Mitsubishi Power supplied the two M501JAC gas turbines, steam turbine, heat recovery steam generator and advanced control recovery system. The company said OCAPS could eventually accommodate up to 100% hydrogen.

“OCAPS is yet another way that we’re making sure Texas families and businesses have the energy and infrastructure they need to succeed,” said David Borde, CEO of Entergy Texas. “Our customers count on us to power critical parts of their everyday lives, and OCAPS helps us deliver even more of the safe and reliable power they deserve in a cost-effective manner. Today is a huge milestone for our communities, and a big step toward the stronger and more resilient energy future Southeast Texas needs to thrive.” 

The design of OCAPS allows operators to quickly increase or decrease power production to match how much electricity customers are using, Entergy said.

The utility broke ground on the project in the spring of 2023. The expected total cost of the project was $1.2 billion at the time, although the utility has not updated the actual cost.

Texas added more residents than any other state between 2024 and 2025, and Southeast Texas continues to see new business and industrial development. Because of this growth, Entergy Texas said it expects electricity demand across its service area to grow by about 13% between 2024 and 2028, which the utility argues increases the need for more modern and reliable power generation resources.  

Including OCAPS, Entergy Texas plans to add more than 2.4 GW of new generation capacity by 2028. That also includes the Legend and Lone Star power stations, two natural gas facilities which would add more than 1,200 MW of generation capacity to the state. Both plants were approved by the Public Utility Commission of Texas, or PUCT, in 2025 and are expected to begin serving customers in 2028.

Air permitting continues well after permit issuance. Whether you are a large, Title V source or a small synthetic minor facility, eventually either the state/local agency or the EPA will come knocking on your door for an inspection. How you prepare for the inevitable will decide whether the inspector leaves a business card or leaves a fine.

Step One: Read your permit. It’s amazing how many compliance managers have never actually read their permit. It’s the roadmap, the blueprint, the flight plan. Without reading the permit, you’re flying blind. Print a copy. Highlight the important parts. Make a table of the limits. Make a calendar of the deadlines and recurring events, laminate it, and use a dry erase marker to document completion of each task. (Figure 1 shows an example.) Put recurring appointments in your Outlook calendar AND copy at least two other backup people. Except at very large plants, environmental compliance duties are often assigned to a combination health, safety, environmental manager. Safety is an hourly activity; air compliance often occurs weekly, monthly or semiannually. Keeping reminders in one person’s schedule guarantees deadlines will be missed.

Step Two: Put everything in one place and in one format. If you are doing everything electronically, put it all in one file folder, on a shared drive. Everything. If your facility is paper-based, get one three ring binder. Print everything, put it in there. Again…Everything. If your records are sometimes electronic and some are paper, stop that and make them all one way or the other. Create a tab or file folder for every report. Organize your data and make it easy to tell if a report is missing (the tab is empty; the files are all named consistently and it’s clear a year is skipped).

Mark the binder/computer folder with Air Compliance, or Air Permit, or AIR. This is not the time for subtlety. Make sure everyone in the facility and management chain knows the storage location. A three-ring binder on a shelf in the environmental manager’s office, boldly labeled “Air Compliance Records” cannot be missed and is available during a network outage.

Step Three: Redundancy. People switch jobs, retire, go on vacation. Have a backup person (or four) that knows the location of the compliance binder or network folder. Create a succession plan; have an assistant. Document institutional knowledge of why that report is needed, the consequence of an exceeded limit, the reason why an operating parameter is recorded. Smaller facilities are often more complicated to inspect and more likely to be out of compliance because the environmental staff turn over frequently, do not have an environmental background, and are kept busy daily with health and safety activities.

Step Four: If you need clarification …. Ask! The inspector wants you to be in compliance. If you are confused about your permit, want to confirm your records are complete, or need help with the difference between 12-month rolling and 12-month calendar, your inspector wants to help. Many agencies have procedures for mock inspections.

Step Five: Documentation and communication. If you don’t write down that you met a limit, then you did not meet the limit. Monitor downtime cannot be differentiated from monitor exceedances. Foster an atmosphere that potential exceedance should be brought to the compliance manager’s attention. Maintenance staff and operators should know that their concerns should not be swept under the rug. Hiding a non-complying situation is far worse than reporting one. There are actually ways to avoid or minimize fines under certain self-audit conditions. When you report your problems, you establish trust with the inspector. Loss of credibility cannot be repaired; a dishonest reputation cannot be mended.

