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.

The bill, proponents argue, would cut down the arduous timeline for getting big energy projects off the ground at a time when demand is rising because of mushrooming data centers for artificial intelligence. The bill would ensure AI data centers are forced to pay for the increased electricity they use and would mark a significant change to a landmark environmental law that critics say slows the process of building energy projects.

Republican Sen. Shelley Moore Capito of West Virginia, chair of the Environment and Public Works Committee, called the bill “a major step toward making it faster and more efficient and easier to build infrastructure projects” of all types while maintaining important environmental protections.

Vote on the bill won’t happen until after the midterms

“The American people sent us here to do big things. This is a big thing. It’s monumental and it’s legacy-setting,” Capito said at a news conference at the Capitol where she was joined by Republican Sen. Mike Lee of Utah and Democratic Sens. Martin Heinrich of New Mexico and Sheldon Whitehouse of Rhode Island. The four senators lead the chamber’s energy and environment panels.

Heinrich said the bill “will mean more energy on the grid, more good-paying jobs, and lower electricity costs for families and businesses. And as data centers drive demand for more power, it will ensure they pay their fair share of the grid upgrades they require — not leave that bill to American families.”

A vote on the bill won’t happen until after the midterm elections — reflecting the fraught political reality as elections loom that could change partisan control of both chambers. But the bill represents a rare instance of bipartisanship over the country’s energy policy as lawmakers from both parties agree on the need to build new energy projects of all types.

Lee, who chairs the energy committee, said he is confident the bill will be approved in a lame-duck session in November, noting its bipartisan support and encouragement from business and environmental groups.

Whitehouse, the top Democrat on the environment panel, also was hopeful but said Democrats were still seeking clarity on how the bill will prevent President Donald Trump’s administration from blocking wind and solar projects.

He and Heinrich, the top energy Democrat, have decried what they call Trump’s “reckless and vindictive assault on wind energy” that includes repeated actions to block large-scale wind projects under construction off the East Coast. The administration suspended five offshore wind projects in December, citing unspecified national security concerns.

The projects later moved forward after federal judges intervened. A federal judge also struck down Trump’s executive order blocking wind energy projects early in his second term.

Brad Campbell, president of the Conservation Law Foundation, an environmental advocacy group, panned the deal, saying it “appears to adopt a fossil fuel industry wish-list.” He said the bill could roll back protections for clean water and endangered species, limit judicial review and curtail the power of the Environmental Protection Agency and states to consider impacts of energy projects.

Drew Maloney, president and CEO of the Edison Electric Institute, which represents for-profit utilities, said he was encouraged by provisions to streamline environmental permitting and “create project certainty.” The group is reviewing the transmission provisions to see how they affect efforts to deliver electricity to its 250 million customers, he said.

In a statement, the White House said the bill would “deliver transformative policies to lower Americans’ energy and housing costs, drive new construction and investment in American infrastructure, and create American jobs.”

Trump’s wind opposition played a role in delaying a deal

Trump’s opposition to wind power has been a consistent stumbling block to a deal on permitting reform, which Democrats say can only go forward if the administration agrees to allow previously approved projects to move forward.

Trump recently offered to ease his administration’s holdup on renewable energy projects, in part to entice Democrats to agree to a permitting deal. But it was unclear how long the offer would last and whether it would change after the election results are known.

Whitehouse called the administration’s proposal reasonable but said the overall issue remains “unresolved.”

Manish Bapna, president and CEO of the Natural Resources Defense Council, said his group was studying the bill’s details, but said: “Ensuring the agreement puts an end to the Trump administration’s war on clean energy — the cheapest and fastest sources of energy — will be a necessary element to any deal.”

Capito was confident such obstacles can be overcome.

Both parties recognize that for far too long, “America has had a permitting system filled with delays, expenses, red tape, uncertainty,” she said. “Too long, too expensive. And we’ve seen projects that should be finished more quickly (take) decades” to complete.

The Senate bill would limit legal challenges under the National Environmental Policy Act, a bedrock environmental law that requires federal agencies to consider a project’s possible environmental impacts before it is approved. The law has increasingly been blamed for stalling projects of all types.

