Winter Storm Fern delivered the kind of cold that grid operators and generators dread, driving up electricity demand, squeezing fuel systems and forcing regions to lean hard on dispatchable resources that can run when wind and solar output dips.

So how did North America’s generating fleet perform during Fern as wintry conditions continue to grip large swaths of the U.S., with additional cold weather forecast to move into parts of the East Coast this weekend?

“It’s still probably a little early to tell,” NERC’s John Moura said during a media briefing Thursday as the cold persisted in parts of the country. “But what I will say is, you know, as we’re looking at the data, both on the electricity generation performance, but also the gas performance, things are holding up.”

The dispatch response was clear in the federal data. In the week ending Jan. 25, coal-fired generation in the Lower 48 states increased 31% from the prior week as Fern affected large portions of the country, according to the U.S. Energy Information Administration (EIA). Natural gas generation rose 14% over the same period, while generation from solar, wind and hydropower declined.

Coal’s share of total Lower 48 generation climbed to 21% during that week, up from 17% the previous week, EIA said, while natural gas contributed 38% and nuclear was about 18%.

In New England, the fuel picture turned more extreme. Although petroleum accounts for less than 1% of total U.S. utility-scale generation, the region leans on oil-fired units during winter peaks when cold weather drives demand and natural gas availability tightens. During Fern, petroleum became the predominant energy source, beginning around midday Jan. 24 and lasting until early Jan. 26, EIA said.

EIA noted that New England holds a disproportionate share of the nation’s petroleum-fired capacity and that petroleum-fired generation reached almost 8.0 GW between Jan. 25 and Jan. 26, exceeding the capacity from units that predominantly use petroleum. That indicates fuel-switching units contributed as well, including a sizable portion of the region’s natural gas fleet that can burn distillate fuel oil when gas is too costly or unavailable.

ISO New England is now bracing for the next phase: sustained high demand as the cold lingers, and the operational challenge of replenishing stored fuels. The grid operator said it plans to publish updated 21-day forecasts each morning through the weekend, rather than its typical weekly cadence, to reflect heightened uncertainty.

ISO New England also said it will request a two-week extension of the existing U.S. Department of Energy order under Section 202(c) of the Federal Power Act. The order, which allows all available resources, including those subject to emissions or other permit limits, to operate if needed, currently expires Jan. 31. ISO New England said it will ask DOE to extend it through Feb. 14.

Further south and west, Texas avoided the kind of systemwide emergency that still looms over winter planning after 2021. In a post-event report dated Jan. 28, ERCOT said it managed the statewide grid through Fern without calling for conservation, without issuing an Energy Emergency Alert, and without any systemwide outages tied to grid conditions.

The grid operator said it leaned on mandatory weatherization, increased reserves, earlier operational actions and a market design change implemented in December 2025 that incorporates batteries into real-time co-optimization.

Some outages did occur in Texas, ERCOT said, but they were localized and tied to ice and downed lines rather than bulk system failures.

In PJM’s footprint, the operational posture included preparing for a tool that, until recently, sat mostly outside the normal reliability playbook: directing certain customer-owned backup generation at data centers and other large-load sites to operate under emergency conditions.

On Jan. 26, DOE issued an emergency order to PJM under Section 202(c) authorizing PJM to direct identified backup generation resources to operate as a last resort before an Energy Emergency Alert Level 3 is declared, or during an EEA 3.

PJM said in an update that the expedited federal process for emergency orders tied to backup generators could help as a last resort if the generation fleet or transmission system experiences major outages, and that it has been working with DOE to identify data center customers who have volunteered to transition to backup generation if needed.

NERC, which highlighted winter energy risks in its 2025-2026 Winter Reliability Assessment, is watching Fern as a real-world stress test of fuel and performance assumptions.

Moura said Thursday that the storm has already produced some operational surprises, including curtailments of interconnections between New England and Canada.

He also pointed to forced outages, noting that a detailed accounting will come later.

“We’ve had a good amount of generators that have been forced out, offline,” he said. “We will come to find those.”

Still, Moura said there is evidence that winterization investments and standards have improved performance compared with prior years.

“What we have done is put a number of NERC standards in place, and there’s been a lot of PUC action on winterization,” he said. “Billions of dollars in winterization have been invested in winterizing the generation fleet, and some of that seems to have worked.”

Coal’s role during Fern sits at the center of a larger debate about reliability through the energy transition, and Moura addressed it directly when asked whether coal provided primary support during the event.

“I think it’s an essential part of the portfolio today,” he said, while also noting the fleet’s limitations, including higher forced outage rates in winter conditions and challenges such as frozen coal piles.

Reliability risk across North America is rising over the next decade as electricity demand growth, driven largely by new data centers, outpaces the pace of new generation, transmission and fuel infrastructure needed to support it, the North American Electric Reliability Corporation (NERC) said Thursday in its 2025 Long-Term Reliability Assessment.

NERC said summer peak demand is forecast to grow by 224 gigawatts (GW) over the next 10 years, a more than 69% increase over the demand forecast in last year’s assessment. Winter peak demand is projected to rise even faster, up 246 GW over the same period, as electricity use patterns evolve and more end uses shift toward electric heating and other winter-peaking loads.

“This assessment is not a prediction of failure but an early warning on the trajectory of risk,” John Moura, NERC’s director of Reliability Assessment and Performance Analysis, said during a media briefing Thursday. “The path forward is still manageable but only if planned resources come online and on time.”

NERC’s long-term assessment is built from a mid-2025 “snapshot in time” based on utility and market projections, and it is intended to flag areas where resource adequacy could tighten under the current buildout trajectory. In the briefing, Moura emphasized that the biggest issue is not a lack of awareness, but the speed of change.

“Reliability risk is increasing, and really not because we lack awareness, but that the system is changing faster than the infrastructure need to support it,” Moura said.

Mark Olson, NERC’s manager of Reliability Assessments, said the report’s risk map reflects the highest risk category each assessment area reaches over the next five years, using reserve margin targets and probabilistic analysis to evaluate the likelihood of unserved energy and load loss. Olson said more areas show elevated or high risk as demand projections rise and resource plans become more uncertain.

The report argues that uncertainty is now a structural feature of resource planning, and that timing has become as important as megawatts. NERC said projected retirements remain high, with 105 GW of seasonal peak capacity planned to retire over the next decade, although that total is down 10 GW from the prior assessment.

At the same time, the composition of planned additions is shifting quickly. NERC said battery storage projects have grown to match solar projections, and that natural gas additions represent about 15% of projected capacity additions, followed by wind and hybrid resources at 8% each.

During the call with journalists Thursday, Olson described a key seasonal challenge that planning models are now surfacing more clearly: resources in the development pipeline may show strong capability for summer peaks, but a very different contribution in winter.

“When we look at what their winter capability is, we can see this shortfall emerging where a lot of resource development is going to be needed in order to meet year-round peak demand and pay close attention to those winter demands,” Olson said.

