To address time to power, one of the biggest constraints currently slowing data center deployment, EPRI is launching Flex MOSAIC, a uniform flexibility classification framework for large electric loads, developed through its DCFlex initiative in collaboration with more than 65 utilities, system operators, regulators, hyperscalers and technology providers.

The voluntary framework is meant to establish a “shared, credible way” to define flexibility from large loads (particularly data centers) based on the magnitude, timing, duration and frequency of their response. By enabling a common understanding of what flexibility a load can deliver, EPRI argues the framework could help shorten interconnection timelines, improve grid planning confidence and accelerate access to power without compromising reliability or affordability.

“As demand from AI and data centers grows at unprecedented speed, flexibility is becoming the third leg of the speed-to-power stool, alongside generation and transmission,” said EPRI President and CEO Arshad Mansoor. “This framework allows everyone — utilities, regulators, and large‑load developers — to have common language about flexibility and to trust what that language means. That shared understanding is essential to moving faster while maintaining reliability.”

Data center construction and the advent of artificial intelligence (AI) are driving unprecedented electric load growth across the United States. Massive hyperscalers with deep pockets and bold aspirations need power, and they need it fast.

From May 12-14, 2026, DTECH Data Centers & AI will assemble utilities, engineers, and technical decision-makers from across this emerging ecosphere in Scottsdale, Arizona, to discuss everything from capacity constraints to streamlining studies, from modernizing infrastructure to integrating onsite generation into both utility and customer-side systems.

Register for DTECH Data Centers & AI now before early-bird pricing ends on April 1, 2026.

The framework defines flexibility through practical performance characteristics, including how quickly a load can respond, how long adjustments can last and how much power can be reduced or shifted. These characteristics are organized into a set of uniform flexibility classes that utilities, system operators and data centers can apply consistently across regions.

The framework is meant to provide a technical foundation that jurisdictions and market participants can adapt to their local needs. “As large, flexible loads play a growing role in the power system, having clear, technically grounded definitions of flexibility is critical for reliability,” said North American Electric Reliability Corporation President Jim Robb. “A common framework like this can help system operators and planners speak the same language, essential for maintaining a reliable grid.”

“As demand from data centers accelerates, state regulators are focused on ensuring customers are not burdened by the costs of serving new, large loads, as well as maintaining grid reliability,” said NARUC President Ann Rendahl. “NARUC looks forward to engaging with EPRI and others on how a voluntary, standardized framework like Flex MOSAIC can create a common language and shared understanding of flexibility, and provide benefits to state regulators when evaluating data center integration, without shifting costs to customers or compromising grid reliability.”

Initial framework participants include Alliant Energy, Arizona Public Service, California ISO, El Centro Nacional de Control de Energía (CENACE), Compass Datacenters, Constellation Energy, DTE Energy, Entergy, Exelon, Georgia Transmission Corporation, Google, Honeywell, Independent Electricity System Operator (IESO), ING, Jenbacher, Korea Power Exchange (KPX), KPMG, LG Pado, Lincoln Electric System, Lower Colorado River Authority, Meta, Midcontinent Independent System Operator (MISO), Nebraska Public Power District, NERC, NVIDIA, Portland General Electric, PSEG, Rayburn Electric, Salt River Project, Siemens, Southern Company, Southwest Power Pool and United Power.

Constellation Energy Corporation and LS Power Equity Advisors announced an agreement under which Constellation will sell a portfolio of generation assets in PJM to LS Power, a step in satisfying regulatory commitments related to Constellation’s acquisition of Calpine.

The proposed sale represents the largest portion of the divestitures required by the U.S. Department of Justice (DOJ) as part of its antitrust review of the Calpine transaction, including all assets required to be divested by the Federal Energy Regulatory Commission (FERC). Under the agreement, LS Power will acquire approximately 4.4 GW of predominantly natural gas–fired generation capacity located in Delaware and Pennsylvania, including the Bethlehem, York 1, York 2, Hay Road and Edge Moor Facilities. The transaction is valued at $5 billion before closing adjustments, representing an acquisition price of approximately $1,142/kW.

