire retardant. The 25 SIPT engines, staffed by two-person crews, are
assisting LADWP by performing targeted efforts to minimize potential damage to power lines and poles.
“The goal is to save the infrastructure and keep the poles standing,” explained Todd Tindill, a SIPT Lead based in Chico, California. “If the fire comes through, we aim to mitigate or prevent damage to the poles.”
PG&E Electric General Construction crews are assisting with infrastructure repairs to help restore power for LADWP
and SCE customers. Additionally, over 130 PG&E employees, including more than 100 Gas Service Representatives, will travel to the Los Angeles area to provide support to SoCalGas.
The wildfires, driven by powerful Santa Ana winds and dry conditions, have caused significant destruction across Southern California. Since Tuesday, at least seven fires have damaged or destroyed more than 10,000 structures, further highlighting the urgency of coordinated response efforts.
Eversource Expands Spending Plans Through 2029
Eversource Energy has increased its five-year capital plan to $24.2 billion through 2029, adding $2 billion in investments. Transmission and distribution will see an extra $923 million and $601 million, respectively, with spending peaking in 2026. CFO John Moreira said investments could grow by another $1.5 billion to $2 billion if opportunities arise.
Key projects include $3.6 billion for Massachusetts, $1.8 billion for Connecticut, and $1.4 billion for New Hampshire. Massachusetts’ $1.8 billion Greater Cambridge Energy Program will feature the nation’s first fully underground substation.
— Geert de Lombaerde
Entergy Veteran Named Next CEO of Algonquin
The directors of Algonquin Power & Utilities Corp. have chosen a former senior Entergy Corp. executive to be CEO of the company as it begins life as a pure-play regulated entity.
Rod West will take the helm at Ontariobased Algonquin March 7, taking over from Chris Huskilson, a board member and
Before that, activist investor Starboard Value LP had challenged the board’s strategy and negotiated two seats at the table for its representatives. Starboard’s push had come in the wake of the abrupt exit of then-CEO Arun Banskota in August 2023 and the collapse four months prior of Algonquin’s plan to pay about $2.6 billion
Investors appeared to approve of West’s hiring: Shares of Algonquin (Ticker: AQN) were up nearly 4% to about $4.50 in midday trading Jan. 31. Over the past six months, however, they are still down more than 25%, a slide that has trimmed the company’s market capitalization to about $3.4 billion.
Transmission and distribution utilities in Brazil address increasing telecommunications demands to ensure an efficient, reliable and secure grid.
By EDUARDO POLVANI CAMPANER
Brazil’s electricity transmission grid is expanding and evolving, becoming increasingly digital over time as a result of improved operational practices and enhanced grid performance. The sector is governed by the national electricity agency, Agência Nacional de Energia Elétrica (ANEEL), and operated by the national system operator, Operador Nacional do Sistema (ONS). The ONS establishes network proceedings that define the rules all assets belonging to the operational network must follow — specifically those with voltages equal to or above 230 kV, referred to as the “basic grid.” ANEEL provides regulations and oversees the auction process for expanding the transmission grid after the energy research office, Empresa de Pesquisa Energética (EPE), conducts studies to identify where expansion is needed.
The winning bidder is determined by the lowest proposed annual allowed revenue, or receita annual permitida (RAP). The concession period for a section of the transmission grid is 30 years, exceeding the expected lifespan of electronic equipment. Consequently, the successful contractor must replace electronic components at least once during the concession period.
Every new transmission line must include an optical ground wire cable (OPGW) as its grounding cable. Introduced in the late 1980s, OPGW cables are widely used in Brazil because of their superior reliability compared to other types of fiber cables, including buried ones. They form the backbone of the country’s electric grid’s telecommunications media.
If the contractor opts to operate assets remotely through a remote control center, it must comply with the telecommunications
requirements outlined in the network proceedings. Tele-assistance encompasses remote supervision and control, voice communication and operational video surveillance, enabling substations to be operated remotely. Substations must have two data and voice channels on different routes, with a combined annual availability of 99.98% — classified as class A channels. The overall system, including channels, supervision and controls, must achieve an annual availability of 99.95%. Operational cameras must verify the disconnector switch status (opened, closed or intermediate) after a maneuver to prevent reporting errors, manual confirmation by crews, asset damage and accidents.
Transmission Utilities
All transmission lines in the basic grid must have two dedicated tele-protection channels using different communication media and total redundancy, including end-to-end electronic systems. For example, one channel may use an OPGW cable, while another might use carrier waves on high-voltage lines. However, carrier waves cannot support differential tele-protection when required, creating challenges for contractors needing a second fiber path.
In cases where high-voltage lines are sectioned, contractors may need to share or exchange infrastructure with others, adhering to the network proceedings and criteria established by the line owner. These negotiations can be complex, especially when mutual interests in channel exchanges are lacking or when renting unused fibers or communication channels is necessary. In such cases, the utility owning the desired channel must hold a multimedia license from the national telecommunications agency, Agência Nacional de Telecomunicações (Anatel).
Oscillography is another mandatory service. These devices operate independently of protection relays, monitoring voltage and current signals to analyze faults and locate their origins. The recordings are transmitted via specific channels to the remote control center for fault investigation by the protection team. Transmission utilities also use traveling-wave technology to improve fault location precision, which requires telecommunications channels to exchange information between the line’s terminals.
Utilities’ remote control centers must share operational equipment status and alarms with the ONS via two redundant links in different regions of the country (for example, Florianópolis and Rio de Janeiro). For enhanced frequency synchronization and
Sunset over a transmission line.
Photo by Daniel Kolm.
Tele-assistance encompasses remote supervision and control, voice communication and operational video surveillance, enabling substations to be operated remotely.
Photo by Eduardo Polvani Campaner.
disturbance diagnostics, assets operating at 500 kV or higher must include phasor measurement units (PMUs) on the line terminals and send the data to two ONS sites in Brasília and Rio de Janeiro with a maximum delay of 500 msec.
In addition to complying with these regulatory requirements, utilities deploy corporate services to improve operational quality and security. It is strongly recommended to separate operational and corporate networks by using distinct IP network addresses. Corporate services include voice communication, email, internet access, and enterprise resource planning (ERP) systems, typically delivered through LAN cables or Wi-Fi networks. Maintenance teams favor Wi-Fi for its reliable communication coverage across substation perimeters for both voice and data. However, Wi-Fi signals can extend to unintended areas, creating vulnerabilities intruders could exploit. Voice communications with frontline workers must be recorded for compliance purposes.
Cybersecurity is a critical concern in Brazil’s utility sector. It has become a mandatory component of network proceedings for remote control centers and remote substations. Regulations now require firewalls, intrusion detection systems (IDS), security operations centers (SOC), endpoint defense solutions (EDR), access control mechanisms and identity management protocols.
Auxiliary services are designed to power these electronics, and contractors must meet specific requirements at transmission substations. These include having two independent power sources via the tertiary winding of transformers, feeding two independent rectifiers, each with a battery capacity of at least 10 hours as well as a 30% surplus for future expansion. Rectifiers must also be monitored by the control center to detect critical alarms or battery discharges. Additionally, an external generator must serve as a third power source in case of disasters.
Failure to comply with ONS rules can result in penalties ranging from improvement recommendations and fines to mandatory local substation operations, significantly increasing operational costs. Labor laws also mandate all workers, including linemen, have access to communication channels while working on the grid. Utilities often use satellite phones and very high-frequency (VHF) systems for this purpose, with all communications recorded for investigation purposes.
Distribution Utilities
Distribution utilities face similar challenges, particularly in automation, smart metering, and loss management. These challenges also include remote substation operations and tele-protection channels, although the requirements are less stringent than those for transmission utilities. In addition to the telecommunication systems previously mentioned, these utilities also implement,
Bay line optical ground wire cable (OPGW) with splice box. Every new transmission line must include an OPGW as its grounding cable. Photo by Eduardo Polvani Campaner.
operate and maintain mesh, LTE/4G, 5G and private radio networks with dedicated frequencies exclusively for utility use. Unlike transmission expansion, which occurs through auctions, distribution expansion is driven by strategic investments recognized during each tariff review by ANEEL.
