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20 Mysterious Transformer Trips: Solving
New on tdworld.com
and photo
Utility Business:
Eaton Investing $340M in South Carolina to Build Transformers
Word of the project comes after the company has spent more than $1 billion since 2023 to grow its electrical equipment group. https://tdworld. com/55268244
Utility Business: Xcel Executives Say They Have Data-Center Deals Covering About Half of Their Five-Year Forecast
More contracts are expected by fall, CFO Brian Van Abel says; “Speed to market continues to be one of the most important factors.” https://tdworld. com/55266622
Utility Business: Dominion, Duke Beef Up Budgets as Data Center Demand Booms
The amount of contracted capacity at Dominion from data center operators climbed 88% in the second half of 2024. https://tdworld.com/55267947
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Eaton Corp.
Dominion
From Print to Podcast: Embracing the Digital Evolution of T&D World
This Gen-X editor resisted what we called “new media” for a long time. I grew up and went to school to learn how to write and edit for print. But just like our energy industry, the nature of delivering information to help you do your job has changed too. I was the first “online editor” for T&D World, taking over all of the digital media for the magazine including the web articles and “e-newsletters.”
Regardless, when COVID came around we found ourselves in front of cameras: first, for staff meetings, then webinars picked up. We did have editors who were more comfortable with video and other outlets before then. Editor-inChief Rick Bush did some short videos from time to time, and we had a contributor named Jim Dukart, who filmed various linework and installation procedures (and narrated them) for our popular “T&D How” video series. But I managed to stay out of the spotlight as long as I could. Alas, as the appetite for how people want to receive content broadened and changed, so did I. T&D World now regularly hosts webinars and webchats moderated by editors, and we participate in forums and discussions with other Endeavor Business Media brands. And look for us to do more video projects as the year progresses, as we hope to make some videos at industry events and potentially host some roundtable discussions ourselves.
Podcast Paradise
the audience is “Whether you’re heading to a job site, tackling storm restoration, or just unwinding after a long day, you can tune in to hear stories about storm recovery, best practices in line work, and the incredible men and women in the trade.”
The podcast has won multiple business-tobusiness media awards and is now up to weekly releases. We have featured apprentices, journeymen and arborists. We had a national labs guest: Peter Fuhr of the Oak Ridge National Laboratory exploring the drone research underway at ORNL.
We also had workers from Duke Energy talk about their experience after Hurricane Helene, one of the more recent storms. And if you don’t have time to pick up the magazine and read it, we also feature audio versions of some of our more popular articles dealing with utility operations. To catch a few of the episodes, visit https://linelife.podbean.com/.
I am also excited to announce the recent launch of T&D World Live, our podcast for the T&D audience that will delve into critical issues, emerging trends, and groundbreaking projects shaping the electric power-delivery landscape.
One type of media I have come to appreciate is podcasting. This doesn’t always involve video, although it can be integrated. But it’s a fun, easy way to bring content to you in an audio format. I am sure many of you know what podcasts are, but I will give you a little background here. They aren’t as new as you might think. They are like a radio talk show to a certain extent, except they are put into sharable sessions or “episodes.”
Podcasts, which used to be called “audioblogs,” go back to the 1980s. But it wasn’t until broadband internet and portable music players — like the iPod — came along that podcasting really took off in late 2004. Fast forward to today, and there are over 115,000 English-language podcasts out there, with plenty of platforms making it easy (and often free) for creators to share their content and for listeners to tune in.
T&D World launched our first podcast in 2021 covering the line trade. Our fabulous field editor Amy Fischbach created it with the intention of featuring the men and women on the front lines of maintaining and restoring electricity. The message for
Our second episode is probably going to be one of my favorites: Senior Editor Christina Marsh hosted Technical Editor Gene Wolf and our Editor-in-Chief “emeritus” Rick Bush for a discussion on the history of T&D World ’s leadership in the industry, as well as the challenges and innovations shaping the future of the electricity industry. They reflect on the evolution of transmission, the rise of high-voltage direct current (HVDC) technology, and the integration of renewables and storage into the grid. Check it out at: https://tanddworld.podbean.com/
Then I had the pleasure of sitting down with Dr. Elizabeth Cook, vice president of Technical Strategy for Association of Edison Illuminating Companies, to explore the transformation of the power grid and the crucial role of integrated system planning. Elizabeth is interesting to talk to; she is full of industry knowledge, having worked at Duquesne Light Company for seven years in system planning and grid modernization. She hosts her own podcast called the Grid Mod Pod and is also a mindset coach and literally full of all kinds of wisdom. She is featured in our third episode.
Share with us what other podcasts you like listening to. When you ask people what their favorite podcasts are, you will get all kinds of different answers: there are podcasts to cover everything you can imagine.
New Technologies Opening New Opportunities
If my inbox is any indication, this year is going to an exciting one! There are so many fascinating topics it’s hard selecting one for this month. That’s what makes it so interesting.
One release came out focused on an estimated 260 gigawatts of distributed energy resources being added to grid by 2028. Another reported that the power grid needs 160 gigawatts of virtual power plants by 2030. Someone sent me a study discussing datacenters and their appetite for electricity. In 2023 they had consumed 4.4% of the total electricity generated in the US, and that could more than double by 2028. A curious press release came from a new Chinese AI company, DeepSeek. They have the solution for datacenter power consumption with a more energy-efficient AI product. It purportedly uses ten to forty times less power than their competition.
Technical Adventure
When I opened an email from the SuperGrid Institute (France), I had my subject. They had seen several of my articles on HVDC (high-voltage direct current) networks and wanted to talk about their HVDC work. They had developed a distinctive HVDC power circuit breaker. HVDC circuit breakers are one of my favorite subjects since 2012, so I contacted them.
November 2012 stands out in my mind because that was the year I was invited to tour ABB’s (now Hitachi Energy) HVDC
research facilities in Switzerland and Sweden. That was like a week at Disneyland, but behind the curtain. It was a whirlwind trip, talking with their experts along with seeing their labs and factories. And you guessed it, they included their brand-new prototype HVDC circuit breaker. It was a hybrid (i.e. solid-state device and mechanical) design they were testing.
What makes the HVDC circuit breaker so fascinating is the physics behind the device. AC breakers take advantage of the current zero point in the AC waveform to interrupt the current, but there is no zero current point in the DC waveform. That results in a DC circuit breaker that needs help, which is where it gets complicated. There are several methods to do this, but it’s a complex specialty. If you’re interested, you can find detailed discussions on Hitachi Energy’s and Siemens Energy’s websites.
Super Cool Tech
Let’s get back to the SuperGrid Institute. Their HVDC circuit breaker is a unique approach. It’s a DC mechanical breaker combined with a resistive superconducting fault current limiter (RSFCL), a vacuum chamber, and current injection. The RSFCL design is based “on a series of ten “pancake coils” of superconducting tape in a cryostat where the liquid nitrogen has been brought down to 68 degrees Kelvin (-205º C).”
SuperGrid Institute said they are taking advantage of a characteristic of superconductors. Basically the superconductor acts as a high resistance to fault limiting the current and a low resistance to normal currents passing the power. The RSFCL is modular and stackable for higher nominal voltage and current levels. Last December, the Institute successfully tested their HVDC circuit breaker up to 50 kV. The SuperGrid Institute’s cryogenic HVDC breaker is a welcome addition.
These HVDC circuit breakers are a critical element in constructing a multi-terminal HVDC power grid. In 2020 the Chinese utility State Grid energized the world’s first meshed HVDC grid with four nodes and 16 propriety HVDC breakers. Europe is in the planning stages for a meshed HVDC grid with an operational target date of 2032. In the U.S., however, some experts say a meshed HVDC grid it’s still science fiction.
There are several suppliers developing HVDC circuit breaker technology. Hitachi Energy has its hybrid HVDC circuit breaker that’s available for deployment at voltages up to 1100 kV. Also, Siemens Energy and Mitsubishi Electric announced a partnership to develop an HVDC circuit breaker last year. GE Vernova and Dutch-German grid operator TenneT are working together to develop a 525 kV HVDC circuit breaker according to an announcement last year.
The global HVDC transmission market hit USD 11.4 billion in 2023. It’s expected to grow annually about 5.4% over the next three years and the HVDC circuit breaker is an important part of that growth. This a trending topic that deserves careful watching!
Design testing of RSFCL HVDC.
Courtesy of SuperGrid Institute.
VPPs: The Ultimate GridEnhancing Technology
There is a workaround for quickly adding transmission capacity to the grid.
Over the last couple of decades, electricity consumption has been fairly steady, but in 2024 it jumped about 2%, and that upswing is expected to continue. The figures differ based on the authorities discussing the issue, but it’s going up. One of the better dialogues comes from the Department of Energy (DOE) who has estimated the U.S. will need about 200 gigawatts of additional resources by 2030.
Transmission wise, NEMA (National Electrical Manufactures Association) reported the US electric grid has over 642,000 miles (1,033,000 km) of highvoltage transmission lines, but more is needed. Connecting the needed clean energy and preventing region-wide blackouts will require that the transmission infrastructure be at least doubled by 2030 and possibly tripled by 2050 according to NEMA.