NERC also pointed to lagging transmission development as a constraint on both reliability and resource delivery. The assessment notes that projected transmission development is rising compared with last year, but that miles of projects under construction have not increased substantially yet, and that delays tied to siting, permitting and other process hurdles remain common. Olson said interregional transmission projects are especially important during wide-area weather events because they can support transfers between neighbors.

Moura said the grid’s changing mix is altering what “stress” looks like, and why planning needs to move beyond traditional reserve margin thinking.

“We must move beyond margin only thinking to thinking about probabilistic and energy risk analysis,” he said.

In the briefing, Moura also pointed to system performance concerns that are not captured by an energy-only risk map, including stability challenges during periods of very high inverter-based resource output. He said the industry is paying closer attention to essential reliability services such as inertia, voltage support and frequency response.

“We’ve seen examples of that in the international space, including the recent Iberian Peninsula outage that underscored the need to manage system performance during periods of high inverter-based resource output,” he said.

The assessment’s headline demand story is closely tied to data centers. Olson said new data centers are the main driver of load growth in many areas, though large industrial loads and electrification also contribute.

During the briefing, Moura said flexibility from data centers could help them interconnect faster and reduce the need for near-term system upgrades if their peak contribution can be managed.

“If data centers can offload their demand usage to their backup centers or move load to different data centers … that flexibility, if that can happen and they are committed to not being there on during peak conditions, well, then they can be interconnected a little quicker,” Moura said.

NERC’s recommendations focus on speeding infrastructure development and improving coordination. The organization urged streamlining siting and permitting for generation, transmission and natural gas infrastructure, managing generator deactivations carefully, expanding adequacy assessments that incorporate energy limitations, and improving electric-natural gas coordination as reliance on gas-fired generation increases.

The bottom line, Moura said, is that the trajectory is moving in the wrong direction, but there is still time to bend it.

“The question is no longer whether the change is coming,” he said. “It’s whether the infrastructure and coordination can keep pace.”

Winter Storm Fern has passed, but roughly half a million Americans were still without power or heat on Tuesday, and temperatures were forecast to fall well below freezing in areas where the massive ice storm did its worst damage.

The U.S. Department of Energy (DOE) issued new emergency orders on Monday aimed at keeping power available as extended cold from Winter Storm Fern drives up demand and stresses fuel and generation availability in parts of the U.S.

One order authorized NYISO to run all generating units in the grid operator’s region and operate them up to maximum output levels, even if doing so conflicts with air quality or other permit limits, or if fuel shortages emerge during the emergency period. The order took effect Jan. 26 and runs through Feb. 2.

DOE issued two separate orders focused on behind-the-meter backup generation at large-load sites, authorizing both PJM Interconnection and Duke Energy Carolinas/Duke Energy Progress to direct certain backup resources at data centers and other large customers to operate as a last resort before an Energy Emergency Alert level 3 is declared, or during an EEA 3. The PJM order expires at 11:59 p.m. EST Jan. 31, and the Duke order expires at 11:59 p.m. EST Jan. 30.

Another order covers Duke Energy’s balancing areas on the central-station side, authorizing generating units in the Duke region to operate up to maximum output levels, regardless of air quality or other permit limits. It became effective at 12:00 a.m. EST Jan. 27 and expires at 12:00 p.m. EST Jan. 30.

DOE is using Section 202(c) to widen the operating envelope in multiple regions, both by authorizing grid operators to push central-station units harder and by allowing system operators and utilities to lean on customer-owned backup assets when grid conditions deteriorate. 202(c) is a temporary emergency authority that can require changes to how the electricity system operates during qualifying emergency conditions.

DOE’s actions began Jan. 24 with orders to PJM and ERCOT. The PJM order authorized operation of generating units across PJM up to maximum output levels, “notwithstanding” permit limitations or fuel shortages during the emergency window, effective Jan. 25 through the end of the day on Jan. 31.

The ERCOT order authorized the Texas grid operator to direct backup generation resources at data centers and other large-load customers under the same “last resort before EEA 3 or during EEA 3” construct, expiring at the end of the day on Jan. 27.

About 130,000 customers had no electricity in the Nashville, Tennessee, area, according to poweroutage.com. About 140,000 remained without power in Mississippi, and nearly 100,000 more in icy Louisiana.

Winter Storm Fern has exited stage right, but not before wreaking havoc on power grids across the southeastern United States. As of Monday morning at 9 am ET, more than 800,000 customers were still without electricity after Fern pummeled a vast swath of the US with snow, sleet, and ice amidst subzero temperatures.

According to live tracker PowerOutage.com, Tennessee (250,459), Mississippi (161,059), and Louisiana (127,719) have the most outages, followed by Texas (66,665), Kentucky (47,624), and South Carolina (44,114). Tens of thousands of power outages persist in Georgia, North Carolina, Virginia, and West Virginia.

A Deadly, Icy Mess

More than a dozen deaths have been blamed on the winter storm already, and perilous conditions persist through the day Monday, creating “dangerous travel and infrastructure impacts” for days, according to the National Weather Service.

For utilities, that means power poles and lines damaged or broken under the weight of ice. Predictions called for up to a staggering 1.5 inches of ice accumulation in some areas, including northern Mississippi and the western Carolinas. For reference, half an inch of ice (or less) is all it takes to down a power line and trigger widespread outages.

On Sunday, freezing rain slickened roads and brought trees and branches down, imperiling hundreds of miles of the southern US. In Corinth, Mississippi, heavy machinery manufacturer Caterpillar told employees at its remanufacturing site to stay home Monday and Tuesday. In Oxford, MS, police appealed to residents to stay home, and some utility crews were pulled from their jobs overnight.

“Due to life-threatening conditions, Oxford Utilities has made the difficult decision to pull our crews off the road for the night,” the utility company posted on Facebook early Sunday. “Trees are actively snapping and falling around our linemen while they are in the bucket trucks.”

Elsewhere, deep snow — over a foot (30 centimeters) in a 1,300-mile (2,100-kilometer) swath from Arkansas to New England — halted traffic and canceled flights.

President Donald Trump approved emergency declarations for at least a dozen states by Saturday. The Federal Emergency Management Agency had rescue teams and supplies in numerous states, Homeland Security Secretary Kristi Noem said.

Hardest-Hit Utilities and Their Response

Tennessee’s Nashville Electric Service (NES) and Entergy (primarily in Louisiana) remain the heaviest-hit utilities Monday morning. More than 175,000 Nashville Electric subscribers are without power, representing nearly 38% of its customer base. More than 147,000 Entergy users are still waiting for their lights to come back on, or roughly 5% of the total served by the utility in LA.

NES says teams of nearly 300 line workers have been deployed around the clock to make repairs and restore infrastructure. The utility says more than 76 broken poles have already been fixed. More than 70 distribution circuits are out and are being restored. Since Saturday, crews have been operating in continuous rotations and will remain on extended 14–16‑hour shifts.

