Under the agreement, B&W has received limited notice to proceed (LNTP) for the project. Notice to proceed for the full contract is expected in the fourth quarter of 2024, the company said.

B&W will convert the currently unspecified plant’s two coal-fired boilers – totaling more than 1,000 MW – to use natural gas fuel. B&W’s full scope would include the design and installation of new burners, air systems, fans and other equipment necessary to implement the fuel switch.

“Utilities across North America and throughout the world are evaluating options to extend the life of their thermal power generating assets,” said Chris Riker, Senior Vice President, B&W Thermal. “Replacing coal or oil with cleaner-burning fuels like natural gas, biofuels or hydrogen is often a cost-effective way for plant owners to lower emissions while maintaining reliable power generation capacity.”

Babcock & Wilcox said it will begin engineering and design work under the LNTP immediately with support from its affiliate, FPS. Babcock & Wilcox Construction will perform the construction portion of the project under an intercompany agreement when a full notice to proceed is received.  

Consumers had sought to amend its long-running agreement with National Energy of Lincoln in northeast Michigan, proposing early termination of a previous amendment that had extended the PPA
for the plant’s 18 MW of electricity to 2027. The latest proposed amendment would have resulted in closure of the plant on May 31, 2024.

In June 2023 Consumers applied for a similar early termination of a PPA with Cogeneration Michigan Associates Limited Partnership’s Cadillac Plant. The new exit date would also be May 31, 2024, from July 2028.

In both cases, Consumers Energy had argued the early terminations provide several benefits, such as “an
expected reduction in cost, which will be passed on to PSCR [power supply cost recovery] customers…”.

But commissioners raised concerns about these claimed potential savings since Consumers “would turn to volatile electricity markets to replace some of the energy output and capacity lost with the shutdown of the plants.”

“The Commission found relying on unpredictable markets for replacement supply outside of a comprehensive Integrated Resource Planning process in this manner entailed an unacceptable level of risk,” MPSC said in a statement.

Consumers had proposed replacing the capacity from the Lincoln biomass plant with a 33.6 MW solar facility and the Cadillac Plant with a 67 MW solar facility. However, the utility had itself noted in testimony that given their non-dispatchable profiles, the two solar facilities would not be able to replace all the electric capacity from the biomass plants without supplemental electricity purchases.

Commissioners said that was concerning given the Midwest Independent System Operator (MISO) has warned of tightening supplies.

Regulators greenlight solar and storage projects

The Commission also approved several renewable energy and storage projects called for in the long-range integrated resource plans of two Michigan electric utilities.

Commissioners approved DTE Energy’s application to construct a 220 MW/800 MWh lithium-ion battery storage facility at the site of the former Trenton Channel coal-fired plant in Wayne County. The battery storage project is expected to cost $460 million.

The application to build the battery facility was approved the same day DTE demolished two smokestacks at Trenton Channel.

Retired in 2022, the plant was originally built to address the needs of an expanding economy post World War I and was the fourth major power plant Detroit Edison put into operation during the 1920’s. The coal-fired plant began operating in 1924.

The plant had six turbine generators with 13 coal-fired boilers. The sixth and last turbine generator arrived by 1929. At that time, Trenton Channel was the largest project Detroit Edison had undertaken. At one point, with the expansion of the plant in 1950, the facility generated 1,060 MW of energy.

At its retirement, Trenton Channel generated 535 MW.

Beyond the actions related to the Trenton Channel site, MPSC on Friday approved Consumers Energy’s application for approval of a PPA between the utility and Freshwater Solar Project, a 300 MW solar facility in Montcalm County, with a total lifetime cost of $715.7 million.

Siemens Energy North America President Rich Voorberg was optimistic and upbeat as he sat down to speak with us at POWERGEN International back in January.

Voorberg has attended POWERGEN for nearly 30 years but still buzzes about walking the show floor or learning the latest technologies.

“It’s about working together,” said Voorberg, “and it’s about learning from each other.”