Challenges under the National Historic Preservation Act also would be restricted. The law protects Native American cultural treasures and other important artifacts.

The bill would ease siting of interstate transmission lines and strengthen the Federal Energy Regulatory Commission’s authority to review major projects at the same time as state reviews, helping needed projects move through the overall permitting process more quickly.

The bill also would require data centers to pay for all associated transmission costs, preventing costs from being passed on to families or businesses.

It’s still unclear when construction will start and what the project will cost. But when TVA filed for its construction permit, it said its first reactor could begin operating around 2032.

The utility said it is still negotiating with industry partners on a cost-sharing plan to keep the bill off customers.

With the permit being issued this week, TVA becomes the first utility authorized to build a BWRX-300 and the second to be issued to build an advanced reactor in the U.S. The NRC’s approval of the project is also being touted as a potential licensing model for similar projects in the future.

The utility noted that the NRC completed its evaluation ahead of schedule and that the process could improve predictability for future advanced nuclear projects.

TVA said the location, along with state and federal support, positions the project as a potential hub for small modular reactor development. The Clinch River site has enough room for four small reactors.

It’s also seen as an opportunity for utilities and developers to explore advanced nuclear technology to meet rising electricity demand, including demand from data centers and artificial intelligence.

SMRs are designed to produce up to about 300 MW per reactor, with modular components that can be manufactured in factories and assembled on site.

The SGT-400 cores, each with an output of approximately 15 MW (1.7 GW total across all 119 cores), will be supplied over the span of multiple years, with the first batch to be delivered in 2027. The Siemens Energy cores will be integrated into the Dynamis DT18, the company’s newest next-generation “hypermobile” power package. The DT18 was built on the engineering principles of the Dynamis DT35.

“The demand for reliable and flexible power generation continues to grow as industries expand and energy needs evolve,” said Karim Amin, member of the executive board of Siemens Energy. “Together with Dynamis, we are helping customers access generation capacity quickly by combining proven gas turbine technology with innovative deployment concepts. This agreement highlights the strength of our SGT-400 platform and demonstrates how collaboration can help address growing demand for efficient and dependable power across a wide range of applications.”

Siemens Energy will manufacture the gas turbine cores at its facility in Lincoln, United Kingdom. The site serves as the company’s global center for small gas turbine manufacturing.

Over the summer, Dynamis placed a major order for Baker Hughes gas turbine technology, targeting the growing electricity requirements of data centers and oil and gas operations across North America. The order covers 76 NovaLT16 industrial gas turbines from energy tech company Baker Hughes, alongside gearboxes and generators powered by the firm’s Brush Power Generation with Automatic Voltage Regulator system. Together, the equipment represents about 1.3 GW of generating capacity, which will be integrated into Dynamis’ DT17 hypermobile power solution, combining gas turbine generation with a modular approach designed to deliver high power output in a relatively compact footprint.

• Lighthouse Energy Storage, Chautauqua County
• Zenobe Burns, Allegany County
• Eastwater Energy Storage, Monroe County
• KCE NY 5, Ulster County
• Blue Spruce Storage, Bronx County
• Palladium Storage, Bronx County
• Holtsville Energy Storage, Suffolk County
• KCE NY 37, Suffolk County

The projects must comply with New York’s energy storage safety codes, including requirements for safe facility siting, first-responder training and emergency response plans.

Payments won’t be made until developers obtain required permits, local approvals and enter commercial operation.

719 MW of new renewable generation

The 13 contracts for large-scale renewable energy projects cover more than 719 MW of solar, wind and hydroelectric capacity.

Once completed, the projects are expected to generate enough electricity to power more than 230,000 New York homes annually.

Several have already begun construction, and all are expected to be operational by 2030.

The renewable awards include:

• Flint Mine Solar, Greene County
• Hecate Energy Greene 1 and Hecate Energy Greene 2, Greene County
• Spier Falls, Saratoga County
• High Dam Hydroelectric Facility, Oswego County
• Wethersfield Windpark, Wyoming County
• Chateaugay Windpark, Franklin County
• Diamond Island Hydroelectric Facility, Jefferson County
• Ellenburg Windpark, Clinton and Franklin counties
• Greens Corners Solar Park, Jefferson County
• Rich Road Solar Energy Center, St. Lawrence County
• Theresa Hydroelectric Project, Jefferson County
• Canisteo Wind Energy Center, Steuben County

More batteries are coming

The awards are part of New York’s broader effort to expand utility-scale energy storage alongside renewable generation.