Icy conditions have limited restoration progress in its territories, according to Entergy. Overnight, temperatures dropped below freezing, hampering travel and causing additional outages in some locations. As of Monday morning, the utility reported more than 88,000 outages in Louisiana and another 55,000 in Mississippi. As of Sunday evening, transmission damage assessments show approximately 20 transmission lines, 470 miles, and 20 substations out of service across Entergy’s service area. Around 10 transmission lines and 30 substations have been returned to service. At least 400 poles, 90 transformers, and 1,460 spans of wire were damaged; more than 20 poles, 20 transformers, and 70 spans of wire have been restored so far.

Duke Energy, Southwestern Electric Power Company, and Appalachian Power Company each have just north of 30,000 customers still without electricity. Tri-County EMC, Blue Ridge Electric Cooperative, North East Mississippi EPA, and Cumberland EMC are still working to restore services for more than 20,000 customers.

Reporting from the Associated Press was used in this article.

Originally published in Factor This.

Stay with Factor This Power Engineering for updates.

U.S. Energy Secretary Chris Wright on Jan. 22 directed grid operators to be prepared to call on unused backup generation at data centers and other large facilities as Winter Storm Fern bears down on much of the country this weekend.

The storm is testing the electric system across multiple regions, with heavy snow, sleet and freezing rain spreading across the south-central U.S. and moving east through Sunday. As of Saturday morning, more than 95,000 power outages had been reported nationwide, including roughly 36,000 in Texas and about 10,000 in Virginia.

According to the U.S. Department of Energy, more than 35 GW of backup generation capacity remains idle nationwide. DOE said making those resources available, if needed, could help mitigate the risk of rotating outages during periods of extreme cold and high demand.

The draft emergency order, issued under Section 202(c) of the Federal Power Act, would apply to data centers and major industrial or commercial facilities with auxiliary, standby, directly connected or battery storage resources. The order would allow grid operators to call on those resources only after demand response options are exhausted and before a Reliability Coordinator declares an Energy Emergency Alert Level 3.

The action aligns with warnings raised in the North American Electric Reliability Corporation 2025 Winter Reliability Assessment, released in November. The assessment found elevated risk across much of North America of insufficient energy supplies during extreme operating conditions.

NERC urged Reliability Coordinators, Balancing Authorities and Transmission Operators in higher-risk regions to review seasonal operating plans and communication protocols for managing potential supply shortfalls. The assessment also emphasized advancing winterization measures and securing fuel supplies to ensure generation remains available during prolonged cold weather events.

“At this time, NERC is encouraged that industry has taken actions to prepare for what appears to be a very challenging winter storm system,” the organization said in a statement Jan. 22.

In a separate update issued Jan. 23, PJM Interconnection said it has issued precautionary alerts ahead of the winter storm and an extended period of extreme cold expected to affect much of its footprint, which spans 13 states and the District of Columbia. Forecasts call for single-digit temperatures across much of the RTO between Jan. 23 and Jan. 27, with subzero conditions possible in PJM’s Western Region.

PJM peak demand could exceed 130,000 MW for as many as seven consecutive days next week, a duration PJM said it has never experienced during winter operations. Depending on conditions, PJM could also set a new all-time winter peak load on Tuesday, Jan. 27.

PJM said it is taking additional precautions with generation and transmission owners, including issuing Cold Weather Alerts and expanding them to the full region through Jan. 27. The alerts prompt coordination with generators to ensure staffing levels are sufficient, units are fully winterized, and operational limitations are accurately communicated to the grid operator, including startup times and minimum and maximum run durations.

PJM said it is preparing for the possibility that the cold weather could extend into early February and emphasized the importance of fleet performance during sustained, high-load conditions.

CPS Energy Chief Strategy Officer Elaina Ball has spent years in an industry built around machines that cannot be allowed to fail. She has also raised a family. On Wednesday afternoon at POWERGEN 2026, she offered a comparison that drew knowing laughter from a room full of power professionals.

“I don’t know what’s worse, a colicky turbine or a colicky baby, but both keep you up at night,” Ball said.

The power generation industry does not pause for convenience, and neither does life. The inaugural Women in Power panel at POWERGEN 2026 Wednesday leaned into that reality, pairing candid stories about leadership, self-doubt and risk, along with lessons about building a career in an industry that often demands everything.

The panel and subsequent networking event, sponsored by Kingsbury, was held at the Center Stage in the exhibit hall at the Henry B. Gonzalez Convention Center in San Antonio.

Jhansi Kandasamy, vice president of advanced nuclear at The Nuclear Company, framed the discussion as both overdue and broadly representative of where the power sector is headed. She traced her own career through four decades in nuclear, beginning in electrical engineering and expanding across nearly every major plant and corporate function.

“This is amazing to be a part of the first inaugural women in power,” she said. “I love that this panel really represents very diverse positions or diverse energy fields.”

Ball anchored her remarks in the operational reality of a vertically integrated municipal utility serving Central Texas. When asked about defining challenges, she focused less on technology and more on timing.

“I’ve been a wife and a mother while running very large power plants,” Ball said. “I think one of the most challenging experiences that that I have throughout my life is just, it’s not work-life balance, but it is about understanding the seasons of your life and the seasons that you go through as a working mother.”

She described early mornings, nights and weekends that came with balancing plant operations with family life.

“There were times when I had to forego work responsibilities to be at a band concert,” she said.

Those tradeoffs, she said, shaped her leadership approach.

“Give yourself grace,” Ball said.

Gretchen Dolson, senior vice president and renewables practice lead at HDR, described a career built through pivots rather than planning. A registered civil engineer, she started in heavy highway and municipal work before moving through water resources, industrial facilities and biofuels, eventually transitioning into power.

She said her most difficult lessons were not technical. Mentors helped her recognize that leadership required more than delivering projects on time and on budget.

“What I maybe didn’t do so well was communicate with my own team, and I have almost zero empathy,” said Dolson. “If you do like the personality test, oftentimes, women who are driven don’t necessarily have some of those soft skills.”

Meghan Eyvindsson, general manager for the Americas at Stamford | AvK, offered a story that began far from an executive role.

“I have a very non-traditional educational and professional background,” she said. “I am the cliche college dropout. Originally, I pivoted and went to cosmetology school, so I was working as a hairdresser before I stumbled into power gen.”

She applied for a receptionist job at a Cummins distributor in Wyoming and did not get it.

“I was devastated,” she said, believing she had failed. Two weeks later, the company called back with a different offer in parts.

“My first thought was, I don’t know anything about diesel parts,” she said. Then she reframed the moment. “What I do have is the desire to learn, and I’m capable, and I can do hard things.”

That experience shaped her leadership philosophy.

“I end up looking for potential, not credentials,” Eyvindsson said. Even now, she admitted, self-doubt persists.

“I still feel like I can’t believe I’m sitting on the stage,” she said, recalling that when she was offered her current role, her first thought was, “Why me?”

Eyvindsson argued that “soft skills” and “relationship building” are often treated as secondary to technical expertise, even though the industry’s challenges now require teamwork across disciplines, geographies and business models.