Recent expansions in smart metering projects have reduced the need for manual readings, improved fault detection and enhanced energy quality monitoring.
Recloser automation is another critical issue for distribution utilities. It enables remote control to restore electricity, reducing the distances teams must travel to inspect a line. It also monitors the frequency of reclosures, which often indicate vegetation interference, and remotely manages load disconnection when the network is overloaded, especially during summertime.
Loss management involves comparing energy measured by residential meters with energy delivered by a distribution transformer to identify energy theft in specific areas. ANEEL sets goals for distribution utilities to detect and address such situations.
Smart metering, recloser automation and loss management are entirely dependent on telecommunication services deployed across the grid and managed by utility professionals. Managing these services requires expertise in various protocols, equipment, network architecture, spare parts and employee training.
However, utilities face significant challenges due to the rapid depreciation of equipment and fast-paced evolution of technology. Manufacturers frequently update their product lines,
Pylon with an operational camera installed. Operational cameras must verify the disconnector switch status after a maneuver to prevent reporting errors, manual confirmation by crews, asset damage and accidents.
Photo by Leandro da Silva.
Graphics for Harsh Environments
Kits
Warning Signs. • Roller for Adhesive Activation.
Notice Signs. • Substation ID Signs.
cables are widely used in Brazil because of their superior reliability compared to other types of fiber cables, including
ones.
creating issues with equipment reaching end of life and reducing the availability of spare parts. The depreciation rate is regulated by ANEEL’s manual on the electricity sector, which requires constant revisions to align with the fast pace of technological advancements. Operation and maintenance of a diverse range of manufacturers and products is another major hurdle. Telecommunications control centers typically feature numerous screens from different manufacturers, reflecting the field’s diversity. This situation necessitates more training programs and skilled employees.
Commonly used in remote areas, radio link networks and their repeaters also face challenges. These include increased costs due to vandalism, the need for environmental licensing renewals and team displacement over long distances.
Though robust, OPGW cables are vulnerable to damage from electrical discharges, weather conditions and mechanical stress, which can degrade their optical transmission capacity. Some years ago, Brazilian OPGW cables experienced fiber ruptures caused by insufficient fiber length to accommodate contraction and expansion due to temperature fluctuations. Nonetheless, OPGW cables remain the most reliable telecommunications medium for transmitting digital services and are widely used as the grid backbone.
With a technical lifespan of 40 years, OPGW cables are preferred not only by utilities but also by telecommunications companies because of their superior availability compared to fiber cables attached to poles or buried underground. This preference was addressed in the joint Telecommunications and Energy Agencies Resolution No. 01/1999 and ANEEL Resolution
An optical ground wire cable (OPGW) with splice box. OPGW
buried
Photo by Eduardo Polvani Campaner.
1,044/2022, which regulate infrastructure sharing between the two sectors, leveraging the unused capacity of utilities to enhance communication services for the public.
Whenever contractors upgrade electronic equipment or replace critical assets like circuit breakers, capacitors or reactor banks, or power transformers, they must adhere to the latest network proceedings, including the electronics involved.
Satellite links play a vital role in expanding the electricity grid, particularly in delivering communications to remote substations. In cases where the primary medium is OPGW cable and a secondary fiber medium is unavailable, satellite links are used to meet tele-assistance requirements. However, without a second fiber medium, teleprotection services are limited by distance zones when high-voltage carrier lines serve as the secondary medium.
Keeping up with Requirements
Despite these challenges, Brazilian transmission and distribution utilities have consistently implemented the required telecommunications solutions. To date, no project has been canceled due to noncompliance with telecommunications requirements in Brazil, although unexpected cost increases are common for contractors that lack construction experience.
Managing assurance contracts, maintenance orders as well as statistics, analyzing failure indicators, handling electronic equipment logistics, monitoring link and service availability, evaluating equipment lifespans, and coordinating replacement and expansion projects are ongoing challenges for telecommunication teams and control centers. Telecommunication equipment is fully depreciated after 15 years under regulatory norms but often lasts up to 20 years. In contrast, advanced technological solutions, such as computer servers and IT hardware and software, typically require upgrades every five years on average.
Large data transmission capacity is crucial for grid digitalization, requiring an evaluation of the most effective media to ensure desired bandwidth, guaranteed availability and long lifespan.
Despite regulatory challenges, the framework is widely regarded as a fair and equitable way to ensure consistency among industry players, whether competing in auctions or upgrading systems.
As grid digitalization accelerates—with more advanced protection and control systems, increased data demands from corporate tools, heightened cybersecurity requirements, realtime asset monitoring, operational video surveillance, substation-to-control center voice communications and mobile communications—greater bandwidth availability will become essential. Consequently, the challenges for telecommunication professionals, manufacturers and regulatory agencies in the electricity sector are expected to increase significantly in the coming years. Proactive measures and close collaboration will be crucial to successfully navigating these challenges, ensuring a reliable, secure and efficient grid for the future.
EDUARDO POLVANI CAMPANER (epcampaner@gmail.com) graduated with an electrical engineering degree from the Federal University of Santa Catarina and a postgraduate degree in safety engineering from Faculdade Estácio de Sá. He began his career as a commercial consultant for large clients in the telecommunications sector and then worked as a telecommunications engineer at Celesc Distribuição. With 18 years of experience in the electricity sector, Campaner currently works as executive manager of automation, protection and telecommunications at Eletrobras CGT Eletrosul. He recently completed a MBA degree in the electricity sector at Faculdade Getúlio Vargas.
In cases where high-voltage lines are sectioned, contractors may need to share or exchange infrastructure with others, adhering to the network proceedings and criteria established by the line owner.
Photo by Leandro da Silva.
Three Focus Areas to Build a Safer Network
NYSEG and RG&E share strategies for reducing damage to underground utilities, which led to a 39% reduction in fiber installation damages in New York.
By JASON MARSH, NYSEG and RG&E
With a steadfast commitment to safety and innovation in damage prevention, New York State Electric & Gas Corp. and Rochester Gas and Electric Corp. have achieved remarkable progress, including a notable 39% reduction in fiber
installation-related damages in 2023.
Continuously striving to stay at the forefront of industry developments, their strategies for minimizing damage to underground utilities were informed by the 2023 Common Ground Alliance (CGA) Damage Information Reporting Tool
(DIRT) report and aligned with CGA’s 50 in 5 industry challenge.
Damage Prevention Programs
Subsidiaries of Avangrid, New York State Electric & Gas Corp. (NYSEG) and Rochester Gas and Electric Corp. (RG&E)
Heavy equipment and work crew during bridge installation. New York State Electric & Gas Corp. and Rochester Gas and Electric Corp. has made progress in safer digging.
Photos courtesy of NYSEG and RG&E.
operate an extensive infrastructure, including approximately 43,900 miles (70,650 km) of electric distribution lines and 5600 miles (9012 km) of transmission lines as well as more than 19,000 miles (30,578 km) of natural gas distribution pipelines and 125 miles (201 km) of gas transmission pipelines. Protecting this vast infrastructure is paramount to ensuring public safety and maintaining reliable energy delivery.
NYSEG and RG&E leverage advanced technology to monitor their systems 24/7. Their damage prevention efforts consist of three key elements:
• Aerial and ground inspections — Regular inspections ensure the early detection of potential issues. These inspections involve drones, helicopters and on-the-ground surveys to identify vulnerabilities before they escalate into significant problems.
• Maintenance programs — Comprehensive upkeep supports safe and reliable operations. Proactive maintenance reduces the likelihood of system failures and ensures compliance with regulatory standards.
• Membership in UDig NY — Partnering with the state’s one-call notification system streamlines excavation coordination, ensuring clear communication between stakeholders and reducing the risk of accidental utility strikes.
The utilities also collaborate with regulators and industry groups to adopt these forward-thinking initiatives in pipeline safety, inspection and maintenance.