Longer-duration batteries can charge when electricity is available and discharge it later, allowing grid operators to shift energy across hours of the day and adding flexibility as renewable generation grows.

NYSERDA plans to issue another RFP by year-end as it works toward procuring 3 GW of bulk energy storage through three solicitations.

The combined storage and renewable projects are also expected to provide more than $127 million in economic benefits to disadvantaged communities, according to NYSERDA.

“So often the mindset was, ‘Well, we need to operate these facilities lean and mean, minimal staff.’ Well, that meant no chemistry staff,” said Buecker, senior technical consultant with SAMCO Technologies. “You had operators that didn’t have any chemistry training, trying to deal with, a lot of times, rather pristine water sources.”

Those pristine sources are harder to count on now. Some plants are turning to reclaimed municipal wastewater, facing tighter discharge limits and pushing treatment systems toward higher recovery. The operators are still there, but the water has changed.

“Now you’ve got a much more complex situation,” Buecker said.

That complexity arrives at a demanding moment for the generating fleet. Load growth, driven largely by data centers, is pulling aging units back into service and pushing new gas capacity online quickly. Other units are cycling hard or sitting idle for long stretches as the dispatch stack shifts. Each of those operating modes stresses the water-steam cycle, and the margin for error is shrinking.

“Even one chemistry failure can take a unit down sometimes for weeks, months. If it’s a turbine problem, perhaps a year, and that’s enormously costly,” Buecker said. Those failures, he added, “most often are very preventable” when plants are proactive rather than reactive.

On top of that, the people who know how to prevent them are leaving.

“A lot of the baby boomers are retiring, and they’re taking tremendous expertise with them,” Buecker said. “The new people coming in are on a huge learning curve.”

That is the backdrop for the 44th Electric Utility & Cogeneration Chemistry Workshop (EUC²W), whose agenda is now live. The workshop is co-located with POWERGEN 2027 in Salt Lake City and runs from 1 to 4:30 p.m. on Tuesday, Jan. 19, and Wednesday, Jan. 20. It is included for POWERGEN all-access badge holders, and exhibition badge holders can add it for an additional fee.

Two afternoons, grounded in the field

Tuesday’s sessions work through the core of cycle chemistry. The afternoon opens with layup strategy for combined cycle units facing extended outages, covering how to protect equipment that may sit idle for a year or more before being called on hard. Speakers then turn to online sodium monitoring, one of the most sensitive early warnings of contamination in the water-steam cycle. Field results from condenser and heat exchanger nanocoating applications tie chemistry-adjacent work directly to megawatt output.

The day closes with cooling water treatment fundamentals and a session on reverse osmosis pretreatment, a critical step in protecting the makeup water systems that many combined cycle plants depend on.

Wednesday turns to water management and back-end challenges. Presenters share deep well injection case studies from Tampa Electric’s Big Bend and Polk stations, where the approach supports both ELG compliance and water reuse. A session on invasive golden mussels in California hydropower cooling systems explores a chemical-free, UV-based alternative to copper treatment.

An international utility case study from Liberia’s Bushrod Island Thermal Plant presents a monitoring framework that links cooling-water chemistry to generator availability. The afternoon wraps with field data on controlling lime and fly ash recycle scaling in spray dryer absorbers at coal plants.

“We’ve been putting out top notch information for over four decades, but it started off as a small conference basically for Midwest utilities,” Buecker said.

Co-location with POWERGEN puts that expertise in front of owner-operators, engineers and managers who may never have attended a chemistry event. Buecker said they don’t need to arrive as specialists.

“They don’t necessarily have to go back to their plants and become the chemistry expert, but they will be talking with people who have that knowledge and could potentially help them in the future,” he said.

His pitch to anyone on the fence was simple: “A lot of nice people that are very eager to help.”