Much thanks to Kansas inspectors Rollin Sachs and Josh Webb for their input.

“This is a common challenge that we’re seeing in industry,” said Chris Wiles, principal AI solutions architect at 1898 & Co., “whether it’s to repower an old coal plant or something brand new where all the data just didn’t get encapsulated from planning to design to construction.”

1898 & Co. is running a pilot with Cleco at one of the utility’s repowered plants in Louisiana. The facility’s records are spread across older and upgraded EAM systems, plant and personal drives, and the institutional knowledge of long-tenured staff.

“Quite often, it’s in a person’s head,” said Wiles.

The pilot will be featured in a POWERGEN session, An AI case study: Improving asset data while setting the foundation for more efficient plant operations this January in Salt Lake City. It’s part of a larger show topic of how artificial intelligence is improving power generation performance and efficiency.

Wiles said the pilot began with a functional workshop and offered more advanced help, such as building job plans and reconciling inventory.

“The reason we start with functional workshops is identifying where the data isn’t,” he said. “Everybody in the plant knows somebody they can go to and ask a question because they can’t find the documentation.”

Cleco’s first request was simpler: for its staff to be able to find their piping and instrumentation diagrams and other sources of truth. From there, 1898 & Co. moved to help the utility centralize its records by vectorizing them, so staff could search all sources at once, regardless of the data’s type, source or age.

1898 & Co. is now writing system and subsystem narratives where clear descriptions are missing. These cover what the plant was before the repower, what changed, and what’s there now.

Longer-term results from the Cleco pilot are still being collected. However, another customer, Cooperative Energy, ingested data for 16,000 assets from three plant drives, reconciling three sets of PM recommendations.

“[Cooperative Energy] saved about $3 million in unadjusted labor costs by being able to extract all the data from three plant drives and populate all the attributes and specifications for those 16,000 assets,” said Wiles.

The Cooperative Energy project also captured knowledge that never made it into a database at all. Midway through the work, an employee announced their retirement, leaving behind dozens of pages of handwritten notes.

“All of their lubricants for all the assets in question were literally written down on sheets of paper, and they’d never been entered in any system,” said Wiles.

The tool ingested those pages and flagged where they conflicted with recommendations already in the EAM. In at least one case, the handwritten guidance turned out to be the part that wasn’t possible, so the cross-check let the team sort out which data was right before bringing it into the EAM.

Wiles described the time savings, projected at one to three hours per week per worker, as a way to shift staff to higher-value work rather than cut headcount.

He said AI is enabling operational changes that weren’t possible even two years ago.

“We’re building out technology pretty quickly that manifestly changes the way that you operate a plant for the better,” he said.

Wiles will present “AI case study: Improving asset data while setting the foundation for more efficient plant operations” at POWERGEN 2027, Tuesday, Jan. 19, at 10:15 a.m. in Salt Lake City. See the full agenda and register for POWERGEN 2027.

Some graduates have already earned promotions or entered accelerated training programs for specialized trades, including electrical work and pipefitting.

TIC Reconnect launched at Entergy Mississippi’s Delta Blues Advanced Power Station with support from state workforce development agencies and regional partners. The initiative has since expanded to Entergy’s Legend Advanced Power Station in Texas.

As utilities race to bring new generation online, securing skilled labor is becoming as critical as securing turbines.

Entergy’s bet? Build the workforce alongside the power plants. Because megawatts don’t build themselves.

The new gas capacity would be built at Black Hills’ existing Cheyenne Prairie Generating Station between 2027 and 2029 for $1.8 billion. The new units would be owned by a non-regulated Black Hills affiliate, not the Wyoming utility.

But the gas expansion is only part of the power play.

The project also includes 2.1 GW of third-party resources, which the project release suggests would be powered by turbines and fuel cells. Those resources would operate through a privately managed microgrid under Wyoming’s Large Power Contract Service tariff. Black Hills would not own them but instead collect a microgrid management fee for coordinating grid operations, reliability services and dispatch across the contracted resources and market purchases.

Google picks up the tab

Black Hills said Google would cover the costs of serving the data center, with contractual protections intended to shield existing utility customers from project-related expenses.

Those protections address stranded assets, early termination and unexpected costs.

Google has advanced $399 million for long-lead equipment purchases, which Black Hills expects to reimburse before July 2027.