Compliance and Education
NYSEG and RG&E’s damage prevention programs align with New York Department of Public Service’s 16 NYCRR Part 753, the code rule for underground facility protection. Although not enforcers of the code rule, the utilities emphasize education to ensure contractors and homeowners understand their responsibilities under the law. Encouraging 811 calls before digging is central to their outreach efforts.
Educating contractors and homeowners about safe digging practices involves more than distributing brochures. NYSEG
and RG&E conduct community workshops, training sessions and awareness campaigns tailored to various audiences. For contractors, these sessions often include demonstrations of safe excavation techniques and the importance of marking underground utilities. Homeowners are taught to recognize the potential hazards of digging, even for seemingly minor projects like planting shrubs.
The 50 in 5 Challenge
CGA’s 50 in 5 industry challenge aims to reduce damages to critical underground utilities by 50% within five years. This initiative targets three focus areas:
• Effective and consistent use of 811 — Promote awareness and adherence to the one-call system
to ensure excavation activities are preceded by proper utility locating.
• Key excavator practices — Implement standardized best practices during excavation, such as proper equipment use, hand-digging near utility lines and maintaining clear communication with utility locators.
• Accurate and timely utility locating — Ensure precise and efficient marking of underground facilities. Advanced technologies, such as ground-penetrating radar and geographic information system (GIS) mapping, are increasingly used to enhance accuracy.
These focus areas address more than 76% of all utility damages, according to
Mismarked gas main damage.
CGA’s 2023 DIRT Report. By integrating these principles into their operations, NYSEG and RG&E have significantly reduced gas hits during fiber installations.
A Coordinated Approach
The rapid expansion of fiber networks presents unique challenges for damage prevention. In Northwestern New York, NYSEG and RG&E partnered with Bermex Inc., USIC LLC, UDig NY and major
fiber companies to establish preinstallation walk-throughs and on-site coordination. This proactive approach has driven a 39% reduction in damages during fiber installations.
These walk-throughs are not limited to simple site inspections. They involve collaborative planning sessions during which utility representatives, contractors and subcontractors identify potential risks and develop mitigation strategies. For instance, fiber installation projects often require excavation in areas densely populated with gas pipelines and electrical lines. By addressing these challenges upfront, the utilities have avoided many potential accidents.
Lessons From DIRT
The 2023 CGA DIRT report underscores the importance of the following:
Excavation best practices: Failure to call 811 and insufficient site preparation account for many damages. NYSEG and RG&E’s focus on preinstallation coordination directly addresses these issues.
Technology integration: Advanced tools like global positioning system (GPS) mapping and augmented reality improve utility locating accuracy. By incorporating these technologies, NYSEG and RG&E have enhanced their ability to detect and mark underground assets.
Stakeholder collaboration: Unified efforts among utilities, excavators and regulators enhance safety outcomes. The success of the 50 in 5 challenge relies heavily on fostering such partnerships.
Teamwork Drives Safety
To improve NYSEG and RG&E’s damage prevention efforts, significant challenges had to be addressed, such as high volumes of dig tickets, recurring damages, contractor disengagement, high turnover and the lack of a unified team approach. A key milestone was the 2023 partnership with Bermex, a company with a proven history in metering services, to enhance the damage prevention division.
Utility management prioritized a collaborative and safety-first mindset across the team. Supported by four supervisors, the program’s efforts focused on creating a safe excavation environment. Bermex damage prevention drivers have conducted thorough investigations and provided essential education to both contractors and homeowners on safe digging practices.
This shift toward proactive teamwork and robust communication has resulted in a significant reduction in damages.
Expanded Public Awareness
Educating homeowners about safe digging practices is equally vital. Many homeowners are unaware that activities as simple as planting a tree require an 811 call. Through community outreach and clear messaging, NYSEG and RG&E address this knowledge gap.
Awareness campaigns often include real-life examples of utility strikes and their consequences. By illustrating the potential dangers of unsafe digging, these campaigns drive home the importance
Above: An inspection for gas main damage during a directional drilling operation.
Left: Steel gas service damage.
of calling 811. Additionally, NYSEG and RG&E leverage social media, local media outlets and public events to reach a broader audience.
Blueprint for Safer Networks
The reduction in fiber installation damages achieved by NYSEG and RG&E showcases the power of collaboration, innovation and a steadfast commitment to safety. As utilities across the U.S. face similar challenges, NYSEG and RG&E’s success serves as a model for building safer, more resilient networks. Their efforts provide a compelling blueprint for others to follow, demonstrating that through strategic partnerships and staying abreast of the latest industry developments, substantial improvements in infrastructure protection can be achieved.
JASON MARSH is a damage prevention supervisor at NYSEG and RG&E. A U.S. Air Force veteran and New York state-licensed water distribution operator, Marsh holds a bachelor’s degree in business administration from American InterContinental University.
Strategies to Control Grid-Edge Devices
Three case studies share different strategies to control and optimize electric vehicles and distributed energy resources at scale at the grid edge.
By SHISHIR SHEKHAR, Landis+Gyr, and ROB HOVSAPIAN, NREL
Electric utilities globally are being compelled to upgrade their existing distribution and transmission systems because of the rising demand for load by residential, commercial and industrial customers. For example, the industry is seeing 6-MW spot load demand by 100% electric bus fleet depots in megacities such as New Delhi, India. In addition, customers and regulators increasingly are concerned about the reliability and resilience of distribution systems, making additional investments likely to meet these expectations. However, the cost of implementing these system upgrades may not be justifiable in the short term, considering the short duration of peak loads or low frequency of extreme events and outages. Therefore, nonwire alternatives (for example, distribution energy storage systems)
A double-decker electric bus on a street in Mumbai, India.
Faroe Islands.
and microgrids are becoming more attractive for utilities and their customers.
As these grid edge devices scale from hundreds to thousands to millions, they are more challenging and difficult to connect and control in near real time. Controller hardware in the loop (CHIL) and advanced metering infrastructure (AMI) also play a role in the evolution of the power grid, especially in distribution systems with large renewable energy integration and adoption of electric vehicles (EVs), thereby reducing the risks of implementing advanced distributed energy resource (DER) control technologies.
The grid edge consists of different types of residential, commercial and industrial customers, including EV fleets. They deploy different types of flexible loads and DERs, such as manufacturing machines, heat pumps, pool pumps, light-duty and heavy-duty vehicles, solar and battery storage. Depending on their operational requirements and use cases, the control strategies for these loads and DERs may be very different. Following are several case studies on different strategies being used around the globe to scale and control grid edge devices.
The Faroe Islands
The North Atlantic may not be the most straightforward starting point for achieving 100% carbon-neutral electricity production by 2030. However, an overhaul of the energy landscape on Faroe Islands and an innovative approach to energy management is putting that target within reach. With a historical reliance on oil-fired power plants, the islands are increasingly being powered by wind, hydropower and, soon perhaps, even tidal energy. The electric utility serving the islands, SEV is implementing a virtual power plant (VPP) solution to enhance grid flexibility — using EVs as a core asset for load balancing and relying on renewable energy when it is available.
The shift to renewable energy presents challenges and opportunities for SEV. One challenge is maintaining grid stability with intermittent energy sources like wind and solar. This has led the Faroe Islands to pursue a strategy of complementary energy sources, such as wind, solar, hydro and tidal energy. Energy storage solutions, such as battery systems and hydropower dams, also play a key role, as do advanced grid management and real-time monitoring systems.
Today, EVs represent roughly 2000 out of 28,000 privately owned vehicles on the Faroe Islands. That number is expected to rise exponentially. The same applies to the use of electric heat pumps. Early on, SEV recognized the need to activate EVs in support of the grid and renewable energy. This led to partnering with True Energy A/S, a Landis+Gyr company, and activating EVs as energy assets that support flexibility and grid needs. For example, EV charging sessions can be spread throughout the night, when overall electricity consumption is at its lowest, enabling SEV to reduce grid strain.