“If we all had the same skill set, we wouldn’t have the diversity of solutions,” she said.

As the conversation turned to mentorship, the panelists emphasized that advancement often comes through sponsorship and visibility, not just advice. Eyvindsson credited a mentor who taught her to set boundaries.

Dolson described mentorship as a series of relationships over time, adding that her earliest influence was her mother, who taught her, “You can fail, but you aren’t quitting.”

Kandasamy closed by naming what she sees missing at the highest levels of the industry.

“What I noticed moving up is less and less women sitting across the table,” she said. Paying it forward, she added, means “making room,” recognizing talent and making contributions visible.

Then the microphones went down and the networking began, with a roomful of power professionals trading stories that, like Ball’s opening line, were equal parts demanding and familiar.

As artificial intelligence and data centers reshape the energy landscape, power providers are racing to meet soaring electricity demand with speed, reliability and sustainability in mind.

At the Wednesday morning Keynote at POWERGEN 2026, hosted in San Antonio, Texas, industry leaders explored how the sector is rethinking resource planning, generation strategy and customer partnerships to keep pace.

The session was moderated by Richard Esposito, R&D Program Manager – Southern Company, and featured Gene Alessandrini, SVP of Energy and Location Strategy – CyrusOne; Simon Tusha, CEO – TECfusions; Jennifer Knott, Executive Director, Strategy Implementation – NextEra Energy; and Elaina Ball, Chief Strategy Officer – CPS Energy.

‘We’re not good communicators’

Tusha, whose company TECfusions designs, builds, and manages data centers, addressed the elephant in the room head on: the negative sentiments surrounding data centers stemming from environmental and price concerns, to name just a few.

“As an industry, we are really good engineers,” Tusha said. “We’re really good dealing with public officials. We’re not good communicators. There’s not a single social influencer in the room doing a Tiktok or some sort of little viral clip. You know, we’re getting our ass handed to us in the public messaging […] This is as much of a PR process is it is anything.”

At NextEra energy, being proactive is key, Knott argued. The company sees communities expressing some concerns about data centers that may be have been addressed years ago – while others have valid concerns that shouldn’t be ignored.

“As we go into into the communities, you get questions that are maybe based off of what was being done five years ago, and things have have changed significantly since then,” Knott said. “So I think being proactive and going into the community and saying, ‘here’s here’s the benefit, here’s the jobs we’re going to bring, here’s the the opportunities that this is going to create,’ while also acknowledging some of the constraints around putting a data center. What is the water consumption? Don’t sugarcoat the concerns, but address them head on.”

Alessandrini, whose employer CyrusOne also designs, builds, and operates data centers, noted that data centers are not a new, unheard-of phenomenon – they’re just coming online in a scale that most never anticipated, causing noise and confusion.

“I think the industry wanted to be a quiet industry,” Alessandrini said. “They just wanted to quietly put up data centers. Nobody knew they were there. They generally don’t make a lot of noise. But now that they’re scaling so large, they’re consuming a lot more energy, and because of that it’s putting more stress on the electrical grid, and because it’s putting more stress on electrical grid, that gets to […] the headline news, right?”

‘The rules are not yet written’

While many RTOs, ISOs, utilities, and regulators are attempting to address data center capacity concerns, we’re still essentially in the wild west portion of the data center boom: the rules and foundations just aren’t all there yet.

“One of the biggest challenges we’re seeing is the rules are not yet written, right?,” Knott said. “I think everybody’s trying to figure out, how do we bring these large loads on online? And so it’s really a partnership between developers, the ISOs, load serving entities, to figure out: how do we do this, how do we do it safely, how do we do it reliably?”

Tusha wasn’t too optimistic about the future regulatory landscape – arguing that regulators are responding to public pressure and would “screw it up.”

“The regulators that are doing this are they’re not responding to the science,” Tusha said. “They’re responding to the political winds that are blowing back and forth, ebbing and flowing.”

BEHIND THE METER?

“Generally, in today’s market, due to the constraints and challenges, the timeline for delivery for power is generally five to seven years,” Alessandrini said. “So with that, and us trying to plan the based on the market demands we have, we are now looking at alternatives.”

CyrusOne is taking a three-tiered approach to data center power development: co-location, co-development, and larger scale projects. Depending on scale, co-development can be take two years, co-location could take two to three years, and larger scale projects could take three to five years. The end result is a relatively consistent delivery portfolio with all three options blended together. Then, later down the line, the facilities still have the option to acquire a grid connection once things have settled down.

“In all honesty, the data center is not necessarily going to wait,” Alessandrini said. “They’re going to be constructive and collaborative, but they’re going to continue to go down this behind the meter generation solution.”

Facing lengthy interconnection queues, TECfusions has also gone all-in on behind-the-meter generation.

“Because interconnection agreements take so long, we’ve just said, ‘Okay, we’re going to be FERC 2222 compliant,'” Tusha said. “We’re going behind the meter and we’re just leaving it and just literally walking away.”

Speed to market

At CPS Energy, projected load growth and old, aging assets have forced the utility into action.

“We have some very new assets, and then we have some assets that have earned their AARP cards,” Ball said. “This is not about politics. This is about very old assets that that are at an end of life. So we are retiring conventional gas assets and converting some assets. And over the last three years we we’ve had a plan to add about 5,700 megawatts to our fleet by the end of 2030 – we’re about 82% there.”

Ball also discussed how the utility is addressing those shortfalls by making some thrifty investments in the gas space, acquiring assets for less than the cost of construction.

“We decided on the gas front to take a different strategy,” Ball said. “We are fortunate to operate into a very integrated, competitive, wholesale market. S we entered into several processes to acquire assets, and we’ve been successful in bringing on over 3,300 megawatts of natural gas assets well below the cost of construction that are operating assets now. It’s actually reduced our expected cost from over $5 billion in new build, and we’ve reduced that that capital outlay by $3 billion, so we’ve acquired these assets for just about a little more than $2 billion.“

One thing has become clear to CPS Energy over the past year or so: it’s all about speed over anything else.

“We have everything from behind the meter, in front of the meter, gas, fuel cell – you name it,” Ball said. “The conversation has changed here in the near term […] The conversation is all speed to market.”

With explosive load growth projected from data centers, manufacturing and electrification, grid operators are warning of looming capacity shortfalls. At the same time, generators are facing mounting pressure to adapt to evolving market structures, seasonal reliability risks, and shifting regulatory expectations.

At the Tuesday afternoon Keynote at POWERGEN 2026, hosted in San Antonio, Texas, energy executives shared how their regions are responding to these challenges: Implementing market reforms, rethinking capacity accreditation and rebalancing risk across market players, while also exploring what these changes mean for utilities and IPPs seeking to stay competitive and reliable in a grid under strain.

The session was moderated by Hari Gopalakrishnan, Manager, Market Strategy – Mitsubishi Power Americas and featured Keith Collins, Vice President of Commercial Operations – ERCOT; and Casey Cathey, Vice President, Engineering – Southwest Power Pool (SPP).