Utilities and grid operators have also voiced their concerns and are working toward increasing capacity. A report from Deloitte said, “Utilities are responding to this dynamic landscape with record capital expenditures.” Still, high-voltage
transmission line construction has been dropping steadily for the past decade.
Last year’s completed transmission line construction figures aren’t available yet, but they’re expected to be around 125 miles (201 km). Numerous factors affect transmission and generation projects. In today’s environment, it can take over ten years to complete a transmission project. So we’re dealing with the old doublewhammy of not enough generation and not enough transmission capacity to delivery power if we had it.
The Practical Solution
Nevertheless, there’s a technological workaround to this complex situation that has been expanding and intensifying, and it’s located exactly where it is needed, behindthe-meter (BTM). It’s distributed energy resources (DERs), and our customers have been busy deploying a wide variety of DERs on their systems. In the process the capacities of DERs have increased to the point they are being measured in gigawatts nowadays, but these gigawatts are the summation of tens of thousands or more individual installations.
In February’s “Charging Ahead” we explored microgrids powered by increased numbers of customer-based DERs made possible with the integration of artificial intelligence (AI). We also touched on virtual power plant (VPPs) technology, but did not go into it too deeply. Now it’s time to look closer at this technology. VPPs are being seen as not only a simple solution, but a practical one when needing more generation and transmission capacity and needing it quickly.
Keeping it short, VPPs are an assortment of small-scale DERs like rooftop solar, small wind turbines, battery systems, electric vehicles, etc. operating as a single large-scale generation asset. A few years ago the DOE published its “Pathways to Commercial Liftoff” for VPPs and they have updated every year since then. In January the 2025 edition was made available on their webpage and makes for interesting reading.
DOE points out, “VPPs will be a vital near-term solution to existing energy challenges, including rising costs, interconnection backlogs, peak demand increases, and distribution system congestion.” They continue, “VPPs present a more efficient alternative to manage this rising demand while making electricity cleaner and more affordable for Americans.” DOE noted there were roughly 33 gigawatts of operational VPPs at the end of 2024. They estimate that between 80 and 160 gigawatts of additional VPPs will be operating by 2030.
Grid-Enhancing Technology Advantage
VPPs can be third-party owned and operated, utility owned and operated, and a combination of those along with a few other designations, but these cover what we’re focused on. VPPs are close to the load being located BTM, which really boost reliability and increases resilience,
Installing rooftop solar panel.
Courtesy of Sunrun.
while reducing energy costs with lower transmission losses. Another tremendous advantage is their ability to be deployed in about six months or less. In addition, they don’t require substantial changes or additions to the high-voltage transmission grid, extensive permitting, or dealing with the interconnection queue delays.
February saw, the North Carolina Clean Energy Technology Center (NCCETC) and the Smart Electric Power Alliance (SEPA) published their 50 States of Virtual Power Plant and Supporting Distributed Energy Resources: 2024 State Policy Snapshot report. It’s full of information on what is happening state-wise with VPPs, and updates are being considered. NCCETC/SEPA report stated the goal is “providing insights on state regulatory and legislative actions related to VPPs and DER aggregations,” and like the DOE’s liftoff report, it makes for some very interesting reading.
It appears that 2024 was a very active year with 105 state and investor-owned utility actions related to VPPs taken place in 38 states and the District of Columbia (D.C.). Many of these actions are expected to continue in 2025. The most common of these were related to energy storage, multi-technology VPP programs, and demand response programs. There were several VPP trends identified like utilities driving VPP activities and expanding VPP programs along with state regulators developing statewide frameworks for VPPs.
Powering Up VPP Programs
One of the essential goals of power grid modernization is decentralized power generation by moving away from large fossil-fuel based generation to on-site clean energy generation technologies. “Charging Ahead” talked with representatives of Sunrun, one of the leading home solar panel and battery storage companies. In 2024 Sunrun expanded their VPP programs to include more than 20,000 Sunrun customers.
These customers are involved in 16 VPP programs across nine states and territories. The programs have successfully supported a combined instantaneous peak of nearly 80 megawatts of power. Their largest endeavor to-date is the CalReady VPP program. It has networked
more than 16,000 customers’ solar-plusstorage systems. Sunrun said this VPP supports California’s electrical grid delivering an average of 48 megawatts to the power gird during peak evening hours in the summer months.
Another Sunrun VPP is the PowerOn Puerto Rico VPP. It’s the largest participant in Puerto Rico’s Battery Emergency Demand Response program with over 4,000 customers’ solar-plus-storage
systems. This VPP provides more than 15 megawatt-hours of energy to back up the island’s power grid. It provided vital backup energy to the island’s power grid during more than 70 energy shortfall events keeping the lights on for communities across Puerto Rico.
Last February, Rocky Mountain Power (RMP) and Torus signed a memorandum of understanding. They will work together incorporating Torus’s Nova
Overhead/Underground Transmission
Overhead/Underground Distribution
Substations & Switchyards
In-House Helicopter Operations
Environmental Compliance
Spin and Nova Pulse technologies into RMP’s Wattsmart 70 megawatt demand response program. It will create a VPP platform that integrates directly into its grid operations system.
Basically, the Nova Spin portion stores energy kinetically using an advanced flywheel technology, and the Nova Pulse is a modular lithium-iron phosphate battery system. It delivers a sub-250 millisecond response time with 99% system uptime and real-time frequency regulation along with other features. The project is expected to be operational within 12 to 18 months.
Filling the Gaps
It’s estimated that by the end of 2024 there were over 500 VPPs operating in the U.S., and they’re increasing. The experts say new VPPs can usually be deployed in less than six months, which makes them desirable right now. Overall there seems to be positive interest from our customers to install DERs and they’re interested in making money with their investments, which is good for VPP applications.
Still there are some issues impacting that deployment. The interconnection process for VPPs/DERs varies from region to region. It’s a straightforward process in most parts of the country. However, when programs with multiple parties meet complicated laws mixed with complex regulations it can take twelve months or longer.
As the NCCETC/SEPA report pointed out, 38 states and D.C. regulators are aware of the value VPPs represent and working to support this developing trend. VPP applications are maturing, advancing, and now they’re being integrated with AI technology, which is opening new opportunities for utilities and grid operators. Harnessing tens of thousands of DERs into a single generation source was once a dream for many involved with the power grid.
AI-driven VPP platforms have made that a reality, which is making the power grid more resilient. It’s another tool for our toolbox when it comes to the modernization of the power grid. AI-driven VPPs are capable of providing superior
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responsiveness for the grid. The interesting thing about these VPP applications is the fact that they are all off-the-shelf technologies and available for use.
Grand View Research (GVR) estimated the global VPP market was US$ 5.01 billion in 2024. They project it to grow at a compound annual growth rate of 22.3% from 2025 to 2030. GVR sees the rise of decentralized energy generation and the urgent need to transition away from fossilfuels contributing to the market growth. In addition, GVR said, “VPPs play a critical role in aggregating and optimizing these DERs, ensuring efficient power generation and distribution.”
VPP technology continues evolving into more versatile applications with more features and capabilities. There are hundreds of gigawatts from untapped DERs living BTM that could be utilized by AIdriven VPP platforms to provide a wide array functions needed by the power grid. They’re a necessary ingredient for futurizing the grid and a trending technology to boot!
DTE Energy Invests $4.4 Billion in Electric and Gas Infrastructure to Improve Reliability and Generate Cleaner Energy
In 2024, DTE Electric announced investment of over $2.5 billion in infrastructure improvements and $1.1 billion in cleaner generation, while DTE Gas invested $740 million to upgrade its natural gas system and expand service to rural communities.
The investments in utility infrastructure helped customers experience a nearly 70% reduction in time spent without power.
“We invested a historic $4 billion to modernize our infrastructure, which enabled our team to make significant progress building the electric grid of the future and upgrading our natural gas pipelines to produce more reliable, affordable and cleaner energy for our customers,” said Jerry Norcia, DTE Energy chairman and CEO. “Furthermore, our progress in 2024 positions DTE to support Michigan’s economic growth by powering the rise of data centers and the electrification of vehicles.”
The accomplishments are:
• Top-tier bill management for customers; reduced customers’ bills by $300 million in fuel and transportation cost savings: Reduced the Power Supply Cost Recovery (PSCR) mechanism, which represents the actual cost of the fuel and other sources the company uses to produce electricity, by approximately $300 million through 2025. This adjustment reduced residential customers’ average electric bill by approximately $5 per month starting November 1, 2024. Combined with this bill reduction, the electric rate order from the Michigan Public Service Commission results in residential electric customers not experiencing an increase in their monthly bills. Through supplier cost management, operational excellence and energy efficiency initiatives, DTE can claim top-tier bill management since 2021.
