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.

The Call for Content for POWERGEN 2027 is now open. Submissions will be accepted through May 18, 2025. Late submissions will not be considered.

Submit Now | POWERGEN Topics & Call for Content FAQ

POWERGEN is looking for engineers, plant managers, project developers, executives and technical experts who have done the work (and have something real to say about it). Our conference educational program is built on case studies, field experience, hard-won lessons and the latest market intelligence, not promotional presentations. If your team navigated a difficult outage, executed a complex project, solved a persistent reliability problem or deployed a new technology in a demanding operating environment, this is your platform.

Utilities, IPPs, EPCs and engineering firms, OEMs, O&M service providers, self-generators and large energy users are all encouraged to submit. Owner-operator participation is strongly valued, and the POWERGEN advisory committee gives significant weight to submissions that feature this perspective.

Why This Moment Matters

The power sector is under more pressure than it has been in a generation. Load growth, driven by data centers, industrial expansion and electrification, is outpacing the pace at which new generation can be permitted, financed and built. Retirements are accelerating. Reliability margins are tightening. Supply chains that were already strained are now being tested further by compressed project timelines and competing demand for equipment, labor and engineering capacity.

At the same time, new technologies are moving from concept toward early deployment. Advanced nuclear, long-duration storage, carbon capture and AI-driven plant analytics are no longer distant possibilities — they are active decisions for owner-operators and developers right now. The industry needs honest, practitioner-led analysis of what is working, what is not and what others should know before they commit capital or change course.

POWERGEN 2027 is being designed to meet that moment. The program will be shaped by the people closest to the work.

What POWERGEN Is Looking For

Submissions should be practical, non-commercial and decision-useful. The advisory committee is looking for content that helps professionals make better decisions about how assets are built, operated, maintained and improved. Strong proposals are focused on execution, performance, reliability, cost, schedule, compliance, digitalization or other specific challenges shaping real projects and real plants.

The strongest submissions share a common structure: here is the problem, here is what we did, here is what we learned, and here is what you can apply. Proposals that deliver that arc — with specificity, candor and technical grounding — are the ones that get selected and the ones that audiences remember.

Vendor-only submissions are considered but must clear a high bar for technical rigor and industry value. The program is not a venue for product promotion or company marketing.

Topics POWERGEN Is Prioritizing in 2027

See all topics with descriptions here

POWERGEN 2027 will cover a broad range of topics spanning market conditions, project development and delivery, generation technologies, plant operations, and digital transformation. The following areas reflect the most pressing issues the industry is working through right now:

Market Drivers and Planning

Electricity demand growth is reshaping everything: development pipelines, dispatch strategies, resource adequacy decisions and investment priorities. POWERGEN is looking for submissions that examine how load growth, including the surge from data centers, is changing how utilities and power producers plan their portfolios.

Related topics include resource and capacity planning in constrained markets, interconnection strategy (now one of the most important gating factors in any development decision), onsite and behind-the-meter power for large energy users, and the practical effects of evolving federal and state policy on generation investment and operations.

Plant O&M, Reliability and Performance

For many attendees, the operations and maintenance content is the core of POWERGEN. This is where practitioners share the hardest-won lessons from running, fixing and improving generation assets in a market that demands more flexibility, more uptime and tighter cost control than ever before.

POWERGEN is looking for submissions on reliability programs, outage planning and execution, lifecycle and asset management decisions, rotating equipment performance, electrical and balance-of-plant systems, efficiency and heat rate improvement, emissions compliance and control system performance. Upgrade strategies that increase output or improve reliability from existing sites are also a priority, particularly as new capacity takes longer to bring online.

Project Development and Delivery

POWERGEN 2027 introduces a dedicated Project Development and Delivery topic area to feature the experiences of EPCs, engineering firms and developers navigating a projected power generation buildout unlike anything the sector has seen in decades. This is a new and deliberate addition to the program, reflecting how central execution risk has become to every major capacity decision.

POWERGEN is actively seeking submissions from EPCs and engineering firms on how projects move from concept to commercial operation in today’s environment. This includes siting, permitting, contracting, procurement, engineering sequencing, risk management and schedule discipline.

Related areas include EPC and EPCM contracting strategy and risk allocation, supply chain and procurement challenges across new builds and major upgrades, and permitting, siting and community engagement realities for projects under development. The emphasis is on execution lessons: what practices, structures and decisions have helped projects advance or recover when conditions changed.

Generation Technologies

POWERGEN covers the full range of generation technologies in active deployment and active consideration across the industry. Submissions are welcome across all of the following areas:

• Gas turbine and combined cycle — new build execution, major maintenance, performance tuning, uprates, fuel strategy, emissions compliance and cycling impacts
• Steam cycle and HRSG — inspection, chemistry, failure prevention, bypass systems and maintenance strategy as plants operate more dynamically
• Boilers — combustion performance, tube failures, materials issues, life extension and emissions-related upgrades
• Nuclear — uprates, license extensions, unretirements, outage performance and capital planning for both the existing fleet and new build considerations
• SMRs and advanced reactors — licensing, siting, supply chain readiness, first-of-a-kind development lessons and owner-operator interest
• Hydropower — equipment upgrades, dam safety, operational optimization, relicensing and modernization strategy
• Solar PV — project development, hybrid integration, interconnection, O&M and supply chain considerations
• Wind — turbine technology, O&M, repowers, reliability and integration with broader portfolios
• Geothermal — project development, drilling and subsurface risk, power cycle design and financing
• Energy storage and hybrid configurations — integration, controls, dispatch strategy and project economics
• Long-duration energy storage — technology evaluation, use cases, economics and integration challenges
• Carbon capture and sequestration — capture technologies, project development, permitting, economics and integration with thermal assets
• Hydrogen and alternative fuels — fuel blending, combustion impacts, infrastructure, storage and retrofit considerations
• Cogeneration and combined heat and power — technology choices, thermal integration, fuel strategy and operating economics
• Microgrids — design, controls, islanding capability, generation mix, storage integration and utility coordination

POWERGEN 2027 is scheduled for January 18-21, 2027, at the Salt Palace Convention Center in Salt Lake City, Utah.