The utility projects about $150 million in net income from the project in 2030 and $2.4 billion in unlevered free cash flow through 2048, after accounting for its generation investment. 

Black Hills expects to start earning returns on the investment next year by introducing microgrid management fees.

The company has secured an air quality permit for the Cheyenne Prairie expansion and is pursuing additional siting and transmission approvals.

Google’s gas deal draws criticism

There is no settled answer to what kind of generation should serve the wave of data center loads being built. Utilities facing gigawatt-scale requests have largely turned to new gas-fired capacity which they can site at existing plants.

Tech companies driving the data center demand have pledged to run on carbon-free power. Google, for example, has a goal of matching its consumption with clean energy around the clock by 2030.

There are a range of approaches between those two positions. These include nuclear uprates and restarts, long-term PPAs for solar, wind and storage, on-site or behind-the-meter (BTM) generation and hybrid arrangements like the one in Cheyenne. State regulators, grid operators and developers are seemingly working through the trade-offs between speed, reliability, cost and emissions one deal at a time.

But Google’s latest agreement is drawing criticism for its reliance on new gas.

Jesse Jenkins, a Princeton University energy researcher and co-founder of Firma Power, criticized the Wyoming deal as a departure from Google’s emphasis on bringing new clean electricity online. Firma Power, develops software and power procurement strategies to assemble renewable energy and storage portfolios for large electricity customers. 

His criticism came as Google announced a separate agreement with Constellation Energy to add 890 MW of nuclear capacity through upgrades to existing reactors — a deal Jenkins praised on X as a model for powering data centers.

Jenkins argued that data center developers should instead tap wind, solar and battery storage projects awaiting grid interconnection rather than build new gas-fired generation to meet surging electricity demand.

DOE puts $4.2 billion behind more nuclear megawatts

A day earlier, DOE announced a conditional loan commitment of up to $4.2 billion for Vistra to upgrade its nuclear fleet.

The projects would add 433 MW of capacity at Beaver Valley in Pennsylvania and Davis-Besse and Perry in Ohio while preserving nearly 4 GW of existing nuclear generation.

Another tech giant expects to benefit from the additional capacity. We reported in January that Vistra entered into 20-year PPAs to provide more than 2,600 MW of energy from the three nuclear plants to support Meta’s operations in the PJM region. This includes the 433 MW of incremental capacity from the uprates.

Meta’s purchases under the agreements would begin in late 2026, Vistra reported earlier this year, with additional capacity added to the grid through 2034.

Perry is a single-unit power plant located on Lake Erie, about 40 miles northeast of Cleveland in Perry, Ohio. The plant has a capacity of 1,268 MW and provides more than 600 full-time jobs in the North Perry area. Davis-Besse is a single-unit power plant in Oak Harbor, Ohio, located on Lake Erie, approximately 35 miles east of Toledo. The plant has a capacity of 908 MW. Beaver Valley is a two-unit power plant in western Pennsylvania, about 30 miles northwest of Pittsburgh. The plant has a capacity of 1,872 MW.

DOE’s latest financing could support future uprates at Vistra’s Comanche Peak nuclear plant in Texas.

No new reactor required

The back-to-back announcements underscore a growing strategy for meeting surging U.S. electricity demand: Get more juice from the nuclear plants already on the grid.

Uprates can boost reactor output through upgrades to turbines, steam generators, controls and other equipment without the timeline — or price tag — of building an entirely new nuclear plant.

That’s especially attractive in PJM, where data center growth is helping push electricity demand higher.

More Nuclear Upgrades

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Vistra and Meta ink PPA for 2.6 GW of nuclear power in PJM region

Vistra signed 20-year PPAs to supply over 2,600 MW of nuclear energy to Meta in the PJM region, ensuring plant operations and adding capacity by 2034.

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Nuclear steam-side upgrades aim to deliver fast, firm megawatts

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Google said its Constellation agreement brings the amount of new U.S. nuclear capacity it has helped enable through uprates and reactor restarts to more than 1.5 GW.

For a grid hunting for firm power, existing nuclear plants are increasingly looking like low-hanging megawatts.

“By pairing industry innovators with leading U.S. test facilities and technical expertise, HyTN accelerates the development of next-generation technologies that keep hydropower reliable and abundant,” said H2O Director Nichole Fitzgerald.