• Customers experienced a nearly 70% improvement in time spent without power from 2023 to 2024: DTE Electric made great progress toward improving reliability in 2024 by installing more than 450 smart technology reclosers, upgrading existing infrastructure including 850 miles of power lines and 3,400 utility poles, and trimming more than 4,300 miles of trees. This work to build a smarter, stronger and more resilient grid, coupled with less extreme weather, resulted in DTE customers experiencing a nearly 70% improvement in time spent without power from 2023 to 2024.
• Supported vulnerable customers by connecting them to $144 million in energy assistance: In the 2023-2024, DTE continued its partnership with human service agencies to connect vulnerable customers to nearly $144 million in energy assistance, providing access to more than $660 million in financial aid over the last five years.
• Championed legislation to assist lowincome customers: Worked shoulder to shoulder with community leaders to double the Michigan Energy Assistance Program (MEAP) funding to $100 million in five years and increase the eligibility of MEAP funds to 200% of the Federal Poverty Level.
• Brought comfort to Michigan families with $63 million in Energy Efficiency Assistance: DTE’s Energy Efficiency Assistance (EEA) program provided $63 million in critical home upgrades at no cost to income-qualified customers, helping them lower their energy bills while improving their comfort and safety. Nearly 5,000 Michigan families benefit annually from EEA upgrades like new LED light bulbs, insulation, air sealing and furnace and boiler tune-ups or replacements, high-efficiency water heaters and ENERGY STAR refrigerators. In 2025, DTE allocated over $2 million to Detroit’s North Coyle neighborhood, where families face some of the city’s highest energy usage and completed nearly 3,000 HVAC upgrades and replacements for residents in this area and across the service territory.
• Improved safety, reliability and service for natural gas customers: DTE Gas ensured the continued delivery of safe and reliable energy to 1.3 million customers across Michigan by replacing cast iron pipes with more durable materials and moving nearly 16,000 natural gas meters to the outside of homes and businesses to ensure people’s safety. DTE Gas also expanded natural gas service to 3,200 new customers in central and northern Michigan and earned top score in Customer Satisfaction for Business Natural Gas Service in Midwest from J.D. Power.
• Launched DTE’s solar park and battery energy storage center: Sauk Solar, a 150 MW solar park with nearly 347,000 solar panels, began operations in October in central Michigan, generating enough clean energy to power approximately
40,000 homes. Sauk is one of the six new solar parks to come online, all of which are funded by customers voluntarily enrolled in MIGreenPower. DTE also inaugurated a battery energy storage plant, the Trenton Channel Energy Center, in June. The company continues to build renewable energy and storage projects to meet customer demand through its CleanVision MIGreenPower program. These new initiatives will help DTE reach its goal of achieving net zero carbon emissions by 2050 and help Michigan achieve its renewable energy standard of 60% by 2035.
• Invested $3.3 billion in local businesses and created jobs in Michigan: DTE spent $3.3 billion with local businesses in 2024, creating and sustaining nearly 14,000 jobs across Michigan. The company continues to be a leader in partnering with local suppliers, investing more than $24 billion since 2010 and creating or sustaining 92,000 Michigan jobs.
• DTE Energy Foundation granted $420,000 to Michigan domestic violence shelters: Continuing its mission to support victims of domestic violence in Michigan, DTE Energy Foundation awarded $420,000 to 45 state-funded domestic violence shelters, bringing the Foundation’s total commitment to more than $3 million over the past six years.
• Earned numerous honors as a great place to work including:
• Gallup Exceptional Workplace Award for the 12th consecutive year, placing DTE in the top 6% of companies globally.
• C. Everett Koop National Health Award for programs to improve employee health and wellness.
• Best Place to Work for Disability Inclusion, earning a top score of 100 on the Disability Equality Index.
• Michigan Veteran Affairs Agency Employer Innovator Award for proactive recruitment and onboarding programs to improve veterans’ lives.
“In 2024, our financial strength and constructive regulatory environment allowed us to continue to invest above our generated cash flows to provide improved reliability and cleaner, more affordable energy to millions of Michiganders,” stated David Ruud, DTE’s executive vice president and CFO. “We are well-prepared to meet our financial targets in 2025 and excited about our future.”
Legislation to Expand Production of Electric Distribution Transformers
U.S. Senators Catherine Cortez Masto (D-Nev.) and Jerry Moran (R-Kan.) have introduced the Credit Incentives for Resilient Critical Utility Infrastructure and Transformers (CIRCUIT) Act to support the production of electric distribution transformers.
The legislation is expected to expand the Advanced Manufacturing Production Credit (45X) passed as part of the Inflation Reduction Act to include distribution transformers to strengthen the domestic energy economy. The U.S. has a record demand for power transformers and current production is unable to match the requirement from new housing, data centers and more.
“Nevada is leading the way in 21st Century energy technologies and manufacturing, and we need more distribution transformers to connect new sources of energy and power to the grid,” said Sen. Cortez Masto. “Our bipartisan legislation to boost the production of distribution transformers is critical for lowering energy costs, supporting energy resiliency, and strengthening our national security.”
“Demand for energy and power is continuing to grow in Kansas and across the country as housing, businesses and transportation needs expand,” said Sen. Moran. “Creating a tax credit to incentivize domestic production and manufacturing of distribution transformers will help the United States move closer to energy independence, provide jobs and keep up with rising demands.”
Arizona Passes Legislation to Streamline Permitting for SMRs Co-Located with Data Centers
or uses to replace or expand generation at existing baseload
The bill, HB2774, removes bureaucratic obstacles in the way of SMR deployment to meet growing energy needs, streamlining the permitting process for utilities and technology companies with
“We need a bold approach to ensure energy production keeps pace with demand, maintains grid reliability, and supports job growth — especially in rural areas,” said Majority Leader, Carbone. “Small modular reactors offer the ability to repurpose existing facilities, attract new industry, and provide clean, reliable, and affordable power to rapidly-expanding industries that are critical to national defense, like data centers.”
For Utilities: Eliminates the requirement for a Certificate of Environmental Compatibility (CEC) when converting an existing thermal unit to an SMR or constructing a new SMR at an
For Large Industrial Energy Users: In counties with a population of 500,000 or less, a new SMR co-located with a large energy user will be exempted from the CEC process and county zoning restrictions.
The legislation encourages private-sector investment and economic development in Arizona. The plan supports the 2025 House Majority Plan to set Arizona’s economic potential, drive energy innovation, and create opportunities for communities impacted by
“Rural Arizona will benefit from high-paying jobs, increased capital investment, and a more stable tax base — all while keeping our energy supply reliable and affordable,” Majority Leader Carbone
HB2774 is moving to the full Arizona House of Representatives for
Companies File Notice of Intent for Upper Midwest’s 765-kV Transmission Line
Great River Energy, ITC Midwest and Xcel Energy have filed Notice of Intent to construct, own and maintain the Upper Midwest’s new 765- kV electric transmission line with the Minnesota Public Utilities Commission.
The notice initiates the permitting, public outreach and environmental review process examined by the Commission and is an initial step in project development. Similar notices will be filed in other states as part of the development process.
“This transmission line will provide significant benefits to our communities, ensuring we meet the unprecedented growth in their demand for electricity while keeping costs low for homes, farms and businesses,” the companies said. “Some estimates project electric use to double over the coming decades in our region.”
The companies will develop the 765-kV transmission project in several segments. The line will connect to the existing transmission grid in eastern South Dakota and travel approximately 410 miles across southern Minnesota to Wisconsin, also connecting into the regional grid in Wisconsin and Iowa. The line will connect the Lakefield, Pleasant Valley and North Rochester substations in Jackson, Mower and Olmstead counties.
The companies worked with the Midcontinent Independent System Operator (MISO) and other stakeholders for several years to develop transmission solutions as part of a multi-phase plan to bolster the reliability of the region’s electric grid.
A single 765-kV electric transmission line is capable of delivering approximately the same amount of electricity as six 345-kV transmission lines with similar land impacts and structure heights as existing high-voltage transmission lines.
The companies expect to file a Certificate of Need application in Minnesota in early 2026 and will work closely with landowners and communities throughout the project area to help determine the best locations for the route to include in their future Route Permit application.
Each application’s review process takes about 12-18 months and includes public information meetings and hearings throughout the project area. The transmission line is anticipated to be operational by 2035.
First U.S. Utility Approved for FAA Part 91 Exemption for BVLOS SwissDrones
Southern Company has received approval from the Federal Aviation Administration (FAA) for a 14 CFR Part 91 exemption, allowing beyond visual line of sight (BVLOS) operations using SwissDrones unmanned aerial systems (UAS). The company is the first U.S. utility to secure this exemption, achieved through a partnership with Phoenix Air Unmanned. This approval marks a step forward in the use of BVLOS technology for utility applications and contributes to ongoing regulatory developments in the industry.
Transformer trips are a common problem, but the solution is sometimes not immediately obvious. A technician shares three stories from the field.
By MOSE RAMIEH, CBS Field Services
Modern substation control and communication have revolutionized the ability to troubleshoot system faults and mis-operations. Event fault records and documenting every input and output provide invaluable information to help answer the question, “What happened?”