Sponsored Content.

Data centers have become modern megaliths in a new world of infrastructure powering the next wave of innovation, and artificial intelligence (AI) is redefining how they’re designed and powered. As AI workloads intensify, they’re creating new demands for efficiency, resilient power delivery, and how we define energy strategies that will determine the future of digital infrastructure.

“Data centers have become the places where AI model training and deployment occur, and that role is central to recent growth in electricity demand,” cites The International Energy Agency (IEA).¹ Because so much of the load is IT equipment, the IEA also points out that “Servers account for around 60% of electricity demand in modern data centers, underscoring why power has become such a hot topic when it comes to global growth in technology.”

Those power needs are colliding with practical limits on grid expansion. Building new transmission or waiting for interconnection approvals can take years, so data-center owners are combining strategies to secure capacity quickly. Many remain grid‑connected while signing long‑term renewable energy contracts and adding battery back-up to smooth short‑term variability. As McKinsey & Company explains, “Operators are pairing grid connections with behind‑the‑meter solutions, hybrid systems and advanced controls to handle fast-growing demand and interconnection constraints.”³ Where speed-to-power is more urgent, some operators install behind‑the‑meter generation—often modular gas turbines or generator sets—because on‑site assets can deliver capacity faster than waiting for grid upgrades. Siemens Energy captures this point plainly: “One solution to this challenge facing the data center industry is on-site generation of electricity and cooling.”⁶

Batteries are now a standard part of that toolbox. They provide immediate response during disturbances and shave short peaks so mechanical generators aren’t taxed beyond what they are designed to do. As the article by Facilities Dive observed, “Flexible battery or generator solutions can help data centers power up faster, reduce grid impacts and keep their owners’ sustainability goals within reach.”⁸ In short, hybrid mixes of grid power, long‑term renewable purchases, batteries and on‑site generation are practical and increasingly common.

Power generation equipment is not immune from these changes. Power plants tasked with serving AI loads may be asked to cycle more often and operate across a wider load range than many traditional baseload or peaking plants—behavior that increases thermal and mechanical stress on turbines, generators, and the gear drives linking them. McKinsey & Company highlights the problem in their online article, “Power supply is becoming an issue in markets that have traditionally attracted clusters of data centers, which is driving interest in dedicated generation and hybrid systems.”⁴ That means gear designs need to cope with more starts/stops, ramping, and generally more variable torque profiles than in historical applications.

With these increased demands, availability and predictability have become even more critical when it comes to power generation. Data centers expect near‑continuous operation, and backup systems are fundamental to achieving that availability. The Lawrence Berkeley Lab report states plainly that “UPS batteries and backup generators are there to keep the data center powered during outages and that these systems are essential to ensure the extremely high levels of reliability that data centers must meet.”² For gear suppliers, that translates into customers demanding not only mechanical robustness but also rapid serviceability.

So, what should gear companies do? There are several practical moves that align product and service offerings with data-center power needs. First, emphasize durability in designs intended for high‑cycle, variable‑torque duty: stronger tooth profiles, improved bearings, advanced sealing and lubrication strategies, and conservative designs that can handle a wider thermal range to reduce risk of early failure. Second, make the product serviceable by offering rapid response offerings, like Philadelphia Gear’s Onsite Technical Services (OTS)™, and high-quality OEM parts to reduce downtime for repairs during critical outages. This includes the ability to serve mobile power solutions deployed from trailers in addition to traditional, fixed brick-and-mortar facilities. Third, add simple but reliable condition monitoring for both mechanical and lubrication systems including vibration, temperature, and acoustic instrumentation so customers can incorporate predictive‑maintenance programs. McKinsey and others point to procurement trends where buyers weigh total cost of ownership, scalability, and service readiness—factors gear companies can influence through design and aftermarket offerings.^3,4

There are also product-level opportunities beyond the gear drive itself for companies that can offer more than just off-the-shelf products and instead provide engineered system solutions. So, whether the end-user is uprating current systems, needs efficiency improvements, or does not have the expertise to build a broader power‑system solution, all of these represent a competitive opportunity for OEMs. GE Vernova and Siemens Energy both emphasize the value of integrated approaches that combine generation, controls, and lifecycle services for data-center power applications.^5,6

In short, AI data centers are increasing electricity demand and, importantly, changing how that power is delivered and how generation equipment should function in this new world. Gear companies that combine proven mechanical reliability with rapid service capability, and partnership-oriented equipment solutions will be best positioned to support power plants and the various on-site power solutions serving AI workloads.