“This transaction is an important step in satisfying the DOJ’s requirements and advancing our path forward,” said Joe Dominguez, president and CEO of Constellation. “These are well-run facilities that will continue powering consumers and businesses for decades to come. We’re pleased to be moving ahead and expect to complete the remaining DOJ requirements later this year.”

In December 2025, Constellation announced a resolution with the DOJ that outlines a series of divestitures designed to address “competitive considerations” in PJM and other markets. The DOJ resolution followed FERC’s July 2025 approval, which required the divestiture of certain assets in PJM. The latest announcement represents the largest and most substantive element of the DOJ and FERC resolutions. Closing is conditioned upon receipt of regulatory approvals, including review by the DOJ and FERC, and other customary closing conditions.

Last January, Constellation announced plans to acquire Calpine in a cash and stock transaction valued at an equity purchase price of approximately $16.4 billion. The deal became one of the largest in the history of power generation at a time when demand for electricity has exploded. Constellation already owns and operates the largest fleet of nuclear plants in the United States. Constellation is also the largest producer of clean energy in the U.S. The company generates more than 32,400 MW of capacity, including through nuclear, gas, wind, solar and hydropower assets.

Constellation sees the deal as a chance to expand its power generation portfolio in a time a record electricity demand growth. After years of flat demand, electricity load growth forecasts have exploded, largely driven by data centers, industry and electrification.

“PJM is at the epicenter of the surge in electricity demand, and these are exactly the kind of assets the grid needs – efficient, dispatchable gas generation that can deliver reliable power around the clock,” said Paul Segal, CEO of LS Power. “LS Power has been developing, building and operating gas-fired generation for over 35 years. We expect our extensive operational experience will enable seamless integration of the assets and their employees and look forward to engaging with plant staff and the local communities around the facilities.”

The Jack Fusco Energy Center, a 606-MW natural gas fired combined cycle facility located outside Houston, Texas, is the remaining facility in the DOJ resolution agreement that has not yet been divested. The minority ownership in the Gregory Power Plant, a 385-MW natural gas fired combined cycle near Corpus Christi, Texas, was divested earlier this year.

Constellation completed its acquisition of Calpine on Jan. 7, 2026, creating the world’s largest private-sector power producer and significantly expanding its generation footprint. The asset sale announced is expected to close later this year, subject to regulatory approvals.

IHI and GE Vernova announced they have successfully demonstrated combustion of 100% ammonia using full-scale components at pressures, temperatures and flows matching full-load conditions for GE Vernova’s F-Class gas turbines.

The companies also said emission levels achieved during the test align with their development roadmap towards the goal of a 100% ammonia-fired gas turbine, with the aim of achieving commercial deployment by 2030.

“An essential piece of the ammonia value chain is now coming into place,” said Noriaki Ozawa, IHI Managing Executive Officer and President of Resource, Energy & Environment Business Area. “Since the signing of the joint development agreement in 2024, the collaboration between our two companies has gained strong momentum, with the efforts of both teams now bearing fruit. The successful achievement of 100% ammonia combustion in a full-scale F-class gas turbine marks a major milestone and helps reinforce the decarbonization roadmap envisioned by our customers in the power sector.”

The demonstration was conducted at IHI’s purpose-built test facility, engineered to replicate GE Vernova’s F-class gas turbine operating conditions. The test facility, located at IHI’s Aioi Works facility in Hyogo, Japan and completed last summer, was engineered to test advanced combustion systems at GE Vernova’s F-class gas turbine operating conditions, including pressure, temperature, and both air and fuel flow rates.

The collaboration between the two companies includes synergies across IHI ammonia combustion expertise and GE Vernova global technical teams, and shared best practices developed at GE Vernova’s advanced combustion test facility in Greenville, South Carolina.

Ammonia, a derivative from hydrogen, does not result in any net CO₂ emissions when combusted. Ammonia is used today in industrial applications, such as fertilizer. It is also used as a carrier of hydrogen.

“The successful demonstration of running an F‑class gas turbine on 100% ammonia fuel marks a pivotal step in our journey toward a lower‑carbon energy future,” said Jeremee Wetherby, GE Vernova’s Carbon Solutions leader. “This achievement reinforces our development roadmap and underscores the strength of our collaboration with IHI. We see significant potential for ammonia as a carbon‑free combustion fuel and are energized to continue working together to help unlock its role in advancing global decarbonization.”