See the EUC²W agenda here

Development could begin as early as 2027, with initial operating capability targeted by — or ahead of — 2030. Formal lease agreements are still in the early stages.

The Army isn’t buying the power plants

Here’s where the deal gets interesting for the power industry.

The Army isn’t paying for construction. The projects will use an Enhanced Use Lease, or EUL, under federal law.

The arrangement allows the Army to lease underutilized land to private companies while retaining ownership of the property. Developers take on the heavy lifting and the heavy capital costs, including financing, design, construction, operation, security and eventual decommissioning.

In exchange, the developers pay rent for the land.

The Army said it prefers that compensation be in the form of “in-kind” improvements, meaning developers could fund infrastructure upgrades at the host installation rather than simply writing a check. It also requires a decommissioning bond to ensure money is available to restore the property when a lease ends.

Power generation meets grid resilience

The strategy isn’t just about keeping the lights on inside the fence line.

The Army’s June solicitation called for commercial generation projects that can serve the grid under normal conditions while providing islanded power to installations during extended outages. In other words: Keep the electrons flowing, even when the grid doesn’t.

That creates an unusual business model: Build generation on military land, sell power into the grid, while maintaining the capability to serve a critical customer when the grid has a bad day. The Army gets access to private capital and infrastructure expertise, the installations get another layer of energy security, and the grid gets potentially more generation and storage.

The solicitation identified seven potential installations and allowed technologies including solar, natural gas, geothermal and nuclear, with nuclear proposals capped at 500 MW per unit. The Army did not include Fort Drum, New York, in its Sept. 18 announcement.

The winners

• Ameresco said its projects at Aberdeen Proving Ground and Picatinny Arsenal in New Jersey could include traditional firm power generation and nuclear technology.

For Ameresco, this includes proposed phased power generation campuses, potentially including firm natural gas and advanced nuclear generation at Aberdeen Proving Ground, and microreactor and small modular reactor technologies at Picatinny Arsenal, subject to final agreements and required approvals.

The company anticipates integrating commercial power generation to add market-based grid capacity while supporting resilient on-site capabilities for Army installations during qualifying grid outages.

“Ameresco is honored to be among the companies selected to support the U.S. Army’s Strategic Capital Initiatives and advance energy resilience across critical military installations,” said Nicole Bulgarino, Ameresco co-president, in a media release. “At Aberdeen Proving Ground in Maryland and Picatinny Arsenal in New Jersey, we look forward to deploying resilient, on-site energy infrastructure that strengthens mission readiness and enhances energy security.”

• Indelible-Bloom is partnering with Bloom Energy on projects at Fort Detrick in Maryland, Letterkenny Army Depot in Pennsylvania, and West Point in New York.

Silicon Valley-based Bloom Energy is known for its fuel cell systems that provide electricity for Fortune 500 customers worldwide, including data centers, semiconductor manufacturing, large utilities, and other commercial and industrial sectors, as well as mission-critical organizations in local communities.

The Army’s statement specifically said the partnership draws on Bloom Energy’s experience supplying reliable power to critical facilities such as hospitals, universities and research laboratories.

This is strategically important because military installations have unusually strong requirements for islanding, resilience and dependable onsite generation. Bloom’s fuel-cell systems are designed around exactly that use case.

• Frontier Power USA said it’ll use the Tobyhanna Army Depot in Pennsylvania for a project that combines American-made battery energy storage with power generation.

Project stakeholders said the partnership reflects Frontier Power USA’s approach to developing integrated energy infrastructure solutions that combine power generation, energy storage, and related technologies to meet critical customers’ needs.

By bringing multiple technologies together into a single resilient platform, FPUSA said it can deliver reliable, secure, and domestically sourced energy solutions that strengthen operational readiness and support broader national energy priorities.

The company also said the approach reflects a broader model of cooperation between the Army and private industry: leasing non-excess, underutilized land to American companies that finance, build, own, and operate the assets at no capital cost to the government. As power demand rises across the United States, projects like this add market-based generation and storage capacity to the grid while giving host installations ready, on-site capability.