However, there are hundreds of thousands of systems with legacy equipment. These systems can present seemingly baffling challenges that could necessitate several attempts (test and try) to work through various scenarios to resolve the issue.
Life in the electrical maintenance and acceptance testing business can throw strange situations your way. This is also true of my experience in the electrical testing business. These three stories occurred over the course of my career and might help you be more efficient at identifying and correcting issues without all the benefits of modern communication. These stories, focused on substation transformers, illustrate that regardless of the complexity of the situation and system, it is often the simplest of solutions that can be the hardest to find.
Two Trips, One Input
Springtime in Tennessee can present some variable weather. Freezing cold mornings and bathing-suit temperatures in the afternoon are not uncommon. These temperature swings played an interesting role in the case of a mysterious trans former trip. Shortly after my third cup of coffee, the call came from the plant engineer. “Get over here now! T1 just tripped off.”
Knowing little more than that we headed to the customer’s plant, where we found a flurry of activity and questions re garding why transformer (T1) had tripped off-line. Physical inspection of the system noted no protective relay targets and an 86T (transformer lockout relay) operation. No pro tective relay operations? That’s odd. Let’s dig deeper and review the HMI event records. As we reviewed the event log there was only one unrecognized item on the list: IN604.
This input (IN106) is from the SEL 2411 that was in stalled to capture and communicate transformer trips and alarms. It was odd to note that the input was high on the event list and a short time later low. The input came in and then cleared. A review of the drawings showed that IN604 is tied to two fault conditions associated with the load tap changer (LTC): Did someone grab the manual LTC crank handle, or was there a pressure relief operation?
Work crews must work and observe carefully to uncover what happened when transformers trip and no clear fault can be found.
Photo courtesy of NETA.
Physical inspections are an important tool for locating problems.
Noting that the LTC handle is behind a bolted cover and that no one had opened the cover, we turned our attention to testing the pressure relief device (PRD). Tests and inspection proved that the switch operated properly and wasn’t the source of the issue.
With the mindset of better safe than sorry, we did some basic tests on the transformer and the LTC. All results were comparable to the previous maintenance results. After much discussion, a decision was made to energize the transformer. It was energized without issue and was left to soak overnight.
The following morning, however, the transformer tripped again. Once again, the event log documented IN106 going high and then going low. There was no PRD operation and no one had messed with the bolted cover that housed the LTC manual crank handle.
All sorts of ideas began to fly about how the system must be mis-operating. To leave no stone unturned, we opened the LTC
handle cover to inspect the switch. Repeatedly removing and replacing the handle proved that the switch was doing its job: Handle out, IN106 went high; handle in its holder, IN106 went low. More tests, more ideas, more head-scratching. No smoking gun. We decided to turn it back on and let it soak overnight. The following morning, shortly after sunrise, another trip. Now I had enough information to see a pattern. What was causing a trip every morning shortly after sunrise? Then it dawned on me that perhaps the issue had something to do with the sun warming up the transformer from the overnight freezing temperatures. My theory was that there must be something wrong with the LTC handle or the PRD switch that only shows up in the transition from below-freezing to above-freezing. Fortunately, the weather continued to cooperate and I had a chance to prove my theory. After all, the client wasn’t going to be confident in the solution unless we could prove the theory. Early the following morning, our team showed up before sunrise equipped with a hair dryer (not standard test equipment). We applied some heat to the LTC handle switch and noted that IN106 went high — but only for a moment and then it went low and stayed low. As the switch warmed, moisture created a moment that caused the trip input to go high. With the theory confirmed, we were able to replace the switch and confidently bring the transformer online and restore the plant to normal service.
Blame it on the Rain
Another tricky example began with a call from a client that a transformer had tripped during a heavy rainstorm. A visual inspection found no protective differential or over-current relay targets, yet the 86T relay had been tripped. As in the previous example, you must investigate all the other protective device trips that could operate the relay in question. The list of those items that could operate an 86T is typically short and includes devices like PRDs and a sudden pressure relay (SPR).
It should be noted that both devices provide targets. SPRs are used in conjunction with a seal-in relay. This device, typically located in the transformer control cabinet, provides a target and seals in the trip so that manual resetting is required.
Photo courtesy of NETA.
PRDs will flip up a yellow flag if they lift, assuming the flag isn’t missing or broken. The PRD switch is a latching device that also requires a manual reset. The PRD isn’t as easy to access as it is typically located on the top of the transformer, and the switch is located under the bell housing of the device.
So how could an unflagged PRD or SPR operate the 86T relay, and what’s the weather got to do with it? Simply put, damaged wiring insulation and/or device connectors combined with water intrusion can create a sufficient low-resistance path to complete the trip circuit. This failure mode is almost always related to the PRD since it operates on one normally open contact going closed. In comparison, the SPR has two contacts (one open and one closed), and both sets must change state to trigger an operation in the seal-in unit.
A Mind of its Own
In this final story, a transformer tripped on an 86T relay operation that opened the SF6 breaker ahead of the transformer and tripped the secondary main in a separate e- house. Keeping with the theme, the strange part was, no targets to help explain what caused the operation. A review of the drawings showed several items that could operate the 86T relay: transformer differentials, low gas pressure in the SF6 breaker, and the sudden pressure relay. We verified all the trips, and they all appeared to be operating and targeting properly.
We tested the transformer, and all results including a DGA
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came back acceptable. With no smoking gun, the decision was made to turn the transformer back on and load it, which was all done successfully and without any drama. The transformer serviced the plant fine for about 18 hours. Then, without warning, it tripped by the 86T relay with no targets on the protective devices. What’s going on here? It’s not the SF6 gas breaker low-pressure trip or sudden pressure relay. It must be the HUmodel relays, but there were no targets. So, we tested the relays and verified that the targets operated. Everything on the relays worked perfectly.
We energized the transformer and loaded it again without any issues. The transformer carried the plant for about 18 hours and then, once again, the 86T rolled — with no targets.
The question now was what changed in the plant. Fortunately, one of the engineers spoke up and shared that both of the previous two trips occurred when they were attempting to start a large HP motor. The transformer system was fine when lightly loaded. Only when a full load was being added did the problem reveal itself. Many readers know that it takes a minimum load (usually 30%) before a transformer differential will operate. Now that the relays have tested fine, what’s the problem? With today’s modern relays, troubleshooting a differential trip is so easy a caveman could do it. Older systems with an electro-mechanical differential relay like HUs represented a greater challenge. Our plan to identify the issue required us to energize and load the transformer with the differential relay trips pulled/opened.
Want to measure current magnitude or compare your phase angles on a system with HU relays? You need a current thief and a phase angle meter. Fortunately, we had the necessary equipment. Start with measuring the primary and secondary current into the relay. In most cases, you must do the math to compare the primary current magnitude to that of the secondary. In our case, there was no secondary current. Now it wasn’t zero, but it wasn’t anywhere close to the amount we were expecting. With this new piece of information, our investigation turned to the secondary main current transformers (CTs).
When we walked into the e-house we could hear the audible groan of CTs that are in saturation because of an open CT secondary circuit (more specifically in this case, an extremely high burden/resistance). After making the system electrically safe, the CT secondaries to the remote e-house were tested, and it was confirmed that they had failed in the underground conduit. After pulling and landing new CT secondary wires, the transformer was successfully returned to service.
Now I hope you are asking yourself, “So why didn’t the differential relays target?” It was a legitimate differential fault because of the lack of secondary current input. As it turns out, this issue goes all the way back to improper and incomplete commissioning of the system when installed a decade earlier. The relay targets were set to the 2.0 amp tap, which is an issue in this application because the current necessary to operate the 86T relay is much
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less than 2 amps. For that reason, no targets dropped when the HU relays operated the 86T relay.
After adjusting the relay targets to 0.2 amps and testing the system, we verified that if the HU relay operated and tripped the 86T relay, the targets would operate on all three relays.
Conclusion
Transformer trips are a common problem faced by engineers and technicians in the field. They can be caused by various factors, including weather conditions, faulty wiring, damaged insulation, and malfunctioning protective devices. In many cases, identifying the root cause of the problem can be a challenging task that requires a thorough investigation of all possible scenarios. As demonstrated by these examples, the process of troubleshooting transformer trips involves a combination of technical expertise, attention to detail, and persistence — lots of it.
Editor’s Note: This article was provided by the InterNational Electrical Testing Association. NETA was formed in 1972 to establish uniform testing procedures for electrical equipment and systems.
MOSE RAMIEH is vice president of Business Development at CBS Field Services. A former Navy man, Texas Longhorn, Vlogger, CrossFit enthusiast, and slow-cigarsmoking champion, Ramieh has been in the electrical testing industry for more than 25 years. He is a Level IV NETA Certified Technician with an eye for simplicity and using the KISS principle in the execution of acceptance and maintenance testing. Over the years, Ramieh has held positions ranging from field service technician, operations, sales and business development to company owner.