SEV has deployed Landis+Gyr’s advanced AMI, smart EV charging solutions and combines them with AMI-integrated distributed energy resource management systems (DERMS). This integration enables SEV to coordinate and manage DERs, including EVs, heat pumps and other renewable assets in real time. Integrating these energy assets into the grid as flexible resources makes it possible to adjust energy loads dynamically, thereby increasing stability, efficiency and resilience.
Bengaluru, India
The growing electricity demand from both EV charging and data center development is surpassing all expectations, resulting in the need to locate these loads strategically. These challenges are emerging in certain global geographies, including the Americas and India. Landis+Gyr is currently engaged with Tata Motors on Controller hardware in the loop (CHIL) and advanced metering infrastructure (AMI) also play a role in the evolution of the power grid, especially in distribution systems with large renewable energy integration and adoption of EVs, thereby reducing the risks of implementing advanced DER control technologies. Graphic by Landis+Gyr.
Using sophisticated hardware in the loop, AMI and DERMS technologies, and virtual emulation infrastructure, NREL can develop an emulation environment that replicates the power grid with millions of edge devices.
a proof of concept for a fleet electrification project in Bengaluru, India. India’s largest commercial vehicle manufacturer, Tata Motors has accelerated Bengaluru’s transportation electrification with the delivery of Starbus EVs to Bengaluru Metropolitan Transport Corp. (BMTC). A Tata Motors subsidiary, TML Smart City Mobility Solutions Ltd. and BMTC have begun operation of 921 electric buses.
A study by the India Smart Grid Federation (ISGF) on the planning and rollout of EV charging infrastructure in Bengaluru concluded the increment in EV charging stations beyond the network’s existing capacity would increase power losses and overloading situations. The feeders mentioned in the study were found overloaded and struggling with multiple undervoltage low-tension lines. Landis+Gyr and TML Smart City Mobility Solutions are collaborating to deploy an advanced e-depot management system to mitigate grid impacts from large fleet loads at the depot, while at the same time ensuring the electric buses are charged when needed and can maintain their operations. A related case study involves the local energy provider in
Manchester, UK, deploying an AMI infrastructure and commercial energy management system at a Landis+Gyr microgrid in the UK. This unique system has edge computing capability in the smart meters that is processing large amounts of grid and energy use data, while disaggregating loads and using advanced artificial intelligence (AI) algorithms to optimize and control loads and DERs on-site. The site also can sell power back to the grid when accessing solar generation.
U.S. National Renewable Energy Lab
As the penetration of these grid edge devices increases, utilities increasingly are facing challenges to scale the ability to control these devices in real time, to maintain grid reliability and resiliency. With advanced AI automation and DER management capabilities being fairly new to the industry and utilities, research labs are still in the process of determining the technology readiness and cybersecurity aspects when these technologies are implemented at scale.
Landis+Gyr and the National Renewable Energy Laboratory’s (NREL) Advanced Research on Integrated Energy Systems (ARIES) are collaborating to develop a strategic experimental setup for integrating advanced metering infrastructure with next-generation capabilities into NREL ARIES project research assets. To meet the objective of ARIES in developing large-scale grid emulation infrastructure, comprising a large number and diversity of devices, work has been ongoing to include up to 5000 grid edge devices. This effort will enable researchers to evaluate the evolution of the power grid, particularly in distribution systems with significant renewable energy integration and adoption of EVs.
To add further variety to the relevant devices, it is proposed to include AMI — a research-ready infrastructure comprising 200 smart meters with enhanced
Landis+Gyr and NREL ARIES are collaborating to develop a strategic experimental setup for integrating advanced metering infrastructure with next-generation capabilities into NREL ARIES project research assets. Graphic by NREL.
Graphic by
Landis+Gyr.
functionalities — alongside 5000 CHIL devices at ARIES. These CHIL devices are capable of emulating grid edge devices, including EVs, building automation systems and distribution automation systems. The CHIL devices can emulate the operational behavior of grid devices while maintaining connections with other grid edge devices through their native communication protocols.
To establish a real-world environment in a control laboratory setting and understand the interactions, NREL will leverage the real emulation of grid edge assets by using CHIL for actual assets like AMI, distribution relays and protection systems. Where actual assets do not exist, the laboratory will capture the characterization from emulation through transfer functions to model the dynamics and nonlinearity of the operation accurately.
Using sophisticated hardware in the loop, Landis+Gyr AMI and DERMS technologies, and virtual emulation infrastructure, NREL can develop an emulation environment that replicates the power grid with millions of edge devices. This setup will allow for the testing of hundreds of utility use cases and de-risking technology deployments before field implementation.
Valuable Insights
As utilities and grid operators across the globe look to achieve carbon neutrality, three valuable insights can be gleaned from the case studies shared:
• Implement real-time data monitoring — Tracking energy demand and production in real time enables utilities to make dynamic adjustments, ensuring energy resources are efficiently distributed, match consumption, and support optimal grid performance and stability.
• Adopt edge intelligence and smart grid technologies — With edge intelligence and other smart grid technologies, utilities can more effectively gather, analyze high frequency data and control grid edge assets, while adapting to changing grid conditions to maintain grid reliability.
• Integrate DERs — DERs such as solar panels, wind turbines and battery storage decentralize energy production, increasing the resilience and flexibility of the grid while reducing reliance on centralized power plants. In addition to these insights, the following strategies can be replicated in other locations globally:
• Deploy advanced data analytics tools that integrate with the grid to collect real-time information on energy flows, demand and renewable production levels.
• Use predictive algorithms to forecast demand surges and renewable output, enabling proactive grid management.
• Integrate demand-response systems and DERMS that can shift consumption patterns based on data insights.
• Upgrade legacy grid infrastructure with smart meters and sensors that enable bidirectional communication between the grid, consumers and DERs.
• Enable distributed intelligence by deploying edge computing at critical points within the grid to process data locally and rapidly adjust energy flows.
• Invest in cybersecurity protocols to protect smart grid systems from digital threats, ensuring safe and reliable grid operations.
• Implement VPPs that aggregate DERs and manage them collectively, enabling smoother integration of renewable energy onto the grid.
• Build a robust DER management platform to effectively connect, aggregate, analyze and control DERs.
• Offer financial incentives or rebates to encourage consumers to adopt DER technologies, ensuring widespread penetration in decentralized assets and power systems. Editor’s note: The use cases shared in this article will be presented in detail at the upcoming IEEE PES Grid Edge Conference 2025 in San Diego, California, U.S. Refer to the sessions on “Solving Renewables and EV Grid Integration Challenges by Using AI and Edge to Enterprise Platforms” and “Lessons Learnt from Implementing EV Charging Technologies for Residential and Fleet Use Cases Globally.”
Shishir Shekhar currently serves as Senior Director and Global Head of Technology and Strategy – Energy Transition Group at Landis+Gyr US and Subsidiary Director of True Energy A/S, A Landis+Gyr Company in Copenhagen, Denmark. Shishir is responsible for Product Innovation, Technology Strategy and R&D for Electric Vehicles and DER Management Solutions.
Dr. Rob Hovsapian, (Rob.Hovsapian@nrel.gov), is a senior research advisor at the National Renewable Energy Laboratory (NREL). He holds a master’s degree in control systems and a doctorate in energy systems from Florida State University (FSU). At NREL, Dr. Hovsapian leads the Advanced Research on Integrated Energy Systems (ARIES) platform, where he is developing the largest DRTS capabilities cluster in the power and energy R&D sector.
High-level diagram of ARIES CHIL Evaluation Test Bed.
Statnett Tackles Extreme Ice Loads in Norway
The utility uses rugged, real-time remote line monitoring to enhance grid reliability in harsh winter conditions.
By ARILD KVAMME BERSTAD, Statnett
Statnett faces many challenges familiar to transmission operators worldwide, but Norway’s unique environment brings its own set of extreme difficulties. Transmission lines in mountainous areas bear some of the heaviest ice loads on the planet; in 1961, an unofficial world record of 305 kg-m (205 lb-ft) was recorded at Lønnahorgi, as Statnett shared at its 2019 R&D conference. Many of the country’s transmission lines traverse vast, mountainous terrain, cross long fjords and endure relentless winds—all of which create ideal conditions for conductor icing.