“We’ve already started working with AI data centers looking for help in meeting their energy demands,” said Carl Rapp, President of Philadelphia Gear. “With over 130 years of experience supporting the energy industry, we’ve been side-by-side with our customers as their energy needs have grown and changed. And during that time, we’ve remained true to our roots as subject matter experts for critical power generation equipment. Our approach has always been to be a trusted advisor and build custom engineered products that solve specific challenges. So, whether it’s a new gear design or servicing the equipment over its lifecycle with aftermarket repair, parts, and service, we have built our business on running to and solving our customers’ most complex problems.”

Carl continued, “As a part of Timken Power Systems (TPS), Philadelphia Gear® is integrated within a network of manufacturing and service centers that provide electro-mechanical expertise for complex engineered systems that include gear drives, electric motors, generators, bearings, and control systems. For data center operators, expertise in a single discipline is no longer enough. That’s what TPS is all about, evolving alongside our customers’ needs to deliver broader, integrated capabilities that simplify operations and help their businesses run more efficiently.”

To learn more about Philadelphia Gear or TPS, visit our websites or scan the QR code to take a virtual tour.

Authors: Carl Rapp, president of Philadelphia Gear; and Rob Fisher, marketing & product manager for Philadelphia Gear.

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References

1. IEA — Energy and AI: Energy demand from AI: https://www.iea.org/reports/energy-and-ai/energy-demand-from-ai
2. Lawrence Berkeley National Laboratory, 2024 United States Data Center Energy Usage Report: https://eta-publications.lbl.gov/sites/default/files/2024-12/lbnl-2024-united-states-data-center-energy-usage-report_1.pdf
3. McKinsey & Company — AI power: Expanding data center capacity to meet growing demand: https://www.mckinsey.com/industries/technology-media-and-telecommunications/our-insights/ai-power-expanding-data-center-capacity-to-meet-growing-demand
4. McKinsey& Company — How data centers and the energy sector can sate AI’s hunger for power: https://www.mckinsey.com/industries/private-capital/our-insights/how-data-centers-and-the-energy-sector-can-sate-ais-hunger-for-power
5. Siemens Energy — On‑site Power Generation for Data Centers (white paper): https://assets.new.siemens.com/siemens/assets/api/uuid:5d02c989-8681-4320-b4e6-5445fb1b9a60/sie-us-si-rss-data-centers-power-generation-whitepaper-en.pdf
6. GE Vernova — Gas Power Technology for Data Centers: https://www.gevernova.com/gas-power/industries/data-centers
7. Facilities Dive — Data centers seek flexible power solutions for resilience, sustainability: https://www.facilitiesdive.com/news/data-centers-seek-flexible-power-solutions-for-resilience-sustainability/753811/

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A federal-private partnership announced last week would bring 10 gigawatts (GW) of new power generation to Pike County, Ohio, pairing a large-scale natural gas buildout with a data center campus on former U.S. Department of Energy (DOE) land.

The announcement was part of a broader U.S.-Japan trade and investment framework that is beginning to take concrete shape. DOE and the U.S. Department of Commerce announced the agreement with SoftBank subsidiary SB Energy and AEP Ohio.

Under the arrangement, SB Energy plans to develop 9.2 GW of natural gas generation alongside a 10 GW data center complex at the Portsmouth Site, a former uranium enrichment facility that has undergone decades of environmental remediation. SB Energy has also committed $4.2 billion to upgrade and expand transmission infrastructure in Southern Ohio in coordination with AEP Ohio.

Both the generation and grid investments are structured so that costs are not passed to ratepayers, a condition the Trump administration has termed its “Ratepayer Protection Pledge.” Excess transmission and generation capacity, officials said, would be made available to the broader grid.

The Portsmouth announcement represents the most developed iteration yet of projects tied to Japan’s $550 billion U.S. investment pledge, which was framed as part of a trade agreement lowering U.S. tariffs on Japanese imports. A February announcement had outlined the project’s scale and general configuration, but left key execution questions unresolved, including interconnection, permitting posture, fuel supply and contracting structure.

Construction is expected to begin this year, though detailed engineering, permitting and financing documentation have not been publicly released.

NextEra also announces plans for large-scale gas generation

The Ohio deal was not the only large-scale natural gas development tied to the U.S.-Japan framework announced that week. NextEra Energy confirmed March 20 that President Trump had approved development of up to 10 GW of gas-fired generation across Texas and Pennsylvania hubs.

Those projects, including a Texas site developed in coordination with Comstock Resources, would be jointly owned by U.S. and Japanese interests and operated by NextEra, pending negotiation of definitive agreements.

NextEra CEO John Ketchum said the company’s hub-based development model, which currently includes nearly 30 sites at various stages of development, is designed to compress timelines and reduce execution risk. The company is targeting approximately 40 hubs total.

Whether execution keeps pace with announcement scale remains to be seen, but the volume of committed gigawatts and named partners represents a measurable step beyond earlier, more tentative project outlines.

Texas and PJM are notably two of the fastest-growing areas for large data center development and associated electricity demand.

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.”

Caterpillar moved to the center of the AI infrastructure buildout this week as developer Nscale said it would use the company’s natural gas generator sets to power a major new West Virginia data center campus tied to Microsoft and NVIDIA.

Monday’s announcement positions Caterpillar’s G3500 series reciprocating engine platform as core infrastructure for what Nscale said could become one of the country’s largest dedicated AI compute developments.

Under the plan, Caterpillar equipment would support 2 GW of onsite generation by the first half of 2028 at the Monarch Compute Campus in Mason County, West Virginia, giving the project a faster path to power as grid access and transmission upgrades remain a constraint for large data center loads.