“FPUSA is honored to support the U.S. Army and its mission,” said Frontier Power USA CEO Jay Bellows, in a statement. “We are proud to bring private capital and American innovation to Army installations, combining American-made battery energy storage with U.S.-compliant power generation to deliver resilient, mission-ready power at scale.”

Source: Tobyhanna Army Depot.

Who’s building what?

The Army limited eligibility to companies organized under U.S. law, with majority domestic ownership and control and a U.S. place of business.

Infrastructure improvements provided to the Army also must comply with Buy American Act and Davis-Bacon requirements.

These projects still have plenty of runway before they become power plants. Construction cannot begin until required environmental and regulatory reviews are completed, including reviews under the National Environmental Policy Act and applicable clean-air and clean-water requirements, along with federal, state and local permitting.

The announcement comes just over four months after Fervo’s May 2026 initial public offering. Following the successful deployment of Fervo’s EGS technology at Project Red, which has been supplying electricity to the grid since 2023, first power at Cape Station represents a “significant scale-up” of the technology in a greenfield setting, the company said.  

Fervo uses horizontal drilling techniques adapted from the oil and gas industry, allowing multiple wells to be drilled from a single pad. The project is an enhanced geothermal system that produces energy by injecting water into hot subsurface rock formations and then extracting the heated water to generate electricity, rather than depending on naturally occurring underground hot water like traditional geothermal systems. If fully developed, the project will cover approximately 631 acres, including 148 acres on public lands.

“This is a gamechanger for the geothermal industry. It establishes EGS as the defining new power generation technology of our time and we believe it shows that the commercial and technical maturity of EGS is ready to meet the urgent need for reliable, clean power,” said Tim Latimer, CEO and Co-Founder of Fervo Energy. “I could not be more proud of the years of hard work from Fervo’s employees, investors, suppliers, customers, and partners, which brought us to this moment. We are just getting started.” 

Cape Station Phase I is an approximately 100 MW installation comprising three 33-MW GeoBlocks, the first of which has achieved first power and is expected to reach its contractual commercial operations date (COD) by October 1, 2026. Fervo will continue ramping up the first GeoBlock as it brings the full well system online while commissioning the remaining two GeoBlocks, which are expected to reach contractual COD by January 1, 2027. The next phase, an additional 400 MW, is already under construction, with an expected COD in 2028. Fully contracted offtake at Cape Station sits at approximately 900 MW, enough to power the equivalent of nearly 1 million U.S. homes annually. 

Utah is home to immense geothermal potential. Researchers estimate that the southwest portion of the state contains more than 10 GW of high-quality geothermal reserves. Additionally, Cape Station will benefit from the Department of Energy’s Frontier Observatory for Research in Geothermal Energy (FORGE). Over the last several years, FORGE has completed research that has advanced geothermal development in the region.

“Cape Station works because we treated the subsurface like an engineering challenge,” said Jack Norbeck, Chief Technology Officer and Co-Founder of Fervo Energy. “Years of drilling, completion design, subsurface modeling, and flow testing led to this moment, and this is the validation that matters most. First Power is proof the science works.” 

Earlier this month, Fervo Energy announced a record-breaking 396-megawatt (MW) power purchase agreement (PPA) with Google to enable the continued development of the Cape Station EGS GeoCluster. Under the agreement, Google will purchase carbon-free energy designed to serve as a “foundational building block” for a potential data center in Utah. As part of the PPA, Fervo will offer Google an option to expand its offtake by approximately 600 MW, for a total of nearly 1 gigawatt (GW) by June 2030. Final data center plans remain subject to a variety of factors including engineering feasibility, state and local approvals, and commercial conditions, the companies said.

The Fervo-Google partnership began with Project Red, Fervo’s commercial pilot project in Nevada that came online in 2023. That pilot delivers power to the local grid, including Google’s data centers in the state. Following Project Red, Fervo signed a 115 MW PPA with Google and NV Energy in June 2024 that helped pioneer the Clean Transition Tariff, which Google argues enabled it to bring more geothermal energy onto the Nevada grid while insulating customers from the project’s costs.

Additional PPAs at Cape Station include Shell Energy North America, Southern California Edison, and an expanded deal with Clean Power Alliance that adds 18 MW of carbon-free geothermal energy to their existing PPA with Fervo.