‘What is the alternative?’

The early aughts were a period of heavy gas development – but recent deployments, including a much bigger share of renewables, have put that growth to shame. However, as the modern resource mix begins to take shape, gaps and bottlenecks have begun to emerge.

In ERCOT, the shift toward solar in particular has created a unique problem: what we have typically thought of as the period of most stress has changed. Peak demand is still occurs around the late afternoon, but a significant amount of solar generation is operating during this period – including charging battery storage. Instead, the greatest period of need on the system in terms of system stress has shifted to later in the day – around eight or nine in the evening – resulting in higher prices.

In Collins’ eyes, this issue has opened up opportunities for new technologies to help allow the grid to adapt to this new reality, including synthetic inertia or gid-forming technologies. But another issue remains: winter.

“The challenge is during the winter months, and ultimately, the average storage duration in ERCOT is about one and a half hours,” Collins said. “And when you think of a cold winter spell, it can, can require not just a single peak during the day, but a double peak during the day. And the challenge there is having the storage capable of meeting a morning peak period as well as an evening peak period.”

New transmission will be an inevitable necessity to help ease some grid strain, Cathey argued.

“This is an investment – transmission is not cheap,” Cathey said. “But the question is, what is the alternative? We are maxed out on our transmission system, and we need to be able to build transmission to complement necessary supply. We, quite frankly, need both. We need generation and transmission to be able to support the future.”

‘We could have a problem’

ERCOT’s system peaks at 85 GW, but is staring down the barrel of over 230 GW of new demand. Unsurprisingly, most of that demand is coming from large load data centers.

“If we start connecting all the large loads, and you look at the growth of resources we have in our system, we could have a problem in the next few years,” Collins said.

As recently as seven years ago, SPP was excited to see 1.2% year over year load growth. Now, it’s seeing upwards of 5% year over year growth, which Cathey said he hasn’t seen in his whole career. The SPP system currently peaks at 56 GW, but at least 110 GW are waiting in the interconnection queue.

SPP has been undertaking a wholesale changing of its fuel mix – swapping out old coal plants and replacing them with wind and solar. But the hefty amount of new generation waiting to interconnect to replace aging generation has also caused delays.

“At one point in time, the [generator interconnection] process worked, but it was never designed for a wholesale fuel mix change and swapping out the entire supply of multi state region,” Cathey said.

At SPP, a new performance-based accreditation process will go into effect next cycle, which is meant to ensure generation shows up when it’s called on. But it’s difficult to accurately plan for the future without leaving gaps or overcompensating.

“We have 64 load responsible entities, utilities that meet these resource adequacy requirements,” Cathey said. “One of the challenges we’re seeing is the nature of the system is changing so fast, even if we set a planning reserve margin four years in advance, it’s hard to have a reliable number to give them for a particular resource.”

To help alleviate this, SPP recently filed what it calls a consolidated planning process with FERC which essentially adds the generation interconnection process into SPP’s regional transmission plan. Generators would have an upfront cost to connect under this process.

“There’s no games around, playing chicken with another developer, trying to withdraw from a queue and then seeing what the results are, seeing if you don’t induce certain electric or extra high voltage facilities, and being hit with hundreds of millions of dollars of cost,” Cathey said.

Short-term plans

Some technologies like geothermal and next-generation nuclear could help ease much of the strain on the grid. The problem, however, is that they’re just not mature enough yet. Collins hopes this will change in the next five to 10 years, but what about in the meantime?

Natural gas has been a no-brainer for getting generation online quickly, but with that supply chain facing backlogs, it could take years to get a turbine. Power producers could pay to take someone else’s spot in the turbine queue, but this isn’t sustainable for the industry as a whole.

So for the short term, we’re left with the relatively quick deployments of solar and storage – with solar taking around 24 months and storage taking between 12-18 months to come online. But recent policy shifts at the federal level have raised questions about this solution as well.

“Obviously, federal policy has changed in terms of tax incentives for new renewable resources, and we haven’t seen how that’s going to change the equation,” Collins said. “In the short run, there are phases that we’re likely to see changes, and part of that is a result of policy, part of that as a result of supply chain technologies. So I think over the next five to 10 years, we’re going to see a significant shift.”

“We’ve got to move though,” Cathey said. “I think that’s one problem that we’ve had as an energy industry: We spend a lot of time. I think we spent four years on a demand response policy. We can’t do that anymore.”

POWERGEN 2026 continues through Jan. 22 at the Henry B. Gonzalez Convention Center, with a week of executive dialogue, technical sessions and networking for the power generation community.

With the U.S. energy sector in the middle of unprecedented load growth driven by data centers and industrialization, it would likely be unwise to turn your nose up at any specific generation source. But with everything changing so fast, and with remaining uncertainty about how much actual load growth we will experience, how can utilities know they’re adequately preparing without taking on unnecessary costs?

Those were the sentiments at POWERGEN 2026’s Opening Keynote, which brought together leaders from utilities, engineering firms, technology providers and the research community to examine how the industry is responding to rapid change.

‘We’ve got to have it all’

The opening keynote began with a session between Rudy Garza, President & CEO – CPS Energy; and Victor Suchodolski, Chairman, President & Chief Executive Officer – Sargent & Lundy; moderated by Ahsan Yousufzai, Global Director Energy – NVIDIA. The trio discussed the unforeseen changes in the power industry that AI has stirred up; how to plan for uncertain projected load growth; how nuclear’s role will evolve in Texas; and pesky bottlenecks that can bring entire projects to a halt.

“The industry’s changing at a pace quicker than I think any any of us ever thought,” Garza said. “The pressure is exponentially changing on us in a way that is requiring us to really stretch every part of our business.”

There’s still plenty of uncertainty in the air surrounding the projected load growth the U.S. could experience. It’s currently unclear if all of the gigawatts of projected load growth will actually come to fruition, but utilities need to be prepared anyway, Garza argued. Otherwise, they may be blindsided by the lack of generation, transmission, and all of the components of these systems that can have large lead times.

“You’re going to have to teach an old dog new tricks, and the old dog is the utility industry,” Garza said. “We’re not used to changing the way we think about things. And if we don’t, the industry is going to go around us, and that’s not good for anybody.”

With so much on the line, the power industry doesn’t have much room to be picky. Nearly every existing form of generation will have a seat at the table – something Texas is already plenty familiar with: the state currently leads the nation in renewable and battery deployments.

“We’ve got to have it all,” Garza said. “And, you know, we don’t spend a lot of time here in San Antonio arguing over which resource is the right resource or the wrong resource.”

At Sargent & Lundy, Suchodolski is seeing firsthand how the markets are responding positively to more certainty – even gas and nuclear are both showing growth, when they have historically always run opposite to each other.