Nscale said the campus would host up to 1.35 GW of AI compute capacity for Microsoft under a letter of intent tied to NVIDIA Vera Rubin NVL72 systems and the NVIDIA DSX AI Factory reference design. The company also announced it had acquired American Intelligence & Power Corp., which includes the 2,250-acre Monarch site and what Nscale described as the first state-certified AI microgrid in the U.S., with expansion potential beyond 8 GW.

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Trump urges tech companies to build their own power plants for data centers

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It’s the latest example of a data center project being structured around large-scale onsite natural gas generation, rather than waiting solely on utility service.

In a recent report, Cleanview identified 46 U.S. data center projects representing a combined 56 GW of planned behind-the-meter power capacity, which it estimated at roughly 30% of planned U.S. data center capacity in its tracker.

The research company also said 90% of the projects it identified were announced in 2025, indicating that “Bring Your Own Power” has shifted from a niche workaround to a more mainstream development path as grid interconnection timelines lengthen.

“A year ago, behind-the-meter data center power was a curiosity, embodied by xAI’s controversial decision to truck mobile generators into Memphis,” said Cleanview. “Now it’s an increasingly common development strategy.”

Cleanview added many of the projects it identified have secured equipment partners and are already under construction.

“Projects like Monarch demonstrate how Caterpillar’s natural gas generation platforms are being deployed as core infrastructure for data centers and other power intensive applications where reliability, speed of deployment, and lifecycle performance are critical,” Melissa Busen, Caterpillar senior vice president of Electric Power, said in a statement.

Nscale said the West Virginia site would operate independently of the local grid, which it argued would avoid adding costs to existing utility customers, while preserving the option of a future grid interconnection that could allow exports. The company also said it is pursuing carbon sequestration and a design intended to reduce water use.

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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).

The first three parts of this series outlined how water-side microbiological fouling and mineral scaling, and excess air in-leakage on the steam side, can greatly reduce heat transfer efficiency in a condenser. We also examined methods for monitoring condenser thermal performance and detecting upset conditions.

However, these fouling mechanisms can potentially induce corrosion and leaks in condenser tubes that allow cooling water ingress to the condensate. The costs from cooling water infiltration and subsequent effects on boiler water chemistry may at times dwarf those of degraded heat transfer. In this installment, we will examine several of the primary mechanisms that initiate corrosion, and we will briefly look at one of the most troublesome issues that impurities cause in steam generators. A later series will outline the online analytical instrumentation that is important for promptly detecting chemistry upsets and for maintaining normal chemistry control in steam generators.

Corrosion influenced by microbiological fouling

Microbes enter power plant cooling water by two principal pathways: the circulating water that supplies the condenser (and auxiliary heat exchangers), and from the air, especially in open recirculating systems with cooling towers. The major microorganisms are bacteria, algae and fungi, but in condensers, bacteria are the chief concern.

Free-floating, aka planktonic, bacteria are not a direct problem, but if the organisms are allowed to settle and form sessile colonies, the situation changes radically.

When bacteria attach to surfaces, some of the numerous species immediately begin to generate a protective, polysaccharide (slime) layer. The slime collects other microorganisms and suspended solids, and deposits can rapidly accumulate as shown in Figure 2.

In Part 1 we examined how fouling restricts heat transfer and fluid flow, but sessile colony development may be even more problematic in other ways. Deposits in general can establish corrosion cells where the area beneath the deposit becomes anodic to bare metal and begins to corrode. The localized attack generates pitting and potentially through-wall penetrations in a short time frame. Beyond oxygen depletion issues is that some bacteria within a colony, such as sulfate-reducers, release metabolic byproducts, including hydrogen sulfide (H2S), that are very destructive to many metals including steels. This attack is known as microbiologically induced corrosion (MIC).

I personally witnessed a MIC case where, during a month-long scheduled maintenance outage, cooling water was allowed to remain standing in the 15,000 tubes of a condenser. At startup, plant chemists immediately discovered excessive condensate contamination, which upon further inspection turned out to be the result of thousands of pinhole leaks in the 304L stainless steel tubes. An entire tube replacement, at huge cost, was necessary. This is but one example of the importance of proper layup procedures for all water/steam touched circuits of steam generators.

From a health standpoint, heavy microbiological deposits provide a habitat for Legionella pneumophila bacteria, which have caused many illnesses and deaths around the world for decades. Space limitations prevent further discussion here, but more information is available from the Cooling Technology Institute and other organizations.

Consider another case, not related to MIC, that illustrates the potentially extreme corrosion potential of sulfides. A contractor replaced the aging Admiralty brass (70% Cu, 29% Zn, 1% Sn) tubes in a condenser with the (usually) more durable 90-10 copper-nickel alloy. Within 18 months, numerous through-wall penetrations appeared in the new condenser tubes.

Subsequent investigation revealed that the material supplier had used a sulfide-containing lubricant during fabrication but did not completely remove the lubricant before shipping the product. The sulfides attacked the tubes in many locations. As in the previous example, this condenser required a complete tube replacement.

With regard to new power plant projects, my experience over several years of reviewing combined cycle project specifications is that design engineering personnel almost automatically select either 304L or 316L stainless steel for condenser tube material, without giving any thought to the chloride content of the cooling water. Chlorides can penetrate the protective oxide layer on these austenitic stainless steels and induce pitting. Recommended chloride limits are now 200 ppm for 304L and 500 ppm for 316L.² These concentrations can easily be exceeded in cooling systems with cooling towers, where all dissolved solids “cycle up” in concentration. Corrosion is exacerbated underneath deposits.