As Hydropower accounts for nearly 6% of the United States’ total utility-scale electricity generation, DOE argues that modernizing existing hydropower plants and implementing new technologies will help the nation meet its growing energy demand and drive down energy prices.

This is the second round of selections from HyTN, which offers access to more than 65 specialized physical testing and modeling capabilities ranging from hydraulic and biological testing to techno-economic analysis. The technology developers selected for this cohort have been matched with these capabilities, pending negotiations, based on their testing needs.

The 14 selected projects are as follows:

• Dry Surface Technologies, LLC, based in Guthrie, Oklahoma, will work alongside Pacific Northwest National Laboratory (PNNL) to scale up the production of a non-toxic antifouling coating to a pilot-scale manufacturing process, aiming to provide a less expensive, non-toxic alternative for preventing clogged components.
• Emrgy, Inc., based in Atlanta, Georgia, will demonstrate at Colorado State University the prototype of a low-head turbine technology platform designed to generate energy from man-made water infrastructure like irrigation canals. 
• GenH, Inc., based in Somerville, Massachusetts, will test a “rapidly deployable, low-impact” technology to generate electricity from existing non-powered dams at the University of Minnesota. Results will inform a predictive framework meant to help design custom systems for different dams.
• Hydro Green Energy, LLC, based in Birmingham, Alabama, will work with the National Laboratory of the Rockies to develop a grid-focused economic analysis for a pumped storage hydropower project at an existing dam and reservoir, with the goal of facilitating advancement towards licensing and construction. 
• Kingsbury, Inc., based in Philadelphia, Pennsylvania, is investigating an advanced thermoplastic polymer as a possible bearing material for use in hydropower generators, continuing its work with Oak Ridge National Laboratory (ORNL) from the first round of HyTN. 
• Nucleic Sensing Systems, based in Saint Paul, Minnesota, will work with ORNL to validate its real-time environmental DNA (eDNA) sensor, which monitors water for the presence of fresh, dissolved eDNA and distinguishes it from stale or transported eDNA. 
• Prometheus Innovations, LLC, based in Lafayette, Louisiana, will continue its work from the first round of HyTN, collaborating with PNNL to assess a coating that could prevent harmful aquatic growth like invasive mussels and brown algae.
• Prometheus Innovations, LLC will also work with PNNL to test an underwater net coating that can attract or repel fish to prevent them from swimming into water intake structures.
• Public Utility District No. 1 of Chelan County, based in Wenatchee, Washington, will evaluate self-lubricating, grease-free wicket gate stem bushings at PNNL’s tribological test facility, determining its effectiveness for upgrading hydropower infrastructure. 
• Public Utility District No. 1 of Chelan County will also work with PNNL to validate a low-temperature “cold spray” technique to repair worn hydropower turbine components on-site without using heat. 
• Radmantis, based in Toledo, Ohio, will use Verdantas’ Fish Passage Survival and Behavior Steel Testing Flume Facility to continue their work from the first round of HyTN, evaluating whether mechanically guided fish entrainment improves AI-based selective fish passage at hydropower facilities. 
• RCAM Technologies, Inc. DBA Sperra, based in Boulder, Colorado, will work with Polaris EcoSystems to advance a 3D-printed subsea pumped storage hydropower system that stores electricity in hollow concrete spheres on the seafloor.
• University of Washington’s Applied Physics Laboratory, based in Seattle, Washington, will collaborate with PNNL to assess the reliability and durability of a small, low-cost sensor designed to monitor water quality for hydropower and pumped storage facilities in a more economically feasible way.
• VBASE Oil Company, based in Pendleton, South Carolina, will continue their work from the first round of HyTN, collaborating with ORNL to test a lubricant  for use in hydropower facilities. 

“We were honored to welcome Assistant Secretary Robertson and the Department of Energy team to Kingsbury,” said Mike Brawley, President and CEO of Kingsbury. “For more than a century, Kingsbury technology has supported hydropower generation across North America. We are proud to continue collaborating with Oak Ridge National Laboratory and the Department of Energy on research that can help improve the reliability and longevity of critical hydropower equipment.” 

The HyTN voucher opportunity is funded by H2O and managed by ENERGYWERX in partnership with DOE, a collaboration made possible through a partnership intermediary agreement set up by DOE’s Office of Technology Commercialization.

Who was in the first round?