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WBy JOE WEISS, Applied Control Solutions
e know of control system cyber attacks in the electric power, water, oil and gas, building controls, and transportation sectors that cause physical damages. Another cyber threat that could represent potential physical security dangers involves battery energy storage systems, which vendors, utilities and grid operators
Moss Landing Power Plant, at Monterey Bay. This plant is home to one of the largest battery energy storage facilities in the world, which consists of two BESS facilities.
A port crane lifts a modular container into place. Cyber vulnerabilities cropped up in the systems that operate these cranes.
44205496 © Prasit Rodphan | Dreamstime.com
are relying more upon to make electricity delivery more reliable.
Battery energy storage systems are critical for reliable grid operations where power from intermittent solar or wind loads need to be stored when excess power is available to be dispatched later when there is a lack of power generation. Like other cyber-physical systems, energy storage systems use instrumentation and control systems including process sensors, control systems with logic circuits, communication systems, and inverters that convert the direct current electricity stored in the batteries into alternating current electricity used by the electrical grid. Control systems coordinate the operation of the BESS, including the battery management system (BMS), energy management system (EMS), BESS plant controllers, BESS inverters, fire suppression detection and suppression systems, and their associated subsystems.
The Electric Power Research Institute (EPRI) whitepaper “Insights from EPRI’s Battery Energy Storage Systems (BESS) Failure Incident Database: Analysis of Failure Root Cause” reported that “a significant fraction of BESS failure incidents had an unknown root cause.” When I was managing the EPRI Nuclear Instrumentation & Diagnostics Program, I tried finding actual cases dealing with specific causes, specifically loss of oil in nuclear safety-related pressure transmitters. There were no cases identified in U.S. Nuclear Regulatory Commission (NRC), Institute for Nuclear Power Operations (INPO), or other relevant databases addressing this specific issue by name. Consequently, the more than 200 cases I identified had to be found by reading between the lines. The same happened after starting the EPRI control system cybersecurity program – none of the cases were originally identified as being cyberrelated. With the appropriate understanding, I believe a large fraction of the BESS cases that were identified in the EPRI
report as being from “unknown root causes” were due to control systems, and of that number, a high number would have been control system cyber-related.
“Of the incidents that were classified, there was no single cause that contributed to a majority of failures. The balance-ofsystem components and controls were the leading causes of failure, with the cell having a relatively small number of failures attributed to it. Control failures include those due to control-system incompatibility, incorrect installation of the control system, defects leading to errors in sensors or controls,” the EPRI report went on to state.
Control system issues not identified in the EPRI report include improper settings, lack of control-system coordination and inappropriate operation limits. The EPRI report did not directly mention any of the BESS incidents as being cyber-related.
BESS Threats
As in most industrial and manufacturing processes, temperature is an important consideration. For BESS, temperature considerations manifest themselves in thermal runaway. This phenomenon occurs when a battery becomes self-destructive due to uncontrolled thermal conditions leading to a chain reaction within a battery, causing a rapid increase in temperature and
pressure. This reaction starts when the battery’s internal temperature reaches a point that causes a breakdown of the battery’s internal components. It can escalate quickly, potentially leading to a fire or explosion. To date there have been more than 60 thermal runaway fires at BESS facilities.
Thermal runaway in lithium-ion batteries can be caused by control system cyber incidents whether they are malicious or unintentional because battery monitoring systems, battery inverter systems, and fire detection and suppression systems are monitored and controlled by instrumentation and control systems that have no cybersecurity or authentication.
Cyber Threats
The possibilities of cyber threats are many. Altered control system settings can affect the timing and coordination of monitoring and safety systems. Additionally, cyber intrusions can be developed to insert settings in unused registers within the control system that could lie dormant until activated at the attacker’s discretion.
A report from Sandia National Laboratory identified issues with port cranes but did not identify the cyber issues with Chinese-made transformers that can communicate with battery systems. Because of lack of control system cyber forensics and
Sandia National Laboratory global security staff works with a team from a private Canadian nuclear power plant during a cyberattack exercise on May 17, 2023.
Photo by Craig Fritz, courtesy of Sandia National Laboratory.
training, it is difficult to identify BESS control system incidents as being cyberrelated or whether they are malicious or benign. Process sensors measuring pressure, temperature, flow, gas detection, etc. have no cybersecurity, authentication, or cyber forensics and were not addressed in the Sandia report. BESS control systems use power conversion systems (inverters) to convert DC to AC, issues such as Aurora need to be addressed.
In addition to BESS software, many BESS instrumentation and control systems are also either made in China or have Chinese components, which could be considered security and safety issues. As the Director of National Intelligence (DNI) National Intelligence Council’s wrote in their 2021 National Intelligence Estimate, “China is the world’s leading supplier of advanced grid components for ultra-high-voltage systems, such as transformers, circuit breakers, and inverters, which we assess creates cyber vulnerability risks.”
Presidential Executive Order (EO) 13920 was issued by President Trump May 1, 2020 to address large Chinese-made power transformers because of extra electronics found in a large Chinese-made electric power transformer installed at U.S. utility substation, and a February 2024 EO issued on hardware backdoors in Chinese port cranes because of hardware found in the cranes that should not have been there.
Accidental BESS Fires
As mentioned, there have been more than 60 BESS runaway fire events. The following is an example of an unintentional control system cyber-induced runaway fire case.
Vistra is a Texas-based electricity and power generation company. The company operates the largest battery storage facility in the U.S. at Moss Landing, California. Vistra’s senior director of community affairs said that two “overheating events” happened at the battery plant in 2021 and 2022 because the batteries got wet. A third incident happened in 2022 at the neighboring Elkhorn battery plant owned by PG&E. On Jan. 16, 2025, a large fire at the Moss Landing BESS facility burned tens of thousands of batteries and released heavy metals into the environment.
In the Sept. 4, 2021 incident, fire damaged roughly 7% of the battery modules and other systems. Smoke was detected by the Very Early Smoke Detection Apparatus (VESDA) units, which released and stopped the flow of electrical current through the affected cores (an automated process referred to as e-stop). Due to an apparent programming error in the VESDA, these actions occurred at detected smoke levels below the specified design level at which water should have been released, triggering an e-stop.
This incident shows the difference between network security and engineering as this incident did not have to exceed any high levels or have a denial-of-service to cause a catastrophic problem. The VESDA system was reviewed to ensure it is programmed in accordance with the specifications. This raises the question about the vendor’s software validation and verification process as there have been several fires with this vendor’s battery systems.
The BESS Cyber Compromise
While some system events are not malicious, there has also been evidence of malicious compromises from a cyber vulnerable Chinese-made BESS.
Duke Energy agreed under pressure from the U.S. Congress to decommission energy storage batteries produced by Chinese battery maker CATL installed at Marine Corps Base Camp Lejeune in North Carolina over concerns that the
U.S. Marine Corps Sgt. Logan Elkins, left, from Ohio, with 3rd Battalion, 6th Marine Regiment, and Sgt. Hobart Whitman, from Tennessee with 2nd Light Armored Reconnaissance Battalion, both infantry riflemen, participate in simulated grenade throwing drills at Marine Corps Base Camp Lejeune, North Carolina, Oct. 21, 2024. Camp Lejeune decommissioned a battery energy storage system over cybersecurity concerns.
U.S. Marine Corps photo by Lance Cpl. Bryan Giraldo, public domain
batteries posed a security risk. Reuters reported that Duke Energy had made plans to decommission the CATL-made batteries that had been installed less than a year before, in March 2023. However, by year’s end, Duke Energy had disconnected the battery storage project, with the utility citing concerns raised by lawmakers and experts around CATL’s close ties to the Communist Party of China (CPC).
The batteries and their inverters may have had vulnerabilities that could be used to compromise the electricity grid. According to CATL, its energy storage products sold to the U.S. contained only passive devices, which were not equipped with communication interfaces. While the Duke executives told the congressional staff they were confident in the security of the batteries, they also expressed a desire to address congressional concerns. Executives told Congress that Duke had been considering CATL batteries for about two dozen projects.
Duke Energy stated that the battery system had been designed with “security in mind,” and that the batteries “were not connected in any way to Camp Lejeune’s network or other systems.” However, according to sources speaking on background, China connected with the battery systems at Camp Lejeune, and then reconnected after the system was ostensibly disconnected by the U.S. This could be similar to the backdoors in large Chinese electric transformers or port cranes.
Lack of Relevant Standards
This incident should raise red flags, as Duke is a leader in grid cybersecurity. The demonstration of the back door into the battery system eventually led Sens. Tim Scott and Marco Rubio and members of the Senate Foreign Relations Committee to introduce the Blocking Bad Batteries Act, to prohibit the U.S. Department of State from procuring batteries produced by certain companies.
Similar issues with backdoors in Chinese-made equipment led to presidential executive orders against large Chinesemade electric transformers and Chinesemade port cranes.
The electric utility cybersecurity standards (North American Electric Utility Corporation—NERC Critical
Infrastructure Protection—CIP) do not appear to apply to BESS unique issues. The National Fire Protection Association (NFPA) standard for BESS fire protection is NFPA 855. NFPA 855 has no cybersecurity requirements.