Other mechanisms that this author has observed, and which led to condenser tube failures include:

Effects of condenser tube failures on boiler water chemistry

For high-pressure utility units, including the heat recovery steam generators (HRSGs) of modern combined cycle plants, high-purity makeup and feedwater are required to prevent deposition and corrosion in boilers and the remainder of the steam-generating network.

Table 1 below, extracted from Reference 3, illustrates the recommended impurity limits in makeup water effluent and condensed turbine steam.

Table 1. Recommended Chemistry Guidelines Extracted from Table 1, Reference 3

*These values are identical for economizer inlet samples. The units μg/kg are equivalent to parts-per-billion (ppb). In a future Power Engineering series, we will examine online chemistry instrumentation requirements for complete steam generator coverage, but this abridged table is sufficient for the following discussion.

Cooling water from a lake or river typically contains several hundred parts-per-million (ppm) of cations and anions; primarily calcium, sodium, magnesium, bicarbonate, chloride, silica and sulfate, as well as other impurities including suspended solids. The concentrations increase if the water cycles up in a cooling tower. A condenser tube leak introduces these contaminants directly to the high-purity condensate.

Numerous reactions are possible when the impurities reach the boiler, which we will examine in greater detail in the future instrumentation series for Factor This Power Engineering. However, the most problematic issue in many cases is a reaction that can readily occur underneath boiler tube deposits.

Eq. 1: MgCl₂ + 2H₂O + heat → Mg(OH)₂↓ + 2HCl

A product of this reaction is hydrochloric acid (HCl). While HCl can cause substantial corrosion in and of itself, when the compound concentrates under deposits, the reaction of the acid with iron generates hydrogen, which in turn can lead to hydrogen damage of the tubes. In this mechanism, atomic hydrogen penetrates into the metal wall and then reacts with carbon atoms in the steel to generate methane (CH4):

Eq. 2: 4H + Fe₃C → 3Fe + CH₄↑

The formation of gaseous methane and hydrogen molecules induces cracking in the steel, greatly weakening its strength.

Hydrogen damage is very troublesome because it cannot be easily detected. After hydrogen damage has occurred, the plant staff may replace tubes only to find that other tubes continue to rupture. The following case history provides a graphic example, and it also relates to the last item in the bulleted list above about operator error being a potential culprit in contamination events.

Case history

An 80 MW steam generator supplied by a 1250 psig coal-fired boiler had just come online from a scheduled maintenance outage. Laboratory personnel discovered that a condenser leak was allowing contaminants to enter the system, such that condensate total-dissolved-solids (TDS) concentrations at times reached 0.75 ppm. Although the lab staff requested that the boiler be taken offline immediately, operations management refused due to load demand issues.

The boiler was on congruent phosphate control, so lab personnel increased monitoring frequency and attempted to maintain phosphate and pH levels within recommended guidelines. After approximately three weeks, operators discovered the source of the leak and corrected the problem. Two months later, boiler waterwall tubes began to fail with alarming frequency. The unit came off numerous times for tube repairs, and in at least one instance had only been back on-line for a few hours when another tube failed.

The failures happened so regularly that plant management scheduled an emergency tube replacement during the next semi-annual outage. The repair costs were at a seven-figure level. Postmortem research showed that the failures were from hydrogen damage, as shown in Equations 1 and 2 above. This event served as a huge lesson learned to plant management about the importance of maintaining proper steam generation chemistry.

However, the problem was not caused by a condenser tube failure, per say. The condenser hotwell was equipped with a drain line connected to the cooling water outlet tunnel. At the start of the outage, an operator opened the line to drain the hotwell but then forgot to close the isolation valve before startup. Once the unit returned to service, the strong condenser vacuum pulled cooling water into the hotwell. This happenstance provided an additional valuable lesson regarding the need for and adherence to precise shutdown and startup procedures.

Looking ahead to part 5

Steam condensation greatly improves the thermodynamic efficiency of power units. However, net efficiencies in the mid-30% range are about the best that can be expected for conventional sub-critical units. Mid-40% is possible with ultra supercritical units. These not-very-impressive values are a primary reason, in this era which places much importance on energy efficiency, for the development of combined cycle and cogeneration units with net efficiencies that reach or exceed 60%. We will examine the foundation behind such better efficiencies in part 5.

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References

1. Post, R., Buecker, B., and Shulder, S., “Power Plant Cooling Water Fundamentals”; pre-workshop seminar for the 37th Annual Electric Utility Chemistry Workshop, June 6-8, 2017, Champaign, Illinois.
   2. Past conversations with Dan Janikowski (ret.), former subject matter expert with Plymouth Tube Company.
   3. International Association for the Properties of Water and Steam, Technical Guidance Document: Volatile treatments for the steam-water circuits of fossil and combined cycle/HRSG power plants (2015).
   4. Buecker, B., Shulder, S., and Sieben, A., “Fossil Power Plant Cycle Chemistry”; pre-workshop seminar for the 39th Annual Electric Utility Chemistry Workshop, June 4-6, 2019, Champaign, Illinois.

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About the Author

Brad Buecker currently serves as Senior Technical Consultant with SAMCO Technologies. He is also the owner of Buecker & Associates, LLC, which provides independent technical writing/marketing services. Buecker has many years of experience in or supporting the power industry, much of it in steam generation chemistry, water treatment, air quality control, and results engineering positions with City Water, Light & Power (Springfield, Illinois) and Kansas City Power & Light Company’s (now Evergy) La Cygne, Kansas, station.