This kind of collaboration is crucial as the power sector faces the pressures of net-zero carbon goals and unprecedented load growth.

Big changes are happening already. A growing number of utilities and power generation owners have committed to cut carbon emissions 80% by 2030.

The U.S. bulk power system is becoming more renewables-heavy, thanks largely to coal-fired plant retirements and huge growth from utility-scale solar. The U.S. Energy Information Administration (EIA) is projecting that renewables’ share of electricity will increase three percent in just one year, from 22% in 2023 to nearly 25% in 2024.

Demand for power is also exploding. Many utilities are increasing their load forecasts, in no small part from new manufacturing and the rise of energy-intensive data centers using AI. Duke Energy Carolinas, for example, recently told regulators its current projected peak demand growth by 2030 is approximately eight times what it projected in the company’s 2022 Carbon Plan.

Voorberg said an all of the above approach is needed in the face of these challenges. This includes more solar, wind and battery installations, but also advancements in clean firm power technologies like hydrogen and small modular reactors, he said.

Conventional power sources will still be needed “for the foreseeable future,” Voorberg said.

The gas turbine remains the workhorse of power generation, and previous efforts have been aimed at extending time between outages and the life of equipment. Now, the focus turns to burning cleaner fuels like hydrogen, which is no longer simply a hypothetical situation.

Voorberg pointed to a hydrogen-blending test at Constellation’ Hillabee Generating Station, a 753 MW natural gas combined-cycle (NGCC) in central Alabama. Constellation blended 38 percent hydrogen by volume, with the demonstration occurring on a Siemens Energy SGT6-6000G gas turbine.

Researchers said only “minor modifications” were required for the blending test. Constellation said it added an inlet for the hydrogen to be blended, a control valve and calibrated instrument to measure fuel flow.

But Voorberg acknowledged that long-term trial runs are needed to see how parts on the backend are truly affected.

“We’ve theoretically got it,” he said. “But we’ve got to get these machines running and prove it out to ourselves over a longer and longer period of time.”

But at the end of the day, it’s about the business case.

Tax credits and other incentives have been established to support scaling up the production, transportation, storage and end-use of clean hydrogen. Siemens Energy itself opened a gigawatt-scale electrolyzer production facility in Berlin last year.

Establishing a functioning hydrogen economy in the U.S. is not without its headwinds. It’s a microcosm of the greater challenge of getting to net-zero by 2050 and the reality that we might not yet have all the tools commercially available to get there.

That’s why Siemens Energy spends more than $1 billion annually in R&D, aimed at bringing newer, cleaner innovations to market.

“It’s going to be difficult, and it’s going to really push out our engineers,” said Voorberg. “We believe only half of the technology exists today in a commercial mandate to get to 2050.”

All the more reason it takes a village to reach net-zero.

This is the key message of a new report, Hydropower Investment Landscape, developed by the National Renewable Energy Laboratory with support from Deloitte.

Globally, hydropower is the third largest source of electricity after coal and natural gas. As the world continues to transition away from fossil fuels, low-carbon sources of firm power will be increasingly critical to maintain the electric grid’s reliability. Hydropower already serves as a force multiplier for other renewable energy sources, and the value of this reliability and flexibility will continue to increase.

With the Bipartisan Infrastructure Law and Inflation Reduction Act offering financial support for clean energy projects, new hydropower and pumped storage projects could offer increasingly attractive investment opportunities.

The new report provides a comprehensive analysis of the risks and opportunities for investing in small- to medium-sized hydropower and pumped storage projects. Key findings from the study, which was funded by the U.S. Department of Energy’s (DOE’s) Water Power Technologies Office (WPTO), include:

Medium-sized projects offer significant opportunities for low-impact hydropower development. The medium-sized project pipeline includes projects that would constitute a total capacity of more than 1 GW and involves capacity additions, non-powered dam retrofits, hydropower generation in conduits, pumped storage, new stream-reach development and hybrid projects that combine multiple renewable technologies.