In early 2025, DOE’s Water Power Technologies Office (WPTO) announced the first 12 hydropower technology developers that will receive testing support through the HyTN.

The 12 selected technology developers were:

• Carpenter Technology Corporation, based in Philadelphia, planned to evaluate the performance of its advanced A-21 alloy at Argonne National Laboratory by testing the material in a controlled environment to identify potential shortcomings and opportunities for improvement. The A-21 alloy is a type of stainless steel that’s extra strong and wear resistant, which could improve the reliability of bearings in hydropower systems. These bearings support and guide rotating machines like turbines. The A-21 alloy could help prevent corrosion, abrasive wear, and cracking/splitting of bearing components, which could mitigate repairs to turbines and reduce the amount of time they need to be offline for those repairs.
   
• Continuous Solutions, based in Portland, Oregon, worked to develop a novel generator and inverter system to produce electricity and regulate power in 10-to-100-kilowatt-scale microhydro turbine systems, which can provide reliable energy for remote areas, small communities, and off-grid applications. Continuous Solutions tested its technology at the Distributed Energy Technologies Laboratory, which is part of Sandia National Laboratories, focusing on electrical standards qualification, turbine design and validation, and system performance in various environmental conditions. 
   
• InPipe Energy Inc., based in Portland, Oregon, is developing an off-grid energy system that converts excess pressure in water pipelines into renewable electricity, offering a sustainable energy solution for remote locations or areas with limited access to an electricity grid. Researchers will use testing capabilities at Continuous Solutions to validate the technology’s effectiveness in an off-grid setting. InPipe Energy will also integrate a battery to store the energy generated and demonstrate consistent energy production and storage.
   
• Kingsbury, Inc., based in Philadelphia, is working with Oak Ridge National Laboratory to evaluate various surface finishes, lubricants, and materials for fluid film bearings used in hydropower units. In a fluid film bearing, a thin film of lubricant separates the stationary bearing and rotating shaft to produce a smooth, low friction motion. Through this testing, Kingsbury aims to improve the reliability, performance, and efficiency of generators for new and existing hydropower and pumped storage hydropower facilities.
   
• KW River Hydroelectric, Inc., based in Cincinnati, evaluated the performance of a prototype crossflow turbine system that is designed to sit underwater at the base of a dam, allowing it to both generate electricity from water flowing over the dam and eliminate unsafe water current conditions below the dam. Testing at Verdantas’ Hooper Facility simulated real-world conditions to determine whether the prototype system performs as expected.
   
• Littoral Power Systems, Inc., based in New Bedford, Massachusetts, worked with Pacific Northwest National Laboratory to evaluate the effectiveness of a louver—a covering made of angled slats—for water intake pipes that prevents fish from entering hydropower turbines. Testing will help verify the louver design for species of migrating fish common on the East Coast and provide data for fish and wildlife agencies evaluating hydropower projects.
   
• Optical Waters Inc., based in Amherst, Massachusetts, worked with Oak Ridge National Laboratory to test optical fibers that emit ultraviolet light that can prevent the accumulation of plants, algae, and other microorganisms on surfaces underwater, a phenomenon known as biofouling. This chemical-free solution can reduce biofouling in hard-to-reach areas within hydropower systems, such as pipes and tight channels, improving efficiency and lowering maintenance costs at hydropower facilities.
   
• Prometheus Innovations, LLC, based in Lafayette, Louisiana, is evaluating and refine a multiuse composite polymer coating working with Pacific Northwest National Laboratory. This coating is designed to minimize the environmental impacts of biofouling, including the accumulation of mussels on submerged surfaces. This coating can also optimize the performance of hydropower facilities by improving acoustic sensitivity and reducing fluid friction across the surface of submerged screens and pipes.
   
• Radmantis, based in Toledo, Ohio, is using Verdantas’ Fish Passage Survival and Behavior Steel Testing Flume Facility to assess a device that uses artificial intelligence to classify and divert fish by species. Successful proof-of-concept testing will assist in further evaluating how selective fish passage can be incorporated at a hydropower facility.
   
• River Connectivity Systems, based in Bainbridge Island, Washington, worked with Pacific Northwest National Laboratory to apply and test biofouling-resistant coatings on its River Connectivity System, a selective withdrawal screen that aims to minimize the environmental impacts of dams by reducing the spread of invasive species and improving downstream water quality.
   