Additionally, his background includes eleven years with two engineering firms, Burns & McDonnell and Kiewit, and he spent two years as acting water/wastewater supervisor at a chemical plant. Buecker has a B.S. in chemistry from Iowa State University with additional course work in fluid mechanics, energy and materials balances, and advanced inorganic chemistry. He has authored or co-authored over 300 articles for various technical trade magazines, and he has written three books on power plant chemistry and air pollution control. He is a member of the ACS, AIChE, AMPP, ASME, AWT, and he is active with Power-Gen International, the Electric Utility & Cogeneration Chemistry Workshop, and the International Water Conference. He can be reached at bueckerb@samcotech.com and beakertoo@aol.com.

At POWERGEN 2026, talk about the what, how and when of power generation dominated just about every discussion. What are the options, how much power can we get, and when can we get it? Headquartered in Loveland, Colorado, Mesa Power Solutions has created a suite of products and service models that are designed to answer all of those questions and more.

Originally utilized in remote oil field environments, Mesa’s systems have evolved in a big way. Unlike traditional generators that require lengthy warm-up cycles, their systems can achieve a near-instantaneous transition to full power output. Their solutions are extremely adaptable, capable of delivering the raw power needed by heavy industrial sites as well as the high-availability requirements of data centers and small-scale commercial applications.

Dominating the booth was the Mesa PowerCore natural gas generator platform, which serves as a potential foundation for next-generation distributed energy resources (DERs). Specifically designed for industrial-scale demand response, peak shaving, and islanded microgrid applications, the PowerCore utilizes a highly scalable modular design. Engineers can deploy these units in standardized trains of up to four units per side, allowing for seamless multi-megawatt scaling. To reduce onsite commissioning time and complexity, each unit features integrated cable trays and high-capacity fuel manifolds. Additionally, the combustion cycle is tuned for ultra-low emissions to meet what can be strict regulatory requirements for large-scale stationary installations.

The GX22 Engine might be the best example of the versatility that Mesa provides. The engine block generates a substantial 500kW (0.5 MW) from a compact form factor. For heavy industrial loads or utility-scale integration, these modular assets can be paralleled to reach 1.2 MW and beyond. This flexibility allows for deep integration with PV arrays, Battery Energy Storage Systems (BESS), and utility-grade microgrids, providing stakeholders with a variety of options to answer those what, how and when questions associated with their power needs.

Beyond raw wattage, Mesa prioritizes both connectivity and security. Their proprietary telemetry has been built to eliminate vulnerabilities and prevent hacking. By combining standard cellular connectivity with Iridium satellite technology, these units are always connected in a way that enables awareness and understanding. While traditional systems are reactive in the sense that they’ll only provide an update after something has gone wrong, Mesa provides real-time diagnostics, with their Colorado-based monitoring team able to identify and resolve issues before they turn into outages or worse.

Whether it’s a high-intensity fracking site requiring plug-and-play reliability or a data center that needs continuous power, Mesa provides their customers with numerous options that aren’t just about a single product. Instead, their focus is on determining the right model and solution that makes sense for them in the present and future.

“It’s about helping the customer articulate their specific need,” said John Kriegbaum from the Mesa Power Solutions team. “What’s the appropriate piece of gear? Sometimes it’s as simple as throwing a switch, but other times it’s a custom data and telemetry package that allows a customer to monitor their own actual usage. We have the products and capability here to support all of it.”

By Brad Buecker, SAMCO Technologies and Buecker & Associates, LLC

The rapid development of data centers and other large energy users around the country is placing challenges on power generation supplies. Many experts recognize the need for a balanced energy production mix that includes renewables and dispatchable sources such as combined cycle and nuclear generation. Mike Caravaggio of EPRI (Electric Power Research Institute) summed it up well in his “We’ve got to have it all” presentation at POWERGEN 2026’s opening keynote session.

A key piece to this puzzle is ensuring the reliability, from a water/steam chemistry aspect, of combined cycle heat recovery steam generators (HRSGs), coal units being scheduled for extended service, and the potentially significant development of small modular nuclear reactors (SMRs). POWERGEN 2026 saw the first in a planned permanent co-location of the longtime Electric Utility & Cogeneration Chemistry Workshop. 

This article highlights the presentations from the just-concluded EUCCW to show the quality material that the conference has offered for decades, and that we intend to continue. Our workshop has covered numerous other important issues over the years that impact many additional industries. Topics regularly include cooling water treatment, industrial wastewater control, environmental issues, and others. We encourage interested readers to plan on attending future workshops and to perhaps consider sharing your expertise with a paper or simply through the excellent networking opportunities.   

HRSG Chemistry Developments

This author was very grateful for being given the leadoff presentation (and a subsequent encore presentation at the “O&M Zone” on the exhibit floor) that outlined up-to-date HRSG feedwater and boiler water chemistry programs. A strong motivating factor comes from direct experience and that of colleagues, in which combined cycle plant owners decide to operate with a “lean and mean” staff, with few if any chemistry-trained personnel. Problematic is that “lean” often accentuates “mean”, where even one water/steam or cooling water chemistry failure can potentially shut down the plant, or worse, jeopardize employee safety, as we shall see below.