Solving the Vulnerabilities
EPRI in their report and Vistra’s response to the September 2021 fire proposed solutions to address thermal runaway incidents. However, neither solution addressed cybersecurity. The Duke Energy case demonstrates that an appropriate control system cybersecurity training program is necessary even for an industry leader in grid cybersecurity. The NFPA standards for BESS do not include cybersecurity and BESS, being electric distribution systems, are out of scope for NERC CIP standards.
BESS suppliers in the U.S. need to gear up to supply BESS on an acceptable schedule and cost. Utility organizations should specify that BESS need to be US-based and use US designed and built software, systems and components. Cybersecurity needs to be part of the hardware, software and personnel training. NFPA and grid regulators need to develop appropriate control system cybersecurity standards and regulations for BESS and personnel.
Battery systems are cyber-vulnerable. There have been cases where intentional and/or unintentional cyber incidents have caused or contributed to thermal runaway fires. There have been other cases where BESS have been cyber-compromised. Yet there appears to be minimal attention being paid to cybersecurity in the design, operation and training surrounding BESS. There needs to be a focus on cybersecurity standards and training for BESS cybersecurity as it is possible to exploit cybersecurity gaps in BESS used in critical systems.
Editor’s Note: This article appeared originally at Control, an Endeavor Business Media brand covering the process and automation industries. It is republished here with the permission of the author and includes relevant updates.
JOE WEISS P.E., CRISC, CISM, (joe.weiss@ realtimeacs.com) is managing partner of Applied Control Solutions, LLC, in Cupertino, Calif. He has more than 40 years of experience in the field of industrial controls and automation, and more than 20 years of experience working with industrial control system cybersecurity. Weiss holds several patents, has written and presented extensively on controls technology, has testified before Congress five times, and is an International Society of Automation Fellow, an IEEE Senior Fellow, and a Ponemon Institute Fellow.
U.S. Marine Corps Staff Sgt. Alexandra Lamas talks to a Congressional delegation at Marine Corps Air Station New River, North Carolina. The adjoining Marine Corps Base Camp Lejeune decommissioned a battery energy storage system over cybersecurity concerns.
U.S. Marine Corps photo by Cpl. Maurion Moore, public domain
Better Neighbors: The Case for a More Cooperative Power Grid
With power-hungry parts of the US economy poised to grow, policymakers need to take a hard look at how the power grid can be built to be bigger than the weather.
By JEFF POSTELWAIT, Managing Editor
The North American Electric Reliability Corporation recently released its latest glance at the interregional needs of the power grid, and recommended an increase of 35 GW in interregional capacity to address the shortfalls that accompany extreme weather conditions. The experts agree that this is a great start, but the North American grid can do a lot better than just keeping the lights on — and indeed needs to.
“The key takeaway for me is we need to get building,” said Allison Clements, former FERC Commissioner, referring to NERC’s study.
During a conference call organized by the American Council on Renewable Energy, Clements said she felt NERC’s study confirms what many in the industry already suspected: that the U.S. and North America need to beef up its interregional transfer capabilities.
“We are in the middle of a transition. Things are changing and this country needs to build all kinds of infrastructure,” Clements said. “We realize we can’t start picking which kinds of infrastructure and
preferring one without really doing the analysis. We need all kinds.”
Clements went on to name load growth from many sources, intensifying extreme weather affecting broad areas and national security concerns about the supply of reliable electricity as several pressures the power grid is currently under.
A study performed by Grid Strategies and commissioned by ACORE found that if, during 2021’s Winter Storm Uri, ERCOT had access to just another gigawatt of interregional capacity between ERCOT and the Southeast, Texans could have saved $1 billion in power costs. Other severe weather events, such as the “bomb cyclone” of December 2017 that struck the Northeast, the polar vortexes that struck the Northeast in 2014 and the Midwest in 2019, as well as the August 2019 heat wave that hit Texas, have shown that the impact of these disasters can have interregional consequences.
The Role of Transmission
Robert Taylor, vice president of Transmission, New Markets, for power generation developer and owner/operator Invenergy
said many studies have confirmed the need for more cooperation between regions in North America, but getting NERC to underscore that need is important.
“I was driving home on Christmas Eve, I live in Chicago and was going back home to east Tennessee. My parents had rotating power blackouts in east Tennessee and western North Carolina because there wasn’t enough generation capacity and there wasn’t enough transmission capacity to import the power,” Taylor said, adding that the middle of the country was curtailing wind power at the time, but lacked the ability to send it to where it was needed.
Taylor said Invenergy’s flagship project is the Grain Line Express, a 5 GW, 800mile line that connects three regional transmission organizations together.
“Most of the RTOs today view merchant transmission essentially as a generator. So, you are seen as injecting power, and if you want to have rights to withdraw power
Transmission lines cross a bend in the Colorado River in Utah. In the US West, resource adequacy groups have been one way stakeholders have tried to maintain transmission reliability. ID 2643623 © Kushnirov Avraham | Dreamstime.com
and send to the other regions, then you’re viewed as load. So they assume you are going to be withdrawing those megawatts at peak load in their zone, even though that’s not functionally the way you’re going to do these things,” Taylor said.
He said rationalizing the processes involved in interregional transmission operation could be helpful. Another means of relieving stress on the grid could be intertie optimization, or working to maximize the efficiency of the interregional ties that already exist.
“Intertie optimization is one of those things that’s so obvious, you wonder why we aren’t taking this on by now,” he said. “You have existing systems that don’t necessarily let you schedule power in real time. You have to make nominations well in advance and the system changes.”
Studies have shown, he said, that there are times of year where un-optimal nominations have forced RTOs and transmission providers to pull power from where it is needed and deliver it to where it is plentiful, with ratepayers ending up paying for the inefficiency. Events like these increase costs and decrease the reliability of system assets at the times they are needed most, he said.
Merchant transmission corporations like Invenergy can be, in effect, a life insurance policy for grid operators.
“Merchant transmission is not going to build us out of the interregional transmission need that we are going to have, but I think it’s got a role to play. With the costs we are anticipating for some of this buildout, I think it’s a really important piece to be able to balance some of that out,” he said.
Spurring Transmission Expansion
Getting to a more reliable power grid will require all the tools in the toolbox, including power generation and grid enhancing technologies, but transmission will play a key role, Clement said.
“Also, remember it’s FERC’s job to protect customers. I wasn’t a champion of transmission just because I think transmission is great. In fact, it would be a lot easier if we didn’t have to build it. I’m a champion of transmission because it is the way to get to cost effective reliability for customers,” Clement said.
To encourage the kind of transmission buildout that is needed, Clement said with the new administration in charge, states should do what they can to support FERC to take action, as state-level policy choices will not be enough to boost reliability, as the issue affects entire regions. This could be a moment of opportunity for FERC.
“FERC should take action on planning and cost allocation for interregional planning. And of course, as much as FERC can do, we still need Congress to act to ensure we can get interregional transmission built from a siting and cost allocation perspective,” she said.
At this time, FERC should focus on the quick and easy ways to boost system reliability, she said, such as installing grid enhancements, improving efficiencies, exploring surplus connections, and then moving on to the harder, more expensive facets once progress is made, she said.
However, at the time this story was being written, reports came in of a White House executive order claiming greater scrutiny over independent agencies like FERC and requiring that new regulations originating from them to pass through the Office of Management and Budget’s Office of Information and Regulatory Affairs. As is typical with such executive orders, the actual impact on the industries FERC
oversees and the future of its work are unclear at the moment.
Strategic Value
The Trump Administration has frequently mentioned energy as a national security issue, as have many administrations before it. Cy McGeady, a Marylandbased fellow in the Center for Strategic International Studies’ Energy Security and Climate Program, said there is a strategic value to reliable electricity that is often difficult to quantify, but which helps those who have it compete better in the global marketplace.
Growing investment in artificial intelligence, data centers, onshoring of manufacturing, and the electrification of transportation and housing each have two things in common: They are both potential drivers of economic growth, and they both require enormous amounts of cheap, reliable electricity to be profitable.
“So, you think about demand. Well, what is demand? The whole purpose of the system is to serve demand. The demand is serving industries that create jobs and economic value,” McGeady said, noting that both Trump Administrations and the Biden Administration called for the US to become a leader in the above arenas. “When you look downstream from that,
A data center in Middenmeer, Agriport, Holland. Growth in data centers and the power they demand is a driver for strain on the power grid.
Severe weather events, such as the “bomb cyclone” of December 2017 that struck the Northeast, have shown that the impact of these disasters can have interregional consequences. ID 141868808 © Alan Budman | Dreamstime.com
all of a sudden, transmission takes on profound strategic implications, right?”
McGready pointed to northern Virginia, home to one of the largest clusters of data centers in the world, some of which is tied in with the US national security apparatus. The technological growth and
commercial potential at play here both indicate that this cluster will need to grow by double or triple.
“How do you get power into that little corner of the grid? Well, it’s going to have to come from the Midwest. It’s going to have to come from the South. It’s going to have to come from the North,” he said.