• VBASE Oil Company, based in Pendleton, South Carolina, is working with Oak Ridge National Laboratory to analyze environmentally acceptable turbine oil, hydraulic fluid, and gear oil as high-performance replacements for traditional lubricants currently used in hydropower facilities. The team is testing these alternatives to understand if they can effectively prevent friction and wear in components. Using environmentally acceptable lubricants in hydropower facilities can reduce the risk of environmental hazards. 
   
• Verterra Energy Inc., based in New Brighton, Minnesota, worked with Pacific Northwest National Laboratory to observe and characterize potential interactions of fish species with Verterra’s modular hydropower technology, which has a turbine that is capable of producing power in shallow water conditions.

WPTO launched the first phase of HyTN in June 2024, which included testing facility selection. HyTN’s three phases are:

• Phase 1: Testing facility (voucher provider) selection: Test facilities could apply to join the network. If selected and matched to a technology developer, the test facility would receive funding to provide testing services to the technology developer.
• Phase 2: Technology developer (voucher recipient) selection and matchmaking: Technology developers can apply for testing services. If selected, developers will be matched with a test facility. Developers will receive up to $250,000 in services to implement targeted physical testing activities that advance technology readiness.
• Phase 3: Project Execution: Facilities and developers will determine the scope of work, establish a contract and begin work.

Originally published in Factor This.

Wisconsin: Project Lighthouse waits on transmission

Oracle’s massive Project Lighthouse campus in Port Washington, Wisconsin is under construction, but connecting it to the grid has become more complicated.

Vantage Data Centers is developing the four-building campus, with Oracle as the tenant. Utility records put its total electricity demand at roughly 1.3 GW.

American Transmission Co. applied in September 2025 for approval of more than $1 billion in transmission infrastructure needed to serve the campus. Wisconsin regulators later withdrew their determination that the application was complete after extensive revisions, requiring ATC to restart the process.

Oracle still lists customer delivery for the second half of 2027. 

However, independent analysis from Aterio estimates partial power could arrive in December 2027, with the full 1.3 GW available by October 2028. 

Those are Aterio estimates, not company targets. Aterio publishes predictive datasets and forecasts on U.S. data centers.

Construction can keep moving, but energization is another story.

New Mexico: Project Jupiter’s gas supply hits turbulence

Oracle’s 2.45-GW Project Jupiter in New Mexico highlights another potential bottleneck: Even behind-the-meter generation needs fuel.

Oracle recently issued a force majeure notice tied to the Stargate campus, although the company says the project remains on track for 2028. The notice could allow Oracle to delay payments if the facility misses that target.

The planned 1,400-acre campus in Doña Ana County, near Santa Teresa, is expected to rely heavily on natural gas-powered fuel cells from Bloom Energy.

But the pipeline intended to supply the project has encountered permitting problems and is running roughly six months behind schedule, pushing expected completion to February 2027.

Project Jupiter hasn’t missed its deadline. Its supporting fuel infrastructure has, adding uncertainty to a project designed in part to sidestep traditional grid constraints.

Texas: Stargate’s ramp takes longer

The flagship Stargate campus in west Texas is operating, but its ramp to full capacity has taken longer than some early estimates suggested. 

The $500 billion AI infrastructure initiative in Abilene is backed by OpenAI, Oracle, SoftBank and MGX.

Samaritan Research initially estimated 600 MW would be operational earlier this year. It revised that forecast after an Oracle disclosure indicated about 200 MW was online in April and subsequently projected the full 1.2-GW campus would be operational in the fourth quarter.

Oracle reported in September that OpenAI had taken delivery of about 75% of the capacity it’s providing at the campus.

The distinction matters for utilities trying to forecast AI-driven electricity demand: Building completion, energization, and full compute load are different milestones.

Ohio: Microsoft blames messy Midwest spring weather

Spring weather in the Midwest is anything but predictable — and it’s been slowing Microsoft’s data center buildout in Licking County, Ohio.

Microsoft said in May that weather delays and time-sensitive construction milestones could require Sunday work to keep projects in Heath and Hebron on schedule.

In Heath, crews continued site preparation through the summer for a planned five-building, 264-MW data center campus designed to expand Microsoft’s cloud infrastructure in central Ohio.

In Hebron, construction continued through the summer on Microsoft’s six-building, 317-MW data center campus, including site development and substation work across more than 200 acres.