New technology innovations and the variety of sites at which hydropower could be developed present potential opportunities for future investment. Top areas of interest include modular conduit hydropower, non-powered dam resources, hybrid plant confirmation and closed-loop pumped storage innovation.

In the past decade, developers have begun designing and deploying small modular conduit systems, which can be manufactured offsite and assembled onsite. This approach can decrease construction costs, reduce project timelines and increase flexibility to expand the size of a hydropower system in the future. One example highlighted in the report of a company pursuing modular conduit hydropower is Emrgy, which raised several million dollars in private investment.

Because about 97% of U.S. dams do not have power-generating infrastructure, non-powered dams represent an attractive development opportunity with a potential capacity of 2 GW or more within the medium-sized range.

Using hydropower in a hybrid configuration with other renewables and battery storage can unlock new revenue streams by providing power during peak demand or ancillary services, such as the ability to adjust quickly to ensure grid reliability.

Closed-loop pumped storage systems feature two reservoirs that are not connected to a naturally flowing water feature like a river. These projects, which can offer siting flexibility, account for the majority of pumped storage projects in the pipeline. These projects would be the first closed-loop facilities in the U.S.

Investors surveyed for this study generally expressed the greatest level of interest in supporting capacity additions at existing facilities. With a connection to the grid already established, these facilities offer critical opportunities to increase clean energy production.

Overall, innovations in hydropower are driving the industry toward smaller, more modular and flexible solutions that can be more easily scaled and replicated.

Of course, there are challenges associated with hydropower projects, which are generally well known in the industry. Risks like financing for early-stage development, long permitting and licensing timelines, supply chain constraints, and more are important considerations but can also be addressed. The report includes several suggestions for addressing challenges in the industry to help increase investment. They are:

• Provide financing, funding and support for early-stage development
• Support improved market-based incentive signals for hydropower and pumped storage
• Support transparent and efficient permitting and licensing processes
• Support new, innovative research on reducing deployment time and costs
• Clarify new legislation and regulations and conduct outreach with developers and industry
• Increase awareness of new opportunities in hydropower and pumped storage

Published on Hydro Review.

A handful of Democratic legislators are opposed to a plan to build a natural gas power plant in Chesterfield, a proposal that Virginia’s largest utility said will ensure electric grid reliability during expected surges in power demands over the next 15 to 25 years.

Seven delegates and two senators representing the greater Richmond area signed a statement Wednesday issued by the office of Sen. Ghazala Hashmi, D-Richmond. The project proposal “runs counter to the measures the Commonwealth has taken recently to lower carbon emissions and to diversify energy production and storage,” it reads.

In 2020, the Democratic-majority General Assembly passed the Virginia Clean Economy Act, a policy that requires the state’s electric grid to decarbonize by 2045 by transitioning to renewable energy sources and retiring fossil fuel generation sources. 

That same year, Virginia passed the Environmental Justice Act, which requires the state to promote “the fair treatment and meaningful involvement of every person, regardless of race, color, national origin, income, faith, or disability” when developing, implementing or enacting environmental laws, regulations and policies.

The legislators’ opposition to the Chesterfield plant cites projections from Dominion’s long-term planning documents that say the utility’s carbon emissions would increase. The utility produced 21.8 million metric tons in 2021 and estimated it would emit 36 to 43.8 million metric tons by 2048. The proposed 1,000 megawatt Chesterfield plant, which would be sited next to the utility’s now-closed coal-fired plant, is included in Dominion’s estimates. 

About 20,000 people live within a three-mile radius of the proposed plant; 36% of them are low-income, and about 48% are people of color, according to information from the U.S. Environmental Protection Agency included in the lawmakers’ statement.

The opposing legislators also question the cost of the project, which was $600 million in a 2019 iteration of the proposal, but hasn’t been disclosed in the current plan. Dominion’s customers would bear those costs.

“With the VCEA stipulation that most polluting plants be shut down by 2045, the construction of a new and costly power plant makes little fiscal sense,” the statement reads. 