RWE announced the addition of flexible, gas-fired power generation to its U.S. portfolio, with plans to add 9 GW of new net capacity by 2031.

Germany’s largest power producer said that flexible gas would complement its existing 13 GW U.S. renewables and battery storage portfolio, strengthening its ability to meet “soaring” power demand.

The announcement comes as part of RWE’s global corporate strategy update, which affirmed the company’s global investment plans of €35 billion ($40.38 billion USD) net from 2026 through 2031 – of which €17 billion ($19.62 billion USD) net is allocated to enable growth in the United States.

RWE executives said the company’s U.S. gas strategy is centered on flexible generation in high-growth markets where power demand is rising rapidly, particularly from data centers. The company plans to leverage already-secured grid interconnections to develop a pipeline of 15 natural gas peaking projects across target markets in MISO, WECC, PJM and ERCOT.

In remarks tied to the company’s fiscal 2025 results, CEO Markus Krebber said said RWE does not want to build gas generation into the merchant U.S. market, but instead plans to pair gas with renewables and batteries in bundled offerings for customers seeking longer-term contracted supply.

The company argues that renewables and gas capacity deployed together can “optimize land use, share infrastructure, and improve energy reliability and efficiency allowing for speed to power and specific customer needs.”

“We want to combine it as a bundle with renewable, battery and the profile and then sell it to the customer,” said Krebber, adding that the company is targeting contract structures similar to renewables deals, with much of the value contracted over 10 to 15 years.

In Q&A with analysts and investors, Krebber said RWE has not yet secured equipment for the projects, but does not view supply chain constraints as a major concern because the company’s U.S. plans are focused on peakers and engines rather than combined-cycle gas turbines, where equipment availability is tighter.

That said, the company plans to move quickly.

“Our goal is to take the first FID this year and have the first megawatts operational by the end of the decade,” said Krebber. He added that the company intends to leverage its existing U.S. renewables footprint, market presence and interconnection position as it builds out the gas strategy.

RWE has existing gas units in the U.K., Germany, the Netherlands and Turkey.

Arizona Public Service (APS) has notified the U.S. Nuclear Regulatory Commission (NRC) of its intent to renew the operating licenses for all three units at Palo Verde Generating Station, which could extend operations from the mid-2040s through the mid-2060s. 

Located west of Phoenix, Palo Verde has the capacity to produce 4,200 MW, and is the largest power generator in the western United States.

In the 1980s, the NRC licensed Palo Verde’s nuclear units to operate for 40 years. In 2011, the NRC approved APS’s renewal application to extend the operating licenses 20 years, allowing the three units to operate through the mid-2040s. Last week, APS filed a Notice of Intent to submit a Subsequent License Renewal Application to the NRC in late-2027. The application will seek to renew Palo Verde’s operating license for an additional 20 years, allowing Unit 1 to operate through 2065, Unit 2 through 2066 and Unit 3 through 2067.

A license renewal for APS would extend Palo Verde’s life to 80 years. APS is following the NRC’s established license renewal process, which has resulted in renewing licenses to 80 years for 10 stations across the country. The NRC is currently reviewing applications for three stations.  

As Arizona continues to grow and energy needs increase, in addition to seeking license extensions for Palo Verde, APS is assessing new nuclear technologies and leading a collaborative effort with Salt River Project (SRP) and Tucson Electric Power (TEP) to explore and advance additional nuclear generation in the state. In 2025, the utilities teamed up to apply for a grant with the U.S. Department of Energy for funding to support the evaluation of possible sites. While awaiting a decision, the three utilities are considering multiple types of nuclear energy solutions, including small modular reactors and large reactor projects. 

Palo Verde is unique as the only nuclear power plant in the world that does not have access to a surface body of water. It uses 100% recycled wastewater from surrounding cities for cooling. It is operated by APS and owned by seven utilities: APS, SRP, El Paso Electric, Southern California Edison (SCE), Public Service Company of New Mexico (PNM), Southern California Public Power Authority (SCPPA) and Los Angeles Department of Water and Power (LADWP).

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.

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.

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.