From canceled to operational in the Buckeye State

Microsoft’s data center buildout in Licking County, Ohio, hasn’t exactly gone according to plan.

After Microsoft walked away from the $1 billion project in April 2025, plans resurfaced with a 2029 operational target.

The current timeline calls for mass grading through November, vertical construction in 2027 and 2028, followed by roughly a year of commissioning and ramp-up.

Microsoft reiterated in a June 2026 economic impact report that its three Licking County campuses remain on track.

Aterio, however, says key milestones bear watching:

• Whether grading finishes on schedule
• When Heath and Hebron move to vertical construction
• The 2029 target holds

The bigger problem: Forecast megawatts aren’t real megawatts

Data center projects underscore a growing challenge for power producers and utilities: Demand may be real, but its timing isn’t guaranteed.

Grid connections in major U.S. markets can take three to four years — and as long as seven years in northern Virginia. Of 16 GW of data center capacity announced for delivery in 2026, only about 5 GW was under construction as of this summer, according to TD Economics.

Texas has gone further, halting new data center grid connections while regulators audit projects amid concerns about speculative or duplicate requests.

Proposed U.S. data center power requests have topped 700 GW, more than 10 times the estimated electricity currently consumed by U.S. data centers.

For generators, that’s the rub.

Data centers want gigawatts now. Power plants, pipelines and transmission lines still operate on timelines measured in years.

The gap between the two could determine how much of the AI power boom actually shows up on the grid, and when.

A new forecast from Enverus Intelligence Research projects that BTM will serve 25.5 GW of demand from new U.S. industrial facilities through 2030.

“We built the forecast by heavily risking both whether new load comes online and how much goes BTM,” said Alex Nevokshonoff, senior analyst at EIR. “We are confident the numbers are realistic, and if anything, likely to rise as more data centers are pushed BTM. 

“About 60% of the expected BTM load is tied to projects we view as high-confidence to come online within the forecast timeline.”

Data centers account for 22.5 GW — or 88% — of that demand.

That represents about 36% of all U.S. data center capacity additions expected during the five-year period, according to Enverus.

“All 22.5 GW comes from new data centers targeting operation by 2030, and the shift to BTM is driven predominantly by grid interconnection delays,” Nevokshonoff said. “Most operators prefer a grid connection for simplicity and reliability. But delays in energization materially hurt project economics, so developers are turning to BTM power to come online faster.”

The trend is particularly pronounced in regions where grid constraints are already squeezing new development. 

PJM is expected to account for 7.5 GW of BTM demand, while ERCOT is projected at 5 GW. 

Together, the two markets represent nearly half of the forecast.

But the race for power isn’t just changing where data centers get their electricity. It’s changing what gets built.

Enverus estimates meeting industrial BTM demand will require 31.6 GW of new generation capacity, including 29.6 GW of natural gas-fired generation.

“About 62% (19.5 GW) of the 31.6 GW is tied to high-confidence loads expected online by 2030,” Nevokshonoff said. “The remainder is allocated using top-down analysis, such as data-center capex spend and industrial trends, which we also view as relatively high-confidence but which is not tied to individual facilities.

“Some high-confidence projects have ordered more generation than we assume comes online by 2030, so we risk generation to the load we expect to materialize, based on factors like contracted compute, rather than taking nameplate load or generation contracts at face value.”

And developers aren’t necessarily waiting around for the biggest turbines.

Reciprocating engines, small- and medium-frame gas turbines and fuel cells are expected to account for 61% of projected gas-fired BTM capacity.

The reason: speed.

Those technologies can reach commercial operation in roughly 18 to 24 months, according to Enverus, compared with as long as 80 months for a large-frame combined-cycle plant.

“Large-frame gas turbines have traditionally delivered reasonably priced baseload power with low heat rates, which cuts operating costs,” Nevokshonoff said. “But demand has sold out many major manufacturers into 2030 and pushed prices up, so developers who need power quickly are looking elsewhere. 

“Data centers that ordered large-frame units a year or two ago will receive them and energize on time. Anyone who did not order in 2024 or early 2025 has been pushed toward smaller, modular options such as aeroderivatives and reciprocating engines, which typically deliver in about 24 months.”

Modular technologies also require less excess capacity to maintain reliability. 

Enverus estimates reciprocating engines and fuel cells can operate with generation overbuild factors as low as 1.1 times demand, compared with about 1.5 times for large-frame plants.