There are power plants that may have to fire up at higher use rates, but are unable to if they lack enough transmission capacity. This calls for a more robust power grid infrastructure all around.
“So, it’s not a resource specific issue here. Any and all resources on the grid today and in the future, need to find ways to access these demand clusters that have strategic value above and beyond all these other value assessments,” he said, adding transmission expansion needs to be thought of as a matter of national security.
A Conservative Estimate
Greater reliability is just one of the benefits in boosting interregional transmission, said Michael Goggin, vice president of
Grid Strategies, a consulting firm covering power grid issues. The amount of new capacity recommended by NERC’s report would be in some ways the bare minimum, Goggin said.
“This is the amount of transmission you would want to build if you are just trying to keep the lights on. The optimal amount, the amount that would save your generating capacity, reduce your cost of producing electricity, give you more competition and greater resilience against extreme and unexpected events, all of that is on top of this. So, this is really the floor of what you should be thinking about in an optimal transmission expansion,” Goggin said.
For the purposes of the study, FERC was only asked to look at smart additions to transmission for reliability, or the bare minimum for keeping lights on. The 35 GW in interregional capacity estimate is a conservative one, and does not account for opportunities such as cutting consumer costs by providing cheaper power. It also does not look at how transmission can help you share generation capacity.
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Goggin called for “making the grid bigger than the weather,” meaning using grid interconnections across regions to address the sort of power crunches that happen when extreme cold shuts down power plants, leading to a downstream collapse in ability to serve customers — exactly the thing that happened in Texas in February 2021. These kinds of benefits were outside the scope of the study, but would be a way to save money and prevent the disruptions caused by lack of power.
“We looked across the Eastern Interconnection and ERCOT and found that if you were able to build enough transmission to fully share resources across that footprint, you could reduce the need for generating capacity by 137 GW. That’s about 21% of the peak load of that area,” he said, comparing this to the 35 GW figure mentioned in the NERC study.
Like a Good Neighbor
NERC’s study also did not consider what the Goggin and Taylor called the “neighbors of neighbors” issue, which is the unrecognized
potential of drawing power from sources beyond the closest neighbors of the grid operator needing power at the moment.
“In many cases, there were opportunities to build transmission beyond your immediate neighbors,” Goggin said. “If you were able to build a larger transmission network, build a national network, or at least look beyond immediate neighbors by maybe building a direct current tie across your neighbor or building an alternating current line through your neighbor and then to their neighbor, I think you would be able to keep the lights on in more hours than the NERC study did.”
Building connections such as these could lead to as much as 60 GW in increased interregional capacity, he said. Establishing better relationships between neighbors could, in this way, be much more cost effective than massively overbuilding the transmission system.
Positives
Clements said it isn’t all doom and gloom, naming several recent improvements.
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“I would look at this report in conjunction with NERC’s annual winter assessments that they put out relatively recently for 2024 and 2025. Those are affirming that, again, we are not in a static place. In a lot of ways, things are getting better. We have changes in capacity contracts that are affecting prices but also are starting to move in a good direction,” she said.
Also, FERC approved some new extreme cold weather reliability standards during Clements’ tenure there, she said, which should help natural gas power generation be more reliable and prepared when temperatures drop.
Goggin said winterization standards pushed forward by FERC and NERC will, once fully implemented, require regions to look at extreme heat and extreme cold when planning transmission.
“Hopefully this will drive them to build more transmission to counteract the risks of these extreme heat and extreme cold events,” Goggin said.
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Lea b t D ’ it of t sca
Preparing for NERC Registration and Compliance with New Inverter-Based Resource Rules
Preparing for these new rules can be daunting, but formulating a plan is essential.
By Terry Brinker, Reliable Energy Advisors
As a former manager of registration for the North American Electric Reliability Corporation (NERC) and president and CEO of Reliable Energy Advisors, I have written articles about the risks and challenges of NERC regulations. In my article “Your Audit Report May Be Worthless,” I warned of falling into the trap of thinking your organization has a strong compliance program because you passed an audit. Today, I am sounding the alarm about potentially hundreds of facilities being swept up into the NERC world where fines and penalties can be as high as $1 million per day per violation.
Recently, NERC unveiled updated rules for inverter-based resources (IBRs), which are reshaping the landscape for utilities and energy producers. These new standards aim to enhance grid reliability and security in light of the increasing integration of renewable energy sources, such as solar and wind, into the electric grid. For utilities that are not currently registered with NERC, these changes bring unique
A large-scale battery bank for energy storage. Battery energy storage resources, as well as high voltage direct current circuits and flexible alternating current transmission system devices like static synchronous compensators and static volt-ampere reactive compensators are inverter-based resources.
challenges and obligations. For entities that are currently registered and have additional facilities that will meet the new thresholds, additional documentation will be needed.
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To ensure a smooth transition, non-registered entities must proactively prepare for NERC registration and adherence to NERC standards. This is no small feat, particularly for newcomers to NERC. In
addition, unlike in the past where registration was a voluntary process and an entity could operate undetected by NERC without being registered, NERC has coordinated with reliability coordinators, and transmission operators to identify entities that meet this new threshold where NERC can then force register entities that meet the new threshold. Force registration is a process where NERC places an entity on NERC Compliance Registry (NCR) without the entity’s consent. The day an entity is on the NCR, they are responsible for following NERC reliability standards whether they agree or not. Escaping NERC registration will be unlikely.
Understanding IBR Rules
safeguard inverter-based systems against cyber threats.
These requirements reflect NERC’s commitment to integrating renewable energy resources while maintaining the reliability and resilience of the bulk electric system (BES).
Steps for Utilities
Registration based on the new framework starts in May 2025 and has a deadline of May 2026. For utilities not currently registered with NERC, the prospect of registration and compliance can be daunting. However, following a structured approach can streamline this transition.
identify areas where your operations diverge from NERC standards. This process involves reviewing the new IBR requirements; identifying which NERC standards apply to your organization; assessing current operational, cybersecurity, and data management practices; and identifying deficiencies and areas needing improvement.
The crucial third step in structuring your compliance approach is developing a compliance program. A robust compliance program is critical for meeting NERC standards. If after reading these steps and assessing your organization’s ability to implement the following components, consider outsourcing compliance duties to firms or other utilities that offer NERC managed servicers if your organization is not quite ready to run its own compliance program.
If your organization does not have compliance documents ready on day one of registration, you could be out of compliance. Key components of this will include developing a clear and comprehensive documentation of processes. This may include the need for a professional engineer for some of the technical standards and documentation. The development of compliance documents can also be outsourced.
Ensuring Compliance
NERC’s updated rules focus on addressing the operational and cybersecurity challenges posed by IBRs. The new requirements emphasize performance validation, data sharing and cybersecurity. They are aimed at ensuring that IBRs can withstand and recover from disturbances without jeopardizing grid stability. The rules mandate detailed operational data submissions for effective grid planning and operations. The cybersecurity provisions are intended to strengthen the security framework to
First, you will want to access your applicability. Not all utilities are subject to NERC’s rules. Entities must determine whether their operations meet NERC’s criteria for registration. This includes evaluating the size, capacity, and operational impact of their resources on the BES. If you have a facility(ies) with a 20 MVA nameplate rating and connected at 60 Kv or higher, the countdown is on for you to register.
Secondly, utilities that are subject to these rules should conduct a gap analysis. A thorough gap analysis will
The compliance staffing component also warrants consideration. Operating a compliance program effectively usually means that you need a compliance staff depending on the size of your fleet. In the training step, you make a plan to educate staff on NERC compliance obligations and the new IBR Rules. Finally, the monitoring step, in which your plan requires implementing tools for continuous monitoring and reporting of compliance metrics.
Another helpful step in developing a compliance plan is to bring in industry experts for engagement and collaboration purposes. NERC-registered utilities or consulting firms specializing in regulatory compliance or industry trade groups specializing in generation and renewable energy can be instrumental here. Their expertise can provide valuable insights into best practices and help navigate complex requirements. A
also has a page dedicated to the NERC IBR project.
Key Compliance Considerations
• Documentation: Maintain meticulous records of all compliancerelated activities, including testing, training, and incident responses. Create a repository for each facility. Without evidence, it is nearly impossible to prove compliance.
addressing operational gaps, and implementing robust compliance programs, these entities can position themselves to meet NERC’s standards effectively. Early preparation not only ensures compliance but also fosters a more resilient and secure grid as renewable energy continues to grow in prominence.
To prepare for audits and registration, mock audits and readiness assessments are essential for ensuring compliance. These activities simulate NERC’s evaluation processes and allow utilities to address gaps before official audits. Often peer utilities or trade groups will do these assessments as well as consulting firms.
Getting some additional training on the topic is also useful. There is training on the subject of IBRs integration into NERC. The industry training company EUCI offers a course on the subject. NERC
• Technology Investments: Upgrade existing systems to meet performance and cybersecurity standards for IBRs.
• Stakeholder Engagement: Work closely with regulatory bodies, industry peers, and technology providers to ensure alignment with NERC expectations.