My power industry career began in 1981 at a coal-fired utility, and over the last 4+ decades I have seen the evolution of water/steam chemistry treatment programs for conventional steam generators and HRSGs. Foremost is a major change in feedwater chemistry treatment to minimize flow-accelerated corrosion (FAC). FAC first became evident in 1986 when it caused a feedwater piping failure that killed four personnel at a nuclear plant. Other fossil-plant FAC failures have occurred in the years since, including one in an attemperator line to the sister plant of one at which I worked, which caused two fatalities. Severe FAC has been observed in many combined cycle HRSGs around the globe (due to improper chemistry practices), as reported by renowned water/steam chemistry expert Dr. Barry Dooley and colleagues. An FAC-induced failure is shown in Figure 1.

EPRI has performed extensive work on the causes and preventive measures for FAC, and the Reference 2 document should be in the library of all high-pressure steam generating plants.

Boiler (or in HRSG jargon, evaporator) water treatment chemistry has also been refined over the years, but with some adjustments for the complexity of HRSG configurations. Conventional coal-fired units are single pressure design, although some sliding pressure operation is often necessary to adjust for load changes. Conversely, combined cycle HRSGs are typically multi-pressure configuration, with the most common units having a low-pressure, intermediate-pressure, and high-pressure evaporator. Tri-sodium phosphate (Na₃PO₄) is usually employed for pH control in the IP and HP circuits, but in the most popular HRSG units, known as the feed-forward low-pressure (FFLP) design, a solid alkali such as TSP cannot be used in the LP circuit. Rather, the ammonia from feedwater pH conditioning is the proper choice. A key factor in modern phosphate programs is minimization of phosphate “hideout” i.e., the precipitation of phosphate on boiler tubes at high boiler temperatures. I addressed this issue in two of my POWERGEN/EUCCW 2026 presentations, and further details are available in publications from the International Association of the Properties of Water and Steam.

Dan Dixon of EPRI discussed issues related to under-deposit corrosion (UDC) in HRSGs. UDC is a problem that has plagued conventional steam generators for decades. Iron oxide corrosion products generated by poor chemistry programs or layup practices travel to the steam generator and precipitate on boiler/evaporator tubes, usually on the hot side. The porous deposits serve as sites for concentration of water impurities that can induce direct boiler tube corrosion and can also initiate hydrogen damage, an insidious mechanism that may cause widespread boiler tube failures, as this author has also learned from direct experience.

Additional Steam Generator Protection with Film-Forming Products and Vapor Phase Corrosion Inhibitors

Additional steam generator protection methods continue to gain ground. The last two decades or so have seen re-emergence of film-forming products (FFPs), with both amine and non-amine active groups. As the name film-forming products implies, the compounds establish a protective surface on steam generator metals. Dale Stuart of ChemTreat discussed these chemistries and outlined successful applications, while pointing out that research continues regarding use and efficacy of these programs in both power and industrial steam generator applications. 

Two interrelated questions still stand out in the author’s mind regarding FFPs; how well do they transport through superheaters/reheaters to downstream equipment, and how much thermal decomposition occurs in these high-temperature regions? Thermal breakdown of alkalizing amines (sometimes utilized for feedwater pH conditioning) is well known. The decomposition products, small organic acids and carbon dioxide, will depress the pH and raise the cation conductivity of the condensed steam, which in turn influences feedwater chemistry. Logic suggests that the organic-based FFPs also decompose to a considerable extent. An important point is that film-forming chemistry should be a supplement to and not a replacement of established feedwater and boiler water treatment methods.

Often not given proper consideration is metal protection during unit shutdowns. When a steam generator is taken out of service and left standing full of water or has pockets of water in spots such as non-drainable superheaters, air which enters as the boiler network cools can establish localized oxygen corrosion cells. Besides direct attack and metal damage, the corrosion products will travel to the boiler at startup to establish deposits for UDC, as mentioned above. Cortec’s Scott Bryan gave an excellent presentation on the increasing popularity and efficacy of vapor phase corrosion inhibitors (VpCIs) to protect steam generators during outages. These products can serve in both dry and wet conditions, where they continually release a non-hazardous compound that migrates throughout the steam generator circuits to form a protective layer on metal surfaces. During startup, the compounds exit the unit via the blowdown stream. VpCIs offer corrosion protection for other applications, including, most notably, cooling system protection during layups.

Makeup Water Treatment Evolution

High-purity makeup water production for utility boilers received a huge boost in the middle of the last century with development of synthetic ion exchange (IX) resins. The demineralization process received a further boost with the maturation of reverse osmosis (RO) technology later in the century and continuing until now. Personnel at many plants retrofitted RO upstream of existing IX demineralizers, which greatly extended IX run times and reduced chemical regeneration frequency. However, another transformation has been taking place. This is the increasing selection of micro- and ultrafiltration membrane technologies for suspended solids removal ahead of RO systems. 

Particulate removal is a critical pretreatment process to protect RO membranes. Clarifiers with effluent sand filtration were the common choice in the last century, but for many water supplies such as lakes or reservoirs, MF and especially UF are much more efficient at removing fine particles. (MF/UF treatment of some river waters can potentially be problematic due to the large surge of suspended solids during heavy precipitation.) A common design now for HRSG high-purity makeup water systems is UF for particulate removal, two-pass RO for bulk demineralization, and then mixed-bed polishing in portable “bottles” that an outside contractor generates off-site. Continuous electrodeionization (CEDI) is another polishing technique.