“With respect to bulk gas generation, regulatory and permitting are less of a driver now, and that’s primarily due to the longer lead time, so you can run in parallel with the permits,” Suchodolski said. “You also have partnerships with OEMs, and you can see there that there’s synergies with knowing what your air missions are going to look like, or what kind of designs you’re going to get. And you can design these projects a little bit more on the front end, you can buy equipment more on the front end.”

However, as some bottlenecks ease up, others become more prominent. Now, delays are being caused by power delivery center components, circuit breakers, and even emergency diesel generators, Suchodolski noted.

“This is really a power generation conference, but the grid is out there too,” Suchodolski said. “We are seeing transmission still having some issues with respect to the permitting process and getting things done as quickly as we want them. So it still takes time. There have been some strides here, but the transmission line projects are not going as quickly as we would hope that hope they would.”

Future nuclear deployments are going to look much different than what the U.S. saw in the 20th century. Garza argued that without state or federal incentives, new, large baseload nuclear generators like we built in the 70s will remain a relic of the past: there’s currently just too much risk and cost involved for that to be feasible. But next-gen nuclear reactors like SMRs, which have a much smaller footprint, could have a very promising future, especially for large loads like data centers, which are now required in Texas to have the ability to go off-grid on their own power sources if the grid gets squeezed.

At least one thing is clear though: the U.S. is going to have to build a lot of new generation, especially as older generating units are retiring. Many of those old units are on their last limbs already, being kept running now only out of necessity.

“ERCOT put one of our older units that we were trying to retire into what they call a reliability must run status, and it’s cost us millions of dollars trying to give that unit another three years of life,” Garza said. “So is that the most efficient, you know, use of our of our limited capital, or do we just need to build new stuff?”

How can AI help speed up new nuclear deployments?

In the next panel of Tuesday morning’s opening keynote, Raiford Smith, Global Market Lead for Power and Energy – Google Cloud; and Lou Martinez Sancho, CTO – Westinghouse Electric Company discussed a collaboration between Google and Westinghouse to create a custom AI-powered platform meant to assist and speed up reactor construction.

Westinghouse plans to have 10 of its AP1000 reactors under construction by 2030, and this platform is a key part of getting that plan into motion. The nuclear industry is notoriously heavily regulated, which can cause projects to take longer than some would like.

“We started this journey and needed to downsize basically the time to deliver new nuclear into market,” Sancho said. “But we needed also to utilize it to improve the way we are operating the current plants, [so] we can understand better how to do super power upgrades to deliver more.”

AI’s ability to learn and retain information has made it attractive to users like Westinghouse. The days of simple “if, then” statements may soon be behind us, Smith argued.

“Better yet, this is a solution that we collectively worked on for a work management problem for nuclear, but work management problems can be addressed using the same capabilities, as long as you have the foundational data and the frameworks – they can also be addressed the same way,” Smith said. “So the technology isn’t a one-off. The technology is not so bespoke that it cannot be applicable elsewhere.”

Details matter

In the final portion of Tuesday’s opening keynote, Mike Caravaggio, Vice President, Energy Supply, Fleet Reliability – EPRI painted a picture of the current moment the industry has unexpectedly found itself in, and what the coming years could look like.

Caravaggio echoed previous panelist arguments that each and every form of generation will have its own role to play, even though all gigawatts aren’t created equal.

“A gigawatt is not a gigawatt, is not a gigawatt,” Caravaggio said. “Our different technologies will fill this load growth void in different ways. A solar plant can’t do what a nuclear plant can can do. A gas turbine can move a lot faster than a combined cycle. We need to balance these technologies to meet the needs of these data centers.”

But that variance applies to the load side as well. Depending on their purpose, data centers can have vastly different load profiles from each other.

“These details are really going to matter,” Caravaggio said.

POWERGEN 2026 continues through Jan. 22 at the Henry B. Gonzalez Convention Center, building on Monday’s technical foundation with a week of executive dialogue, technical sessions and networking for the power generation community.

POWERGEN 2026 opened Monday in San Antonio with a strong focus on the practical, technical work that underpins power generation, as attendees took part in in-depth workshops and an offsite technology tour ahead of the conference’s main programming.

The day began with the 43rd Electric Utility & Cogeneration Chemistry Workshop (EUC²W), a long-running forum that has drawn thousands of chemists, engineers and plant professionals since its launch in 1981. Now co-located with POWERGEN, EUC²W again centered on the day-to-day chemistry and environmental challenges facing power plants and industrial facilities. Sessions addressed makeup water treatment, boiler and HRSG chemistry, cooling water reliability, wastewater treatment and emerging environmental issues, including PFAS and evolving regulations. For plant personnel, the workshop offered a rare opportunity to exchange field experience and best practices with peers, consultants and technology providers focused squarely on reliability, safety and compliance.

Monday also featured a technical tour of Southwest Research Institute’s Power Cycle & Energy Systems Laboratory, giving attendees a close look at advanced power cycle and storage research underway in San Antonio. Participants toured the STEP Demo facility, a DOE-funded 10-MW supercritical carbon dioxide pilot plant designed to demonstrate higher-efficiency power cycles with smaller equipment footprints than conventional steam systems. The tour also included SwRI’s pumped thermal energy storage demonstration and turbomachinery laboratories, where compressors, turbines and heat exchangers are tested for next-generation applications. For many attendees, the tour provided tangible insight into how emerging technologies could shape future generation options across nuclear, gas, geothermal and industrial heat recovery.

With workshops and tours complete, attention now turns to the main conference program as POWERGEN officially opens Tuesday morning.

The Opening Keynote, beginning at 8:30 a.m. on Tuesday, brings together leaders from utilities, engineering firms, technology providers and the research community to examine how the industry is responding to rapid change. An executive panel featuring Rudy Garza of CPS Energy and Victor Suchodolski of Sargent & Lundy will discuss how utilities and EPCs are managing accelerating load growth, evolving regulations and tighter project timelines.

The keynote also includes a joint presentation from Westinghouse Electric Company and Google Cloud on the use of artificial intelligence and digital tools to support nuclear construction and long-term asset performance, followed by a system-level perspective from Mike Caravaggio of Electric Power Research Institute.

Beyond Tuesday morning, three additional keynote panels will anchor the week’s discussion. Sessions on grid market reform, AI-driven load growth and the bottlenecks slowing new generation projects will feature voices from ERCOT, Southwest Power Pool, utilities, developers, EPCs and major power customers. Together, they aim to move beyond theory and focus on how the industry is adapting in real time to deliver reliable megawatts.

POWERGEN 2026 continues through Jan. 22 at the Henry B. Gonzalez Convention Center, building on Monday’s technical foundation with a week of executive dialogue, technical sessions and networking for the power generation community.

Talen Energy Corporation announced it has signed definitive agreements to add approximately 2.6 GW of natural gas generation capacity to Talen’s portfolio through the acquisition of the Waterford Energy Center and Darby Generating Station in Ohio, and the Lawrenceburg Power Plant in Indiana from Energy Capital Partners (ECP).

Talen said the acquisition will “substantially expand” its presence in the western PJM market and add additional efficient baseload generation assets to its fleet.