Dominion proposed the natural gas plant last summer as part of its non-binding, long-term planning document, called an Integrated Resource Plan, as a way to meet an expected increase in electric grid load growth, largely due to data center development in the state, more electric vehicle use and efforts to boost homes’ energy efficiency. This type of facility is commonly referred to as a “peaker plant,” because of its intended use during periods of peak demand for electricity.

A challenge of relying solely on renewable technologies like wind and solar during the energy transition is that they’re limited to producing electricity on an intermittent basis, when the sun is shining and the wind is blowing. Federal Energy Regulatory Commission member Mark Christie, a former member of the State Corporation Commission that regulates Dominion, echoed that concern in remarks last May.

When it comes to grid reliability,, “the problem generally is not the addition of intermittent resources — primarily wind and solar — but the far too rapid subtraction of dispatchable resources, especially coal and gas.”

About 95% of the energy generation sources in Dominion’s IRP is from carbon-free sources, including 2,600 megawatts from offshore wind, about 800 megawatts a year from solar and long-duration energy storage devices, which can provide power for over 100 hours instead of the traditional four-hour period, and small modular nuclear reactors, though they are largely unproven at the commercial level. The remaining 5% of new generation sources comes from the Chesterfield plant.

“Renewables alone cannot keep our customers’ power on 24/7, especially with power demand nearly doubling over the coming decades,” said Dominion spokesman Jeremy Slayton. “That is why we need an all-of-the-above, balanced approach that advances the clean-energy transition, but without sacrificing on reliability.” 

Still, community members have joined lawmakers in raising concerns about the planned power plant and some are calling for local action against it.

“Given the significant potential for harm to the community, we urge the Chesterfield County Board of Supervisors to deny Dominion Energy’s zoning application to move forward with the gas plant,” said Aliya Farooq, a founding member of the group Friends of Chesterfield County that formed last year to oppose the proposed plant.

The project still needs approvals from the Department of Environmental Quality for its air permit, Chesterfield County for its land use permit and the SCC for its Certificate of Public Convenience and Necessity. If all of these are acquired, construction of the plant would begin in 2026 and it’s slated to become operational by the end of 2028.

Virginia Mercury is part of States Newsroom, a nonprofit news network supported by grants and a coalition of donors as a 501c(3) public charity. Virginia Mercury maintains editorial independence.

The solar and battery storage system will help match the electricity consumed by Google’s forthcoming data center campus in Mesa, Arizona. Energy not needed by the data center will be used to meet other SRP customer needs.

Also supporting Google is the newly developed Storey Energy Center, an 88-MW solar and battery storage system, located in Coolidge, Arizona. Both facilities are operated by subsidiaries of NextEra Energy Resources. SRP and NextEra Energy Resources’ under-development wind facility, Babbitt Ranch Energy Center, will also support Google. This is a 161-MW wind project, on Babbitt Ranches property in Coconino County, north of Flagstaff.

Google is pursuing net-zero emissions across its operations and value chain by 2030, supported by a goal to run its data centers and office campuses on 24/7 carbon-free energy. The Sonoran, Storey, and Babbitt Ranch projects contribute to these commitments by supporting the energy needs of Google’s future data center in Mesa, which the company announced in 2023 with plans to use air-cooled technology.

“We’re aiming for every Google campus to operate on clean electricity every hour of every day by 2030, including in Arizona where we are excited to put down roots with our first data center in the state currently under construction,” said Amanda Peterson Corio, Global Head of Data Center Energy, Google. “The collaboration with Salt River Project and NextEra is accelerating decarbonization in Arizona and our own carbon-free journey in the region.”          

Through its Integrated System Plan, SRP found it will need to at least double the number of power resources on its power system in the next 10 years as it completes the planned retirement of 2,600 MW of coal resources, and amid growing energy demand.

“These renewable energy centers will generate low-cost, homegrown energy and provide millions of dollars in additional revenue to both Maricopa and Pinal counties over the life of the projects,” said Anthony Pedroni, Vice President of Renewables and Storage Development at NextEra Energy Resources. “We are pleased to work with SRP and Google to bring online Arizona’s newest renewable energy centers.”  