This combination of high mountains, windy conditions and expansive fjords requires the adaptation of innovative solutions that ensure both safety and reliability. Ice buildup can lead to line failures, costly repairs and significant risks for crews and linemen working in dangerous conditions. Ensuring network stability and reliability requires prioritizing the prediction, reduction
and mitigation of ice loads, particularly given the anticipated increase in ice accumulation due to ongoing climate change.
Rugged Monitoring
In 2013 and 2014, Statnett experienced heavier ice loads than predicted on parts of its transmission system, as shared at the 2015 International Workshop on Atmospheric Icing of Structures event in Uppsala, Sweden.
After testing several solutions for monitoring ice accumula tion over the next few years, most were unsuitable due to the rugged conditions in which Statnett operates. However, one solution showed promise. In 2020, the utility launched a pilot project using technology from Laki Power at Ålvik Mountain in northwestern Norway, situated 1000 m (3281 ft) above sea level. This location experiences particularly severe ice loads and access is challenging, especially during adverse weather.
Laki Power’s LKX-203 system, now rebranded as the LKXMULTI, features three ultra-high-definition cameras along with
Transmission lines near Skedsmo, a municipality in Akershus County, Norway.
An ice-caked power line that has become twisted.
a suite of environmental and line sensors. The cameras provide continuous, real-time visual monitoring and video recording of spans, towers and ground. The accelerometers and wind sensors enable the calculation of ice loads and assessment of environmental conditions before deploying helicopters to deice lines during challenging weather.
One of the most cost-effective aspects of the remote line monitoring system is its power-harvesting technology. By drawing
ASPEN
ENGINEERING SOFTWARE
on diesel generators and other external power sources. Installation consists of inserting the correct inlays for the conductor at hand and closing the lid.
Real Results
Before implementing the surveillance system, Statnett relied on load cells for ice load measurements as the sole input for scheduling deicing work. However, these devices provide only
OneLiner
Short circuit, relay coordination and breaker rating for transmission networks.
Power Flow
Full-featured power flow for transmission systems.
DistriView
Fault simulation, relay and fuse coordination, voltage drop, harmonic analysis, and reliability calculation for distribution networks.
Relay Database
Customizable database for relays and related equipment.
Line Database
Customizable database for overhead lines and underground cables with built-in electrical parameters calculation engine.
EDX Module
Customizable platform for collaborative OneLiner/Power Flow model building and database-driven model data management.
A power line without ice accumulation.
A damaged power line shows a corona discharge. Photos courtesy of Statnett.
picture of the ice type and condition of the line during an icing event. With the rugged remote line monitoring system installed, spans, load data and local weather conditions are now monitored in real time, enabling visual assessment of ice buildup along the conductor. Understanding the type of ice—whether it is in-cloud icing, rime icing or another variety—enables Statnett to create specific strategies to prevent additional buildup.
Through this collaboration, Laki Power enhanced its Analytics Studio, adding an ice overlay feature based on input from Statnett. This feature allows direct measurement of the ice diameter, critical information that gives Statnett an even clearer understanding of conductor stress and time to organize deicing with the helicopter well in advance of potential failure.
In the past, deicing involved sending helicopters out three times to four times each winter. This was a costly and carbonintensive process, often resulting in wasted trips back to the base due to adverse weather or foggy conditions that prevented work from being done. Thanks to the system’s real-time visual monitoring, helicopter deployments are now limited to fly-ready weather conditions, reducing both operational costs and environmental impact.
The pilot also revealed unanticipated risks. In one instance, the system alerted the utility to line galloping, an oscillation caused by wind and ice that can damage lines over time. With this real-time insight, Statnett was able to address the issue and plan more effectively for maintenance and mitigation.
Additionally, corona discharges observed both during and after a storm indicated potential conductor damage, prompting the utility to schedule proactive maintenance.
Ultimately, the project exceeded initial expectations, providing valuable insights into line health and environmental conditions. As a result, the utility decided to purchase several units. The system’s ease of installation and removal allows Statnett to move the units to the most beneficial locations as needed.
Building on the pilot’s success, Statnett is continuing to collaborate with Laki Power to unlock even more value from the autonomous monitoring system. Using data and images collected during the pilot, work is underway to develop an AI forecasting model that will predict the likelihood of icing or galloping events up to 24 hours in advance.
Some of the units will be relocated to new sites after collecting sufficient data to support transmission design teams. A crucial next step is testing live-line installation, which would eliminate the need for scheduling outages and simplify the process of moving units where they are most needed. This system has not only strengthened Statnett’s operational capabilities but also paved the way for preventing failures, marking a significant leap toward more reliable and proactive grid management.
ARILD KVAMME BERSTAD received his bachelor’s degree in Electrical Engineering from Bergen University College in 2014, and started working at Statnett at the transmission line department the same year. He is currently Involved in electrical engineering of new transmission lines, reconstruction programs and more.
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EPRI’s Research Aids Emission Reduction
Results from EPRI’s laboratory tests and field trials can help utilities not only reduce SF 6 emissions but also save money and increase grid reliability.
By DREW MCGUIRE, Electric Power Research Institute
With its chemically stable composition and ability to withstand extreme conditions, sulfur hexafluoride is a man-made gas used in particle accelerators, semiconductors, cellphone components, eye surgery, common consumer products and even some manufacturing processes. Since the 1950s, the U.S. electric power industry has managed the high voltages traveling from generating plants to customer load centers by using sulfur hexafluoride (SF6)
in circuit breakers, gas-insulated substations (GIS) and gas-insulated lines (GIL).
In fact, approximately 80% of the global use of SF6 is in the transmission and distribution of electricity, including the generation and storage of renewable energy. Medium- and high-voltage electrical equipment contains SF6 to insulate live electrical parts and quench arcs during power switching events. SF6 is a compact and economic approach to safely performing these tasks.
However, while SF6 is a highly effective electrical insulator, it also is a potent greenhouse gas. A relatively small amount of SF6 can impact the climate, as it is 23,500 times more effective at trapping heat than an equivalent amount of carbon dioxide (CO2). Even in low concentrations, it remains in the atmosphere for approximately 3200 years. SF6 can be leaked by aging or defective equipment as well as inadvertently during gas handling in any stage of the equipment’s life cycle.
Photos courtesy of EPRI.
A circuit breaker. Medium- and high-voltage electrical equipment contains SF 6 to insulate live electrical parts and quench arcs during power switching events.
Identifying emission sources is the first step to better managing SF6 gas in power systems. EPRI’s controlled laboratory tests and field trials aid electric utilities in emission reduction by informing leak detection and mitigation approaches. In addition to protecting the environment, reducing SF6 emissions saves money and increases grid reliability.
Lab Testing Leaks
Current practices for sealing SF6 leaks are costly, often difficult to implement in the field and may require removing equipment from service.
EPRI performed a controlled lab experiment to seal simulated leaks and tested a collection of adhesives using custom-built pressure cells. From there, at its SF6/GIS lab in Charlotte, North Carolina, U.S., the research organization conducted outdoor leak sealing tests on pressurized, out-ofservice gas-insulated equipment (GIE) containing SF 6 . The GIE was exposed to multiple weather conditions, such as direct sunlight, wind, precipitation and temperature fluctuations. For two years, the project team tracked the performance of seals on pipes, threaded fittings, flanges and threaded bolts, determining the most successful sealing techniques for different types of leaks.
In evaluating sealing materials and developing application techniques for gas-filled substation equipment, the EPRI team adhered to criteria important to grid operators:
• Use cost-effective materials that are commercially and readily available
• Ensure any sealant technique is easy to apply, remove and reapply by utility personnel
• Avoid the need for specialized tools or clamps
• Prevent the system from needing to be depressurized
• Contain or significantly reduce a leak until a permanent repair can be installed.