The acquisition price is $3.45 billion and consists of approximately $2.55 billion in cash and approximately $900 million in Talen stock. The transaction is expected to provide immediate and significant adjusted free cash flow per share accretion in excess of 15% annually through 2030E. Additionally, these assets are expected to achieve an approximately 85% unlevered free cash flow conversion rate before recognition of any tax benefits.

“When this transaction is complete, Talen will have approximately doubled its expected annual generation output inside of two years, meaningfully diversified our fleet, and materially increased our free cash flow per share,” said Terry Nutt, Talen President. “We are also excited to welcome ECP as a significant Talen shareholder.”

The 1,218-MW Lawrenceburg and 869-MW Waterford facilities have an average heat rate of approximately 7,000 Btu/kWh and capacity factors greater than 80%. The 480-megawatt Darby facility also operates as a peaking unit. Talen argues that the addition of the facilities to its portfolio enhances the company’s ability to offer low-carbon capacity to hyperscale data centers and large commercial off-takers.

Talen expects to issue new debt to fund the cash portion of the purchase price.

The transaction is expected to close early in the second half of 2026 and is subject to customary closing conditions and regulatory approvals from the Federal Energy Regulatory Commission, Indiana Utility Regulatory Commission and other regulatory agencies.

By William Kaewert, Strategic Advisor and Board Member, Stored Energy Systems

Part 1 showed why outages and price spikes will pull on-site assets like generators and battery storage into weekly service. This continuation focuses on what equipment must do to succeed. Availability comes first with economics a close second. 

Fast forward to 2030: we’ll have demand outrunning firm capacity, and the grid shows it: 

Aging thermal plants are cycled hard, so forced outages creep up, while the gear that could relieve some of the pressure – large transformers, combined cycle gas turbine powerplants and new transmission – takes years to arrive. Grid batteries help for hours, but not for days of wind and solar drought. The result: more curtailments and more requests to dispatch on-site storage and power generation systems. Prices mirror the strain: negative at night, punishingly high in the afternoon and evening. On-site power will soon be on weekly or even daily duty rather than on standby. 

Now, if you want your system to become 2030-ready, it must be able to do two jobs: to keep critical loads online during blackouts, and generate cash by decoupling peak power usage away from periods of peak power pricing.   

Availability comes first with economics a close second.

This will result in a dramatic change in the requirements for on-site power. You will need storage that tolerates frequent cycling, bidirectional conversion that charges batteries quickly and can export back to the grid, and controls that let the plant act as a grid-synchronized resource without adding safety risk. 

What on-site power will look like in 2030 

While it’s too early to predict specific technologies or suppliers, we can reasonably identify some general requirements: 

The general concept of power flow in 2030 is that electricity will in many places flow into and out of customer facilities much like oceanic tides roll in and out. Although the reversal of flows will be much less predictable than tidal movement, changing flows of power are the consequence of increasing renewables penetration. Daily cycles of the sun, power demand, and the seasons mean that power generation will be increasingly difficult to match with demand. The only solution will be on site power generation and energy storage. These assets will be necessary to stabilize the inevitable mismatches between demand and renewable generation.

Storage 

Daily or weekly cycling materially changes the requirements for energy storage. Technologies to support an expected 200 cycles per year and 15-to-20-year calendar life places very different demands on batteries than legacy “standby” applications, such as UPS or switchgear backup duty.  

Batteries for revenue service must be sized much larger than today’s standby batteries. On top of the “insurance” job of powering critical systems during blackouts the batteries of 2030 will stack another job. This second job is the time-shifting of facility loads such that peak demand occurs during periods of low electricity prices, rather than during when energy is consumed. Many sites would need to upsize today’s stationary battery systems by ten times or more to satisfy the time-shifting requirement. 

The much larger size of future high-capacity batteries, combined with fire safety concerns, will drive these stacked application batteries out of basements and outside the building. 

The outdoor location and the electrical and fire safety, seismic and other AHJ requirements mean that tomorrow’s critical power battery systems will look a lot like best practice for outdoor BESS systems. 

Power conversion 

The single-purpose, uni-directional charger of yesteryear will give way to power conversion that can charge, support loads, and export back to the grid. It will be capable of reversing direction (i.e. charger to inverter, and vice-versa) quickly, and follow both site commands and external dispatch signals from a virtual power plant operator or other grid source.  

Fast recharge speed will become an economic requirement. The former 24-hour recharge requirement typical of standby battery sites could shrink to four hours to exploit unpredictable opportunities of negative electric power prices. This sixfold faster charging requirement combined with batteries ten times larger than today’s standby batteries means the capacity of tomorrow’s power conversion could be sixty times greater than the power of today’s stationary chargers. Today’s 10 kW charger becomes tomorrow’s 600 kW bi-directional power converter.

Because the concept of negative prices for electricity is a mind-bender, an analogy to explain the much larger size of power converters is in order. Imagine for a moment that food is super expensive most of the day. For a few hours most days, however, you’re paid to eat. You take breakfast and lunch in short succession – because this deal only lasts a few hours. Plus, the more you can eat during the short “pay to eat” window, the more money you earn.  

The motivation is to eat a lot in a short period. That’s exactly what the big power converter does: delivers a lot of power into a big battery in a short time.  

To handle the much higher power, operating voltage must increase to maintain reasonably sized conductors. A higher storage bus, at least 800 volts DC, enables reduced wire cross section and circuit breaker ratings. Legacy 250, 125, and 48 V buses must then be fed through DC-DC conversion. Isolation, protection, and low-voltage disconnect behavior must be clearly defined. 

Meanwhile physical design should be for availability and service. Modular power stages allow N+1 operation and replacement under lockout without dropping the plant. Technicians will need adequate clearances, lifting paths, and access they need to do the job safely. The shift to higher voltages and power demands new operator training in high energy and arc flash hazards.

A quick ​​sizing example to align expectations 

Suppose a site currently has 100 kWh of standby storage maintained at float with a 10 kW charger. To support both a one-hour ride-through reserve and daily four-hour time shifting, battery capacity is increased to 500 kWh, with 30% capacity (150 kWH) left in reserve in case of blackout. This leaves 350 kWH for time shifting. To recharge 350 kWh in four hours, the converter needs roughly 90 kW at the DC bus after efficiency. Allowing for conversion losses and margin, a 110 to 120 kW converter is a practical minimum. If the site wants to exploit two-hour negative-price windows, double that power. This is why many facilities end up with both larger batteries and much higher conversion power than legacy systems. 

This is more than idle speculation. Forces are already in motion that, by the end of this decade, will result in electricity shortages. Blackouts will become more frequent, longer, and more widespread than ever. The price of electricity will reach staggering heights, while at other times, businesses will be paid to consume. As grid disruptions and volatile prices affect bottom lines, many C&I enterprises will add or repurpose stationary batteries. 