Originally published in Renewable Energy World.

Clean hydrogen is seen as essential for decarbonizing difficult-to-abate sectors of the U.S. economy, such as heavy manufacturing, chemical production and transportation. In power generation, hydrogen can be combusted in natural gas-fired engines or turbines.

These projects, funded by the Bipartisan Infrastructure Law, are intended to help advance electrolysis technologies and improve manufacturing and recycling capabilities for clean hydrogen systems and components. The projects are expected to enable U.S. manufacturing capacity to produce 14 GW of fuel cells per year, and 10 GW of electrolyzers per year – enough to produce an additional 1.3 million tons of clean hydrogen per year.

Managed by DOE’s Hydrogen and Fuel Cell Technologies Office (HFTO), these projects represent the first phase of implementation of two provisions of the Bipartisan Infrastructure Law, which authorizes $1 billion for research, development, demonstration, and deployment (RDD&D) activities to reduce the cost of clean hydrogen produced via electrolysis and $500 million for research, development, and demonstration (RD&D) of improved processes and technologies for manufacturing and recycling clean hydrogen systems and materials.  

The selected projects will address clean hydrogen technologies in the following areas:    

• Low-cost, high-throughput electrolyzer manufacturing (8 projects, $316 million): Selected projects will conduct RD&D in the effort to enable greater economies of scale through manufacturing improvements, including automated manufacturing processes; design for processability and scale-up; quality control methods to maintain electrolyzer performance and durability; reduced critical mineral loadings; and design for end-of-life recovery and recyclability.   
• Electrolyzer component and supply chain development (10 projects, $81 million): Selected projects will support the U.S. supply chain manufacturing and development needs of key electrolyzer components, including catalysts, membranes, and porous transport layers.    
• Advanced technology and component development (18 projects, $72 million): Selected projects will demonstrate novel materials, components, and designs for electrolyzers that meet performance, lifetime, and cost metrics to enable cost reductions and mitigate supply chain risks.
• Advanced manufacturing of fuel cell assemblies and stacks (5 projects, $150 million): Selected projects will support high-throughput manufacturing of low-cost fuel cells in the United States by conducting RD&D meant to enable diverse fuel cell manufacturer and supplier teams to flexibly address their scale-up challenges and achieve economies of scale.  
• Fuel cell supply chain development (10 projects, $82 million): Selected projects will conduct R&D to address deficiencies in the domestic supply chain for fuel cell materials and components and develop advanced technologies that could reduce or eliminate the need for per- and polyfluoroalkyl substances (PFAS), often referred to as “forever chemicals.”  
• Recovery and recycling consortium (1 project, $50 million): This funding establishes a consortium of industry, academia, and national labs to develop innovative and practical approaches to enable the recovery, recycling, and reuse of clean hydrogen materials and components. It will aim to establish a blueprint across the industry for recycling, securing long-term supply chain security and environmental sustainability.   

The allocation is provided as a non-federal match for Energy Northwest’s participation in the U.S. Department of Energy’s (DOE) loan programs office application. The utility wants to develop “up to 12 Xe-100 advanced small modular reactors” capable of generating up to 960 MW of electricity adjacent to the large nuclear-powered Columbia Generating Station in Richland.

The capital allocation received bipartisan support but still needs to be signed by Washington Gov. Jay Inslee.

The $25 million allocation represents the first significant investment in nuclear energy generation by the Washington State Legislature in over a decade.

“The people of the 8th District are energy-savvy consumers who understand the importance of clean nuclear energy,” said Rep. Stephanie Barnard (R – Pasco). “The development of advanced SMRs has been a top priority goal in the Tri-Cities for years, and it’s a top priority for me.”

Energy Northwest said it expects to bring the first Xe-100 module online by 2030.

X-energy’s Xe-100 SMR is a high-temperature gas-cooled reactor. The Maryland-based company said its SMR can address a broad range of uses, including applications that currently rely on fossil fuels to produce steam and heat for processes like manufacturing, petroleum refining and hydrogen production.