Leak-Sealing Field Trials
The next step involved real-world experience by field-testing to determine if sealing methodologies would perform well on in-service equipment. Since 2019, EPRI project team members have applied
cutting-edge SF6 leak-sealing techniques in eight field trials globally, resulting in an overall reduction of 2685 lb (1218 kg) of SF6 that otherwise would have been emitted. This reduction is equivalent to avoiding 28,618 metric tons of greenhouse gas emissions from 6811 gasoline-powered cars for one year.
Some participants in the field trials include New York Power Authority, FirstEnergy, Consolidated Edison, UK Power
Networks and Saudi Electricity Co. (SEC), part of National Grid Saudi Arabia (SA). EPRI is currently initiating new field trials with three additional utilities.
In one trial, SEC enlisted EPRI’s assistance with the research design and implementation of SF6 leak sealing at one of its National Grid SA substations. The project team applied a lab-tested technique that did not require an outage or reduction in equipment pressure and used materials
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that were easy to procure, apply and remove. After sealing the leak in the field, the team observed a considerable reduction in leakage, leading to decreased requirements for refilling SF6 gas annually. Based on the success achieved, National Grid SA is planning to apply the technology to substations across its service territory. Sufficient hands-on training and
knowledge transfer from the EPRI team ensured National Grid SA staff could apply the techniques without relying on outside vendors.
Another participant in the field trials, UK Power Networks enlisted EPRI’s assistance to test innovative SF6 leak-sealing materials and techniques at one of its 132-kV substations. UK Power Networks
tested an adhesive and vent-pipe method for leaks in bolts and threaded fittings. The trial was successful and the technique subsequently applied at an 11-kV primary substation, which enabled the line to stay energized during the heart of winter when demand is highest. The seal held until a more permanent repair could be implemented. The method is expected to be used widely throughout UK Power Networks to significantly support the utility’s goals of decreasing SF6 emissions, improving electric system reliability, and reducing operating and maintenance costs.
Replacing SF 6
Work is also underway in the electric industry to eliminate or significantly reduce the use of SF6. However, replacing it presents technical challenges, particularly in high-voltage equipment. EPRI is researching effective alternatives to SF6, whether by adopting other gases, vacuum technology or a different approach. Each new technology brings a combination of benefits and challenges.
In analyzing alternatives, EPRI is leading a 12-month project to rapidly derisk the application of new SF6 -free technologies in circuit breakers. Using a research substation at EPRI’s high-voltage lab in Lenox, Massachusetts, U.S., the team is deploying a range of technologies, including vacuum/clean-air, CO2+O2 , and fluoronitrile-mixture solutions to
EPRI is researching effective alternatives to SF 6, whether by adopting other gases, vacuum technology or a different approach. Each new technology brings a combination of benefits and challenges.
EPRI performed a controlled lab experiment to seal simulated leaks and tested a collection of adhesives using custom-built pressure cells. From there, at its SF 6 /GIS lab in Charlotte, North Carolina, U.S., the research organization conducted outdoor leak sealing tests.
simulate the full life cycle of circuit breaker operations.
Researchers are gaining insights on circuit breaker performance in weather extremes, wet environments, and lightning and overvoltage events. The team also plans to introduce intentional leaks to better understand gas detection and performance. The lab enables researchers to perform all the practical tasks a utility would need to perform with new technologies, such as commissioning, leak detection, analysis, recycling and disposal.
EPRI’s research on potential strategies for SF6 replacement also extends to tracking and understanding the regulatory developments affecting SF6 and alternate technologies.
Research up Next
Leak monitoring is crucial for reducing SF 6 emissions. Monitor suppliers offer various commercial approaches, each with different physical and mechanical constraints, sensor types and proprietary algorithms to interpret data. This complexity makes it challenging to compare the value of different monitors.
To address this, EPRI is analyzing commercially available online monitors to understand their capabilities more fully. Work in 2024 focused on gathering utility use cases, documenting experiences from deployed monitors and using that information to update EPRI’s circuit breaker guidebook. Assessments have continued into 2025, focusing on technologies of interest to electric utilities.
EPRI is also investigating innovative leak detection technologies, such as acoustic imaging, unmanned aerial vehicles and robotics. Further work will concentrate on technologies and techniques that can provide early warnings before significant volumes of SF6 are released.
Ongoing research with EPRI’s SF6 leaksealing techniques includes monitoring field trial performance, investigating sealants that cure at lower temperatures, scaling existing techniques to large flanges and exploring effective methods used by other industries. For successful lab and field-text techniques, EPRI has developed application guides, such as its annually updated GIS and GIL guidebook, workshops, howto videos, webinars and technical reports.
Areas of exploration in 2025 include C4-fluoronitrile mixtures, in-depth vacuum technologies, noninvasive mechanical wear detection techniques, and further interpretation of component deficiencies, irregularities and degradation. These efforts aim to inform the industry on reducing SF6 usage and emissions, ultimately helping grid owners reduce costs, increase system reliability and protect the environment.
DREW MCGUIRE is transmission and substations research and development director of the Electric Power Research Institute. Drew leads research teams focused on Transmission and Distribution Assets and T&D Environmental Issues. He has more than a decade of experience performing and managing R&D for electric utilities. Specific research interests include distribution resiliency, UAS, artificial intelligence applications, and utility sensors.
FACES OF THE FUTURE
BY AMY FISCHBACH, FIELD EDITOR
Luis Gutierrez
ComEd
Inspiration for Going into Line Work
After graduating from high school, I did not know exactly what I wanted to do for a living. I always knew I wanted to work outside. I would often spot ComEd crews working out in the field, and it would make me think on how great it will be working for the company. Eventually, I met my fiancée, who introduced me to one of her cousins, an overhead lineman for ComEd. He told me about the amount of growth and opportunities ComEd offers to its employees. I decided to give it a try, and a few months after I submitted my application for an entry-level trades position, I was hired. A couple of months later, I was able to join the underground apprenticeship school. So far, it’s been going great.
• Is an underground apprentice.
• Enjoys fishing, horseback riding and spending quality time with his family. He grew up horseback riding with his father, and it has been a significant part of his life.
• Didn’t attend a lineman school or pre-apprenticeship program. Instead, he took an assessment, participated in four weeks of initial training, passed a five-day qualifier exam and engaged in on-the-job training to prepare him for his new role at ComEd.
• Works on a lot of manhole jobs in the underground department like identifying cable to cut and remove. To make this task easier, he uses the Hipotronics Transmitter and Detector, which identifies the cable before it is cut with the hydraulic cutters. These cutters can be set on the cable and then operated with a small remote once everyone is out of the manhole for their safety.
• Predicts a lot of changes coming to the industry — from the ways jobs are being done to the machinery that is used to complete those jobs. Because of advancements in electrification, there is a growing demand for clean energy and for more workers in the line trade.
Learning Skills at the Training Center
I recently became a Underground Splicer Apprentice 2 (USA2), and I am on my last step to become a splicer—a full-fledged lineworker. ComEd’s underground training center, which is in Chicago, is equipped with classrooms for in-class training as well as a lab splice area where we practice and test for our assessments. ComEd goes a long way to make sure apprentices get the proper training for the job. We have instructors and demonstrators who are always willing to help and teach us everything that we need to learn. As an apprentice for underground, we focus on perfecting our craft when it comes to building joints. We are also learning how to install and remove cable and reconnect secondary services and identify cables.
Day in the Life
I work with an underground crew in the city of Chicago. Every day can be a bit different from another. Most of our jobs are inside of manholes where we can be removing or installing cable, building joints or doing walk downs to make sure there are no safety hazards inside the manholes. Occasionally, we also set new transformers or even pull cable up poles.
Challenges of Working as an Apprentice
Some of the biggest challenges apprentices face in today’s industry are the physical demands of this job. Although a lot of new machines and tools help us out on a day-to-day basis, the job itself is still very physical. Some days, the weather conditions we work in can be incredibly challenging. In Illinois, the summers can get hot and humid, and the winters can be extremely cold and windy. Having to deal with these challenges while also making sure the job gets done right can make it difficult.