If “standby” power is going to work every week, it will look quite different from the equipment we use today. Storage must cycle, conversion must move power both ways, and operations must treat on-site power not just as an insurance policy, but also as a cash-generating asset. 

The good news 

While predictions of growing grid instability and looming blackouts are alarming, the very industries demanding the most from our grids are actually in the best position to support the grid. Commercial and industrial facilities have at their disposal an incredibly powerful resource: standby power. According to an address at the EGSA 2025 Spring Conference, the combined capacity of C&I standby generators installed in the United States is between 130 and 200 gigawatts, with about 45 gigawatts of that capacity located at hyperscale data centers. 

Properly harnessed with the surrounding infrastructure outlined above, this installed base could replace retiring dispatchable generation faster than any other option, with minimal upgrades to distribution. 

For us in the on-site power industry, the old ways of thinking are facing unprecedented challenges. As an industry, we will need to seize the opportunities this presents – or make way for those who do. 

This concludes Part 2. If you need the case behind these recommendations, see Part 1, which explains why load growth, plant retirements, and aging assets are pushing critical power into daily service in the first place. 

For deeper explanations, examples, and references behind these requirements, see the paper Bill delivered at Battcon 2025.  

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William Kaewert is Strategic Advisor and Board Member of Colorado-based Stored Energy Systems LLC (SENS), an industry leading supplier of non-stop DC power systems that are an essential part of the nation’s critical infrastructure. SENS products provide non-stop power that enable 24/7 operation of the power grid, energy production, data centers, health care facilities, the financial system and other services that sustain modern life. Mr. Kaewert received his BA in history from Dartmouth College and MBA from Boston University. 

He has served on the board of directors of several economic development organizations and the Electrical Generation Systems Association (EGSA). He is an active member of InfraGard, a public/private partnership of private industry and the FBI to protect United States critical infrastructures from deliberate attack.

Bill co-founded Resilient Utilities Now, a non-profit working to improve US resilience against long-duration electric system failures. Bill has in the past served in other roles related to power system resilience, including director and Chairman of the Board for the Foundation for Resilient Societies a NH-based non-profit.

Duke Energy has brought on line a 50-MW, four-hour battery energy storage system (BESS) at its former Allen coal plant on Lake Wylie, serving customers in North Carolina and South Carolina, and has also unveiled plans for additional battery storage and new jobs at the Gaston County site.

The first BESS, at a cost of approximately $100 million, began serving customers in November. Final testing is being completed this month. Construction of a second BESS – Duke Energy’s largest, a 167-MW, four-hour system – will begin in May on 10 acres where the coal plant’s now-demolished emissions control system once stood.

Both lithium-ion battery systems qualify for federal investment tax credits, which will offset 40% of the cost for Duke Energy customers. That figure includes an extra 10% for reinvesting into an energy community. The coal plant retired in December 2024.

We’re building new resources to keep the Carolinas’ economy thriving, while reinvesting in a former coal plant community that helped power this region for decades,” said Kendal Bowman, Duke Energy’s North Carolina president. “Repurposing existing energy infrastructure and taking advantage of federal funding significantly offset costs for our customers while continuing to support rapid growth across the region.”

Duke Energy plans to make similar battery storage investments in multiple counties across the Carolinas. The company’s 2025 Carolinas Resource Plan, now under review by state regulators, projects the addition of 6,550 MW of batteries by 2035 in North Carolina and South Carolina. Across the Carolinas, Duke Energy’s customer energy needs over the next 15 years are expected to grow at eight times the growth rate of the prior 15 years.

Duke Energy’s plans call for battery storage at both of the county’s retired coal plant sites along the Catawba River: Allen (1957-2024 in Belmont) and Riverbend (1929-2013 in Mount Holly). Construction of the latter, a 115-MW, four-hour BESS, is expected to begin in late 2026, coming online in late 2027.

“We are proud of how this site and its people continue to support our customers,” said Bryan Walsh, Duke Energy’s vice president of Regulated Renewables and Lake Services. “Multiple former Allen plant employees now work on our Regulated Renewables team, which maintains and operates the new batteries at Allen and elsewhere in the Carolinas. Duke Energy’s test site for new battery technologies, its Emerging Technology and Innovation Center, is also in Mount Holly.”

As part of the company’s rate review now before the North Carolina Utilities Commission, Duke Energy has proposed a third BESS at Allen to come on line by the end of 2028, as well as a regional operations, training and warehouse facility for batteries and renewables that could house 20-50 employees. Plans for both are still evolving and subject to regulator approval, Duke Energy noted.

Originally published in Factor This.

POWERGEN 2026 will devote three of its keynote sessions to a question many power generation professionals are grappling with daily: how to deliver reliable megawatts in the face of accelerating demand, tighter markets and persistent project constraints. Together, the panels offer a practical look at how grid operators, utilities, developers and EPCs are responding to conditions shaping the industry in early 2026.

The first of the three, The New (Grid) Balancing Act, takes place Jan. 20 from 1 to 2 p.m. and centers on the growing strain facing organized power markets. Load growth tied to data centers, manufacturing expansion and electrification is colliding with limited new capacity and heightened seasonal reliability risks. Executives from ERCOT and Southwest Power Pool will discuss how their regions are responding through market reforms, changes to capacity accreditation and shifts in how risk is allocated across market participants. Moderated by Hari Gopalakrishnan of Mitsubishi Power Americas, the panel will examine what these changes mean for utilities and independent power producers navigating competitive markets under pressure.

On Jan. 21 at 8:15 a.m., Powering the AI Era: A New Blueprint for Growth turns the focus to the demand side of the equation. As artificial intelligence and data center development drive unprecedented electricity growth, power providers are being forced to rethink resource planning, generation strategy and customer relationships. The keynote brings together leaders from utilities, developers and large power customers, including CyrusOne, TECfusions, NextEra Energy and CPS Energy, to discuss how new partnership models are emerging to support reliability and growth. Moderated by Richard Esposito of Southern Company, the session will explore how these shifts are influencing the future generation mix and the technologies utilities are prioritizing to keep pace.

Later that day, from 1 to 2 p.m., Bottlenecks & Breakthroughs: Getting Power Projects Built addresses the obstacles slowing the delivery of new generation and upgrades. Equipment shortages, multi-year interconnection queues and permitting uncertainty continue to delay projects, even as demand forecasts rise. Moderated by Terri Poussard of HDR Engineering, the panel features leaders from utilities, EPCs, legal and supply chain organizations, including the Lower Colorado River Authority, NiSource and Zachry Group. Speakers will share how they are rethinking procurement, standardizing equipment and adjusting construction strategies to move projects forward more quickly, and what those changes mean for schedules, workforce planning and capital deployment.

These three keynotes offer a grounded look at how the industry is adapting in real time. Rather than focusing on theory, the discussions highlight how market rules, customer demand and project execution are evolving, and what that means for delivering reliable power in today’s environment.

POWERGEN 2026 begins next week at the Henry B. Gonzalez Convention Center in San Antonio, Texas. Be sure to register to join your customers and peers!