Cooling Water Treatment

Cooling water treatment is a critical (but sometimes overlooked) issue at an enormous number of industrial plants, not just power, so future EUCCW attendees should probably always expect to see this topic on the agenda. At the top of the list is microbiological fouling control, as biofouling can cause the most prompt and intense problems in cooling systems. Well-designed and operated chemical feed programs/systems are paramount for reliable operation. A difficulty that arose in the 1980s and continues to this day is that modern corrosion/scale inhibitor programs operate at a mildly alkaline pH around 8.0. As water pH rises above a pH of 7, the efficacy of standard bleach drops dramatically. If conditions allow microbes to settle on metal surfaces, some quickly begin to form a polysaccharide layer (slime) that protects the organisms and others from biocides. The slime/silt layer greatly reduces energy transfer in heat exchangers, reduces and restricts flow, and can induce severe under-deposit and microbiologically-induced corrosion.

Jo Anna Ordóñez of Water Tech outlined an emerging technology in which bleach potency can be enhanced with a special metal catalyst to produce a mineral oxychloride (MOCl) and hydroxyl radicals (OH∙) that have a much higher oxidizing power than conventional oxidizers. Having worked with cooling water treatment for years at three different power/industrial plants, the technology intrigues me, in part because of its reported ability to attack sessile organisms and the accompanying slime layer. Of course, nothing beats a well-operated program to prevent organisms from settling in the first place.    

Additional 2026 Presentations

The remaining two presentations from this year’s EUCCW also provided excellent information.

Brian Snyder of NiSource (the parent firm of Northern Indiana Public Service Company, NIPSCO) outlined a program that plant personnel implemented at one of their primary power stations to reduce scaling and fouling issues related to transport of coal combustion residuals (CCR), i.e., fly ash and bottom ash. As many readers are no doubt aware, issues regarding CCR storage and disposal have become high profile over the last several decades, which have been exacerbated by several spills of ash pond material. Many ash ponds still exist at both retired and active coal-fired power plants around the country, where concerns remain about ash disposal and the potential for pond leachate to enter surrounding aquifers and surface supplies. Interestingly, these ash impoundments may serve as sources for recovery of rare earth elements (REE). Research is underway regarding this possibility.⁴

We at the EUCCW also want to keep our finger on the pulse of nuclear plant development for future workshops. This year, Claudine Fields of Day & Zimmermann gave an informative presentation entitled, “Attracting the Next Generation of Nuclear Craft Professionals.” If the U.S. experiences a nuclear renaissance, potentially in the form of small modular reactor development, the industry will need a wide variety of personnel ranging from the trade crafts to engineering disciplines to safety and environmental management. Ms. Fields pointed out that the time to generate student’s interest in science and the potential for a good career is at middle-school or early high school age.   

The 2027 EUCCW

We are already making plans for the 2027 EUCCW, to again be co-located with POWERGEN next January in Salt Lake City. Steam generation chemistry will still be on the agenda, as combined cycle power plants remain an important part of the energy mix, and another year should help clarify planned nuclear development. Geothermal projects also are gaining steam (pun intended). Expect to see additional cooling water treatment discussion because this topic is critical for many industries. Makeup water treatment, with recognition of the increasing selection of alternative raw water supplies such as municipal wastewater treatment plant effluent, continues to be an important topic.  

To reiterate, we welcome your suggestions for cutting-edge topics to be included in the call for papers.

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References

1. Buecker, B., Shulder, S., and Sieben, A., “Fossil Plant Cycle Chemistry”; pre-workshop seminar for the 39^th Annual Electric Utility Chemistry Workshop, June 4-6, 2019, Champaign, Illinois.
2. Guidelines for Control of Flow-Accelerated Corrosion in Fossil and Combined Cycle Power Plants, EPRI Technical Report 3002011569, the Electric Power Research Institute, Palo Alto, California, 2017.  This document is available to the industry as a free report because FAC is such an important safety issue.
3. Post, R., Buecker, B., and Shulder, S., “Power Plant Cooling Water Fundamentals”; pre-workshop seminar for the 37^th Annual Electric Utility Chemistry Workshop, June 6-8, 2017, Champaign, Illinois.
4. “$8.4 Billion: Enormous Cache of Rare Earth Elements Discovered in America”; SciTechDaily, report from the University of Texas, Austin, March 17, 2025.

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Brad Buecker currently serves as Senior Technical Consultant with SAMCO Technologies.  He is also the owner of Buecker & Associates, LLC, which provides independent technical writing/marketing services. Buecker has many years of experience in or supporting the power industry, much of it in steam generation chemistry, water treatment, air quality control, and results engineering positions with City Water, Light & Power (Springfield, Illinois) and Kansas City Power & Light Company’s (now Evergy) La Cygne, Kansas, station. Additionally, his background includes eleven years with two engineering firms, Burns & McDonnell and Kiewit, and he spent two years as acting water/wastewater supervisor at a chemical plant. Buecker has a B.S. in chemistry from Iowa State University with additional course work in fluid mechanics, energy and materials balances, and advanced inorganic chemistry. He has authored or co-authored over 300 articles for various technical trade magazines, and he has written three books on power plant chemistry and air pollution control. He is a member of the ACS, AIChE, ASME, AWT, and he is active with POWERGEN (and the now co-located Electric Utility & Cogeneration Chemistry Workshop), and the International Water Conference.  He can be reached at bueckerb@samcotech.com and beakertoo@aol.com.

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.