Today’s Technology and Training
The training in today’s industry is a lot different from the past. There is a lot of modern technology that is in place to help with training new apprentices, as well as online courses or videos that help with the training. The world around us keeps evolving, and like anything else, we need to evolve and adapt as well. Overall, with the recent technology and online education that we get, training can seem a lot smoother to understand.
Working Storms
I have had the privilege to work a couple of storms now. The storms that I have worked on have been rainstorms with heavy winds. There are always tree branches that break off and hit customer services or even trees that are broken down. Whenever we go on storm duty, we know the days are going to be long and we will be working nonstop to try and get everyone restored as efficiently and as safely as possible. As underground crews, we usually focus on reconnecting services for customers. One of the things I like the most about working storm is getting to restore people that have been without power for a while. Knowing you got to do something good for your community always makes the long days at work worth it.
Focus on Safety
Safety is the most important thing about this industry. We plan to come in to work and go home the same way we came in every single day. ComEd goes a long way to keep us safe, from the huddles in the morning to the job briefs that every crew does before the job begins. Another way of staying safe in the field is looking out for one another. We make sure everyone is on the same page. Helping each other out goes a long way to getting the job done efficiently and safely.
Life in the Line Trade
I am proud to be part of this trade that powers millions of people each day. Every day that I go to work it seems like there is a purpose to go out and do my best job. One of the things I like the most about being in this field is everyone I get to work with every single day. They have been incredibly supportive and understanding when it comes to teaching me something. Everyone around me always goes an extra step to make sure I understand what is happening on the job and make things simpler for me to understand. I can never thank them enough.
Strategies to Succeed in an Apprenticeship
It takes a lot to succeed in this industry, but if you show grit and determination, anything is possible. You need to be a very
responsible person, show leadership skills and be a team player to help you succeed in this field. I take a lot of pride in my work. Whatever job I am working on I always go the extra step to make sure the work is done right.
Advice for Apprentices
Apprentices should always ask questions no matter the situation and make sure they work as safely as possible for their protection and others. There will be times where you do something wrong, but always remember to speak up and not hide anything. One
Harnessing the Power of AI for Inspections
NYPA is streamlining its maintenance program with AI technology to detect anomalies and prioritize tasks in the field.
By AMY FISCHBACH, Field Editor
The power of technology can transform the operation and maintenance of today’s electric utilities. Case in point: New York Power Authority (NYPA) has incorporated artificial Intelligence (AI)-driven computer vision technology into its maintenance program for detection of equipment defects and anomalies using visual data captured from drones or cameras. AIdriven computer vision technology makes
it possible to inspect assets without costly interruption to operations and reduces the variability in inspection quality that may be caused by human fatigue or error.
NYPA is using widely available models including Convolutional Neural Network (CNN), You Only Look Once (YOLO) and cloud-based options and adapting them through training and fine-tuning. The end result is an AI-driven computer vision model that can identify asset class and subclass
like a transmission lineand sort, analyze and inspect large image repositories.
“AI-driven computer vision speeds up inspections by analyzing vast numbers of images quickly to detect issues,” says Atena Darvishi, R&D director for NYPA. “Upon receiving new images from our drones, we can easily apply computer vision models that are fine-tuned for our needs. When an anomaly is detected that signals the asset requires further investigation, this
A computer vision model detects broken insulators from maintenance images of a NYPA lattice tower transmission line.
rapid processing reduces the need for time-consuming manual inspection and helps prioritize maintenance efforts.”
Ricardo DaSilva, vice president of strategic operations, noted that NYPA continues to develop AI capabilities with its partners to achieve operational excellence. The Power Authority’s ISO55001-certified asset management system is focused on optimizing cost, risk and performance.
“AI-driven technologies (coupled with our robotics program) enhance situational awareness of equipment health and failure detection, which, in turn, support prioritizing operational investments and resources,” DaSilva said. “These insights offer a more robust inspection and monitoring program aligned to asset class strategies and use of predictive analytics.”
Analyzing Images
Leveraging AI-driven computer vision technology to analyze and inspect images allows for more comprehensive and accurate monitoring of assets and significantly reduces the time needed for inspections, greatly increasing overall efficiency.
“AI can also spot anomalies in patterns more efficiently, thereby allowing us to predict when and where failures are likely to occur and allowing for more targeted and timely maintenance,” Darvishi says. NYPA tested the models with images of assets with known anomalies/maintenance issues from its archives and opensource images available through EPRI, a
non-profit energy research, development and deployment organization. Examples of anomalies/maintenance issues that were analyzed included cracks and structural damage on dams, seepage, erosion, spalling, vegetation encroachment, erosion on insulators, broken insulators and conductor damage. The models achieved high Mean Average Precision (mAP), a metric that is
• Grounded Stringing Blocks
• Helicopter Stringing Blocks
• Fiberglass Hot Arms
• Chain Hoists
• Compression Tools & Dies
• Cutting Tools
• Impact Wrenches
• Magnetic Drill Presses
• Battery Tools
• Hydraulic Pole Pullers
• Traveling Grounds
• Groundsets & Jumpersets
• And much more!
• Fiber lass Hot rms
• Chain Hoists
• Compression ools & Dies
• Cuttin ools
• Impact renches
• Ma netic Drill Presses
• Batter ools
• H draulic Pole Pullers
• ra elin Grounds
• Groundsets & Jumpersets
• nd m ch mo e!
commonly used to measure performance and the ability to predict accurately.
Open-source or cloud-based models are readily available and cost effective. They provide flexibility, and NYPA can further train and fine-tune them for its needs. However, a vast number of these models are available, and it requires substantial time and expertise to find the best model for various types of inspections.
Speeding Up Inspections
A central platform for uploading, storage and search of drone images makes the storage and retrieval of images and inspection faster and more seamless.
AI-powered systems can process large volumes of data from cameras and sensors faster than humans, providing near real-time insights and enabling quicker
decision-making. This can streamline maintenance workflows, reduce response times, and allow the field workforce to prioritize maintenance efforts. Faster inspection and decision-making can also mean safer operations for line workers as issues are identified and addressed before they become critical.
Integrating computer vision into operations brings additional notable benefits. AI-enabled real-time monitoring of assets reduces the need for costly routine inspections and identifies issues before they escalate. As a result, costly repairs or replacements are avoided, minimizing the need for manual labor and ensuring a more streamlined process. As R&D partners with groups across NYPA on exploring the application of AI to solve business and customer challenges, organizational
and technology-based capabilities are enhanced, which leads to further application by employees throughout the organization.
Flying Drones
The utility’s robotics program began in 2016, with drones playing a critical part. NYPA uses a variety of drones from six different manufacturers to capture images of its assets across New York State. More than 100 members of the workforce have been trained as drone pilots. Recently, the FAA granted NYPA license to fly unmanned aircraft systems beyond the visual line of sight of the pilot in command in a onemile radius in any unrestricted or Class G airspace without prior approval. The approved waiver expands NYPA’s ability to use drones to monitor and inspect its transmission, generation and canal assets throughout the state.
“Using AI-driven computer vision models to sort these images, identify assets and flag anomalies makes it easy for the field workforce to search for an image or an asset and see flags about potential issues,” Darvishi says.
The utility industry is increasingly employing AI to optimize operations, increase efficiency and improve reliability.
“AI is set to significantly improve the process of maintenance through automated inspection and provides an efficient and cost-effective way to monitor and analyze physical infrastructure, assets and equipment,” Darvishi says.
This close-up of the top walkway and gentry crane is from Long Sault Dam in the St. Lawrence hydro power project.
This lateral drone shot of Long Sault Dam shows all bays, the top walkway and the gentry crane used for manipulating flow/crest gates.
This frontal view of Bay 2 at Long Sault Dam in St. Lawrence, New York, show vegetation growth on the spillway.
PARTING SHOT
PHOTO BY RICK GIAMMARIA PHOTOGRAPHY.