Conclusion
The new NERC rules for IBRs signify a pivotal moment for utilities, especially those not yet registered with NERC. By proactively assessing their readiness,
Learn how real-time simulation and HIL testing are changing the grid
As the energy industry evolves, adhering to NERC’s regulations is not merely a regulatory obligation — it is a critical step toward supporting a sustainable and reliable energy future. Did I mention not adhering to NERC’s regulations can result in fines and penalties up to US$1 million a day per violation?
TERRY BRINKER is a 30-year industry professional with experience leading, facilitating and implementing improvements in power plant operations, control room operations, compliance and regulatory matters. Terry and his firm excel in helping clients navigate NERC compliance matters including, audits, registration, and program management. Terry has an MBA from Indiana University, and a certification in Strategic Management from Harvard University.
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New standards aim to enhance grid reliability and security in light of the increasing integration of renewable energy sources, such as solar and wind, into the electric grid.
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A LINEWORKER’S
Jon Backman
The troubleman for Puget Sound Energy responds to outages, emergencies and public safety concerns in Washington.
• Born in upstate New York but lived his entire childhood in the Pacific Northwest. He has a younger brother and sister.
• Married for more than 20 years to his wife, Christina, an elementary school teacher. They have an 18-year-old son, Sal, a freshman at the University of Washington and a 10-year-old son, Hugo, who loves playing baseball and fishing.
• Enjoys fishing anywhere for anything. He says it remains challenging and continues to present opportunities to learn and improve.
• Relies on troubleshooting tools like the cable thumper, service tester and voltmeter; and always has a set of Kleins handy. As a troubleman, he also can’t live without his computer, which allows him to be more efficient by having all the mapping, work management software and communication apps at his fingertips.
Learning About the Trade
I am a first-generation electrical worker. My introduction to the industry came at a time in my early 20s, when I was in search of direction and a means to secure an income so I could become a responsible husband. My parents had met some people whose sons had attended a lineman college, and they told me about the idea. After a bit of research, line work sounded like a perfect fit for me — just the right combination of physical and mental challenge, combined with a certain element of risk. I’m very fortunate I found my way into this trade, as it’s provided a wonderful opportunity for me to provide for my family while continuing to learn and grow as an individual.
Early Years
My first job at a utility was when I was offered a line apprentice position with Tacoma Power in Tacoma, Washington. While at Tacoma, I received first-rate training and work experience and was very fortunate to learn from a fantastic group of excellent journeymen who took a great deal of pride in their trade. I owe them a debt of gratitude for making me the journeyman I am today.
Day in the Life
Currently, I work as an electric first response troubleman for Puget Sound Energy (PSE). My regular tasks include scheduled customer work and a multitude of emergency response tasks. I respond to outages, emergencies and public safety concerns on our system, subject to overtime callouts around the clock. I respond to storms around the service territory, and recently, our department has become more involved with wildfire mitigation
To learn more about Jon Backman 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.
efforts. I have become more involved with changes and improvements to our system and work practices. We are installing a lot of automated devices and smart grid technology in the field.
Safety Lesson
As a young man in this industry, I was very typical in my attitude of physicality over sensibility, but over time, maturity led to a slow progression in my thinking. I have experienced a few onthe-job injuries, some of which have had lasting effects on my mobility and quality of life, and I’ve learned the hard way from those. There was one tragedy, however, that was close enough I really felt it. During my apprenticeship, our region was hit by a massive windstorm, and we had more than a week straight of storm response work. The utility had its own in-house line clearance tree crews, and during that response, a veteran tree worker attempted to cut a portion of a broken pole that was on the ground. When he made his final cut, there were communication lines still attached to the pole which were twisted under tension, and the pole windmilled with great force, striking him. He was hospitalized with life-threatening head injuries and eventually lost his battle for life. His name was Barry, and everyone liked him and admired him — both as an employee and as a person. This loss was felt by everyone at the utility, and it really brought the reality of the hazards we face to the forefront.
Future Plans
Moving into the future, I want to find a path that allows me to help improve the experience for lineworkers as they navigate their careers. The electric utility industry is in the early stages of massive change and growth. It’s unprecedented, which is exciting but daunting at the same time. I’m eager to contribute in whatever way I can to helping the line trade conquer these challenges.
If you know of a journeyman lineworker we could profile in our Lineworker Focus department, please email Field Editor Amy Fischbach at amyfischbach@gmail.com. All profiled lineworkers will receive a tool package from Milwaukee Tool for their dedication to the line trade.
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Calm seas made for the perfect day to set our first substation topside. Fantastic work by the DEME Group & Semco Maritime teams to set this 3,907 metric tonne (4,307 U.S. ton) beauty on top of the jacket yesterday, a record lift for the Orion!
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Infrastructure Investment: The Key to Energy Dominance & Economic Prosperity
History may not always repeat itself, but it often rhymes. And throughout America’s history, infrastructure investment has driven many of the nation’s significant economic leaps forward.
Whether it was James Monroe’s advocacy for new roads, canals, and bridges; Abraham Lincoln’s leadership enabling transcontinental railways; or the federal highway system championed by Dwight D. Eisenhower, public-private infrastructure partnerships have reliably served as an economic catalyst.
The nation’s infrastructure is once again at a critical juncture. Strategic competition with China on artificial intelligence is straining the U.S. power grid, as new data centers are struggling to come online due to challenges in connecting to new power generation. Persistent inflation and gaps in wealth and income have left many Americans struggling to pay their bills. And recent extreme weather events have left millions without power — and disrupted operations at military bases.
A common thread among these seemingly disparate challenges is a lack of adequate transmission lines connecting America’s balkanized power grids. That lack of infrastructure is contributing to generally rising energy costs, preventing consumer savings on electricity, specifically.
The incoming Trump administration has fortunately recognized this issue, promising to halve energy prices in 18 months. While undoubtedly an ambitious goal — and out of reach for globally priced energy sources — there are several pragmatic actions the incoming Administration can take to position the nation for domestic energy dominance by continuing the American tradition of public-private collaboration to enable needed infrastructure.
First, streamline federal permitting rules. Achieving energy dominance requires maximizing the availability of low-cost, domestic energy production. As it relates to electricity generation, that means reliable access to the most affordable sources of power. Streamlining federal permitting for transmission lines would help private sector developers speed up the completion of new lines — including those connecting neighboring grid regions — which will ensure lower-cost, reliable power in future severe weather events.
Second, maximize the use of existing rights-of-way to enable new American manufacturing and data centers. The U.S. Department of Energy’s Grid Deployment Office recently succeeded in accelerating investment in grid enhancing technologies (GETs) and high-performance conductors (HPCs), which rapidly and cost-effectively add capacity to the existing grid footprint.
Third, take regulatory action to enable more efficient transfers of power between grid regions in the Eastern half of the U.S. Requiring optimization of existing interties, the points at which the regional power markets connect, would save businesses
millions annually on their power bills. Regional market monitors in New England, New York, and the Mid-Atlantic have recommended such reforms for about two decades. Optimizing interties and available transmission in the West collectively saved consumers more than $4 billion from 2014 to 2023, while similar optimization in the East could provide approximately $50-60 million annually in additional value.
Finally, lean into the bipartisan goals to increase energy security and domestic manufacturing. The President and Congress have an opportunity to work together to encourage and incentivize the development of more American-made electric transformers and the components for high-voltage lines that are needed to efficiently deliver power long distances. This issue is particularly salient as America’s economic competitors in China and the European Union continue to buy up the global supply of key technologies to modernize grid infrastructure.
History also serves as a guide on what happens when nations neglect to make investments in infrastructure advancements at critical junctures. For example, in the early 1800s, the Hapsburg Empire feared the potential creative destruction of market forces enabled by the Industrial Revolution. Francis I, the first Emperor of Austria, wanted to lock in the status quo to protect existing elites and thus blocked the construction of railways.
Since the government would not grant a concession to build a steam railway, the first built in the empire had to use horsedrawn carriages. Design choices necessary to accommodate the carriages subsequently made it impossible to convert the route to enable steam engines — delaying decades of economic progress before steam engines were implemented in the 1860s, after a revolution. In short, efforts to protect outdated interests from new technologies cemented dated infrastructure as other nations raced ahead. It was one of many costly mistakes the Hapsburgs never recovered from.
While the U.S. is, of course, not a monarchy, similar perverse incentives exist here today. Recent studies demonstrate that significant new interregional transmission is needed to grow the American economy and ensure reliable power service — yet it’s not getting built.
Our new national leaders have the chance to change that dynamic and build an economic success story. There are 1.3 million jobs possible from enabling the completion of just 36 high-capacity transmission projects that are “shovel ready” today.
Let’s build on the infrastructure lessons learned from Monroe, Lincoln, and Eisenhower and have this page in America’s history books similarly prosperous. Stronger grid infrastructure powered by our most affordable, reliable, and clean technologies will benefit us all.
KEVIN O’ROURKE is SVP, development and public affairs, at ACORE.