That combination of faster deployment, lower capital costs and less required overbuild gives modular generation an edge as data center developers scramble to secure power.

“Initially, reciprocating engines and small turbines won on availability, since they could be delivered sooner despite costing more per kW than a CCGT plant,” Nevokshonoff said. “Now economics are shifting in their favor too.” 

Demand has pushed large-frame prices above reciprocating engines for a new order placed today.

Redundancy also favors smaller units because many BTM data centers plan to overbuild primary generation for reliability. 

Modular fleets typically need only 10-20% overbuild, while 100+ MW large-frame units can require as much as 50%.

As grid interconnection timelines grow longer, technologies deployable within the next two years have a significant advantage.

The Tung Hsiao power plant in Miaoli County shows what a fast aeroderivative gas turbine installation looks like in practice. Six turbines went from install to full operation in ten months. The project ran from February 2022 to January 2023 and added 180 MW to the national grid.

For plant managers and project engineers planning similar fast track power plant commissioning, this project offers a clear example worth studying.

Turbine selection: Why aeroderivative units fit a tight timeline

The plant used LM2500XPRESS units, built with a modular design. About ninety five percent of each unit is assembled at the factory before it ever reaches the site.

That factory work is what made the schedule possible. Onsite crews mostly handled foundations, mechanical connections, electrical hookups and testing, and much of that work ran at the same time instead of one step after another.

The turbines also had to meet two demands common in modern grids. They needed to reach full power from a cold start in about eight minutes, which helps back up solar and wind. They also needed to run on a hydrogen blend, currently rated at thirty five percent with a plan to reach one hundred percent by 2030.

Turbine logistics and port coordination for fast track projects

Moving six large turbine units is not simple. Getting them through the port and onto the site without delays took careful planning long before the equipment arrived. A slow customs process or a missed shipping window can eat up schedule time fast.

Coordinated transport and port clearance kept equipment arrivals lined up with what site crews were ready for. This kind of end-to-end coordination is often what separates a ten-month schedule from one that drags on much longer, as shown in this project’s full case study.

Supply chains for turbine parts and other components were also under pressure during this period. The team managed sourcing actively instead of waiting for problems to show up, which helped the project avoid material shortages that could have stalled the schedule.

Grid interconnection and site readiness

Civil, mechanical, and electrical work all had to be ready before the turbines landed onsite. Many fast-track projects lose time here because site prep waits until equipment shows up, but that was not the case at Tung Hsiao.

The grid connection work was engineered and prepared ahead of delivery. This let the turbines get dispatched almost as soon as installation was finished.

Meeting emissions standards without slowing regulatory approval

Taiwan has strict air quality rules. The turbines needed Dry Low Emissions technology to meet them, cutting NOx and CO by more than ninety percent compared to standard combustion.

Many projects treat environmental approval as something that happens after construction. This project ran technology selection and regulatory approval at the same time, which is a big reason full compliance came through without delaying the schedule.

Building local workforce capability for long term operation

A turbine that arrives mostly built still needs people who know how to run it. The project included structured training and onsite workshops so local staff could take over operations and maintenance.

Support did not stop once the turbines were running. The team also provided ongoing performance monitoring and troubleshooting after commissioning. This detail matters as much as hitting the install date, since a plant staffed by undertrained crews tends to fall short of its contracted uptime within the first year.

Key takeaways for plant managers and project engineers

A few lessons from Tung Hsiao apply to most aeroderivative and fast track power projects.

• Factory preassembly cuts onsite schedule risk more than adding onsite labor ever will.
• Port clearance and logistics need the same attention as engineering milestones.
• Running environmental review alongside construction often saves the most time.
• Hydrogen readiness and low emissions technology are becoming standard, not extras.
• Workforce training should be part of the plan from day one, not an afterthought.

Conclusion

The Tung Hsiao project shows that a 180 MW plant can go from groundbreaking to full operation within a year. It took equipment choice, logistics, regulatory planning, and workforce training all moving together instead of one after another. As more grids look for this same mix of speed, low emissions, and renewable backup, this aeroderivative gas turbine installation offers a model worth studying.

About the Author: Laiba Mehboob is a senior technical content writer at Prismecs, a power generation equipment and services company, where she writes about the technologies and operational challenges facing power producers. She has spent several years in technical and SEO-focused content roles and also works as a data analyst, bringing a data-driven approach to industry writing.