Pepco contractors restore lines following a snowstorm in the Washington, D.C. and Maryland suburbs on February, 8, 2010. This photo is part of a collection of thousands of images shot by Rick Giammaria, a Pepco photographer, during his 35 years of service to the company. As he did a retrospective of his photos, he says a theme emerged — how the men and women of the company responded to crisis situations. To see more of his photos of line crews in action, visit the T&D World website to view a photo gallery.
Brian Lozano
The journeyman lineworker for Midwest Energy in Hays, Kansas, competed at the International Lineman’s Rodeo.
Learning About the Trade
I was interested in getting into the line trade when I was a junior in high school. One of my best friends had a close family friend who was a lineworker at the time, and he told me what a lineman did. At the time, I had no clue what I was getting myself into. I just knew it had something to do with electricity and climbing poles, and that really interested me. I am a firstgeneration lineman, and I would love to see my boys follow in my footsteps and keep carrying the name in the line trade.
Early Years
My first job was working for a contractor out in Colorado back in 2016. It was very difficult as an apprentice for the first couple of years, but it taught me so much and gave me a backbone that has made me who I am today as a journeyman
lineman. On a day-to-day basis, we maintain and rebuild our transmission system and overhead distribution and underground system.
Challenges and Rewards
The most challenging part of my job is leaving my family in the morning or at night during a storm and having that thought if I make one mistake, I could possibly not see them again. The most rewarding part of my job is the lifestyle I get to give to my family and how recognized lineworkers are in the community for what we do.
Safety Lesson
To learn more about Brian Lozano and his career in the line trade, stay tuned to a new episode in our Lineworker Focus series for the Line Life Podcast at linelife. podbean.com.
• Born in El Paso, Texas, as the youngest of three older siblings.
• Married to Carina, and they have a one-year-old son, River Haynes, and another baby boy on the way.
• Enjoys going to the lake in the summer, fishing, camping, hiking, working on vehicles and spending time with his family.
• Currently replacing rotten poles that get tested every few years to keep the reliability and integrity of the system. In the near future, he and his crew will be building new feeds as the city is expanding.
• Can’t live without Kleins, fiberglass sticks and batterypowered tools that make his job easier and safer. He says the battery-powered tool industry has improved lineworkers’ productivity significantly over the years, cutting time in half for some jobs and causing less fatigue on the body.
During the first year of my career, I encountered a life-changing experience that changed my whole perspective on electricity. I was working for a contractor at the time, and most the guys on the crew were all very young. I was only 19 years old myself, and we didn’t really know a whole lot other than the basics of the trade. Our job was to frame poles along a busy blacktop road with no shoulder. We pulled in the ditch parallel with the power line that was getting rebuilt. I was on the ground behind the digger getting material ready along with one of my good friends who is no longer in the trade. The operator was on the captain seat of the truck swinging the boom around to grab the pole, which was lying on the ground. He wasn’t paying attention nor was anyone else spotting him on the power line right above him. All I remember is hearing a loud explosion-like sound, and I fell to the ground. I looked over to see my friend screaming and holding his hands over his stomach. He had been electrocuted from secondary point of contact, and I had been in the step potential zone. After that whole experience, I realized we all could have died from that situation, but God was watching over us that day. I learned that no job is too important to slow down and look around and see what is around you. I now push myself and other apprentices to take the time to be slow down and stop if something doesn’t feel right during a job. Safety is what gets you home—no matter the circumstances.
Plans for the Future
I would go into the power industry all over again. I think I would do certain things differently, but I love how much this industry has grown. I am able to experience a lot of things, and I get to have fun doing it as well. It is also a very rewarding career. In the near future, as I age, I hope to get into a management position that is easier on the body.
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Economic Winners and Losers: The Energy Transition Under Trump
When creating economic policy, the ideal outcome is a win-win. More often, however, where there are winners, there are also losers. For the incoming Trump Administration and power markets, we see many tradeoffs with emerging winners and losers. Ascend Analytics has a 20-year history of market forecasts and economic modeling of energy projects, from wind, solar and storage to thermal resources like natural gas plants. Our economists constantly adjust our outlooks to account for changing market conditions, and the incoming administration introduces many potential variables.
In examining the potential policy changes, the Trump Administration is pro-energy but may be more technology-neutral than many expect. Their ideal world is not just one of American energy security, but one of American “energy dominance.” This goal presents both headwinds and tailwinds for clean energy projects and their potential value, with winners and losers acros different energy supply stack options and across time.
Tariffs and potential changes to the Inflation Reduction Act (IRA) are likely to increase future costs for many inputs into power supply. These potential changes will likely lead to increased inflation and higher capital costs for new energy supply projects, renewables and otherwise. However, for near-term energy projects, up to five years out, safe harbor practices and secured supply can, to an extent, protect them and possibly make them more valuable, along with existing generation that now lives in a time-bound “walled-garden.”
Winners: Late-stage projects and existing generation.
Losers: Long-lead time greenfield capital-intensive projects in search of financing.
While cost increases may dampen commitment to projects further out, states’ clean energy policies remain aggressive and corporate clean energy goals continue to grow, independent of federal policy. The Trump Administration is also aggressively pro-growth and will do what it can do to encourage and foster the expansion of American computing. Data center and AI load, and the generation required to serve those facilities, will likely receive the permitting and interconnection assistance needed to maintain the velocity of the industry. Pro-growth policies, combined with state and corporate clean energy goals, will accelerate the value of late-stage and operating projects and may also serve to get a lot of clean energy online as fast as possible. Trump’s own statement on energy goals commits to “cutting red tape, enhancing private sector investments, focusing on innovation over...unnecessary regulation.” These efforts could lead to permitting reform that may speed new development and be a boon to clean energy projects, blunting some of the inflationary headwinds.
Geography also matters. Open land with good wind and solar resources gives the Western two-thirds of the country an
advantage versus the heavily forested, less-windy, and less-sunny Eastern US, although policy commitments in the Northeast will still support development. The New York and New England markets will be the most heavily impacted and will need to make hard choices between meeting policy targets and maintaining retail rates at reasonable levels.
Winners: Inside track projects and the Western U.S. Losers: Northeast markets facing tough choices.
“Drill, baby, drill.” Trump’s energy dominance stance also includes increasing the supply of natural gas, both for domestic consumption and to “sell to our friends,” including European nations. Increasing LNG exports will lead to higher domestic gas demand, moving up the classic supply curve and actually raising gas prices. Additionally, domestically produced clean energy allows increasing energy exports, further supporting “energy dominance.”
Winners: Supply resources that are cheaper than LNG.
Losers: Buyers of natural gas who will pay more.
Nuclear energy, as recently as a few years ago thought of as an unwieldy expensive solution, becomes a potential solution for specific geographies and for customers with less elastic demand. Data centers, with their flat load profile and owners with deep pockets, make nuclear a potential solution in their toolbox. With expanding load, nuclear can potentially service the ESG demand for a clean peak resource at a competitive cost relative to other expensive solutions, like hydrogen, in geographies where building the renewables to produce green hydrogen is cost-prohibitive. Heavy renewable headwinds in the eastern third of the U.S., for example, strengthen nuclear’s position. Here, small modular reactors (SMR) may be competitive with offshore wind and hydrogen if they hit their cost targets and offshore wind does not, though that remains a big ‘if’ in the nuclear industry. SERC-based utilities have included advanced nuclear in their IRPs, and other similarly positioned regions may look to nuclear if tariffs and tax-credit repeal for clean energy technologies come in strong.
Winners: Nuclear in high renewable cost regions, especially the Eastern 25% of the U.S.
Losers: Offshore wind and greenfield solar in the northeast. Winning in this environment of relentless load growth and energy dominance will require a strategic “all-of-the-above” approach. Overall, we will see a narrowing set of conditions where renewables are the ideal choice, and legacy thermal generation will be pushed to stay online longer than planned. Many energy buyers will not have the luxury of choice, either due to state-level mandates or competitive growth pressures. Those that do are likely to select a more diversified “all-of-the-above” portfolio of their own to serve their needs, including some difficult choices along the way.
BRENT NELSON, PhD is managing director of Markets & Strategy at Ascend Analytics.