Energy Northwest and X-energy have discussed plans for an Xe-100 reactor facility in central Washington since 2020. At one time X-energy’s goal was to have an operational unit by 2028, starting with a 320 MW four-unit Xe-100 power plant in the state.

SCRANTON, Pa. (AP) — Pennsylvania Gov. Josh Shapiro unveiled a plan Wednesday to fight climate change, saying he will back legislation to make power plant owners in the nation’s third-biggest energy-producing state pay for their greenhouse gas emissions and require utilities to buy more electricity from renewable sources.

Such legislation would make Pennsylvania the first major fossil fuel-producing state to adopt a carbon-pricing program. But it is drawing fierce opposition from business interests wary of paying more for power and will face long odds in a Legislature protective of the state’s natural gas industry.

Shapiro’s proposal comes as environmentalists are pressuring him to do more to fight climate change in the nation’s No. 2 gas-producing state and as the state’s highest court considers a challenge to his predecessor’s plan to adopt a carbon-pricing program. It also comes after many of the state’s biggest power polluters, coal-fired plants, have shut down or converted to gas.

At a news conference in Scranton, nicknamed the “Electric City,” Shapiro said his plan will make Pennsylvania competitive in a clean energy economy, improve electricity reliability, cut greenhouse gas emissions and lower electricity bills.

It is long past time for lawmakers to act, he said.

“If they choose to do nothing, they’re choosing to be less competitive in an environment that demands us to bring excellence to the table every single day,” Shapiro said. “They’re choosing to fall behind if they choose to do nothing.”

Under Shapiro’s plan, Pennsylvania would create its own standalone carbon-pricing program, with most of the money paid by polluting power plants — 70% — going to lower consumer electric bills. No one will pay more for electricity and many will pay less, Shapiro said.

Meanwhile, utilities would be required to buy 50% of their electricity from sources that are mostly carbon-free by 2035, up from the state’s current requirement of 18%.

Currently, about 60% of the state’s electricity comes from natural gas-fired power plants, and the 50% renewables requirement could hurt demand for electricity from those plants. Another third of Pennsylvania’s electricity is from nuclear plants — which are not included in the 50% renewables requirement — and the rest from coal and renewables.

Republicans who control the state Senate have pushed to open greater opportunities for natural gas production in Pennsylvania, and have warned that carbon-pricing could raise electricity bills, fray the electricity grid, hurt in-state energy producers and drive new power generation to other states.

“Families are feeling the strain of inflation and increased household expenses, which must be a chief concern when implementing any changes to energy policy,” Senate Majority Leader Joe Pittman, R-Indiana, said in a statement Wednesday.

Shapiro’s administration did not provide many details of his strategy Wednesday, including how much it would reduce greenhouse gases, how much money power plants would pay or how it would affect the average household electric bill.

Patrick Cicero, Pennsylvania’s consumer advocate, said the amount of savings on electric bills will depend on usage — large industrial customers would see more and low-income households would get “significant reductions” because of a planned expansion of the state’s energy-assistance program.

For the average household, “it’s not going to be much,” Cicero said, “but it’s not costing households more. That’s a win-win.”

Neighboring Maryland, New Jersey and New York have set requirements to draw 50% or more of their electricity from renewables by 2030, prompting warnings that Pennsylvania risks falling behind in a clean energy economy.

Robert Bair, president of the Pennsylvania State Building and Construction Trades, whose members work on power plants, refineries and pipelines, said Pennsylvania energy policy must protect workers in the coal and gas industries. But he also said Pennsylvania will lose clean energy jobs to other states if it does nothing.

Heavy energy users and coal-industry businesses slammed Shapiro’s “energy tax” as posing a damaging blow to industries and a fatal blow to the state’s few remaining coal-fired power plants.

The Marcellus Shale Coalition, which represents Pennsylvania’s enormous natural gas industry, was more circumspect. The most pressing challenge is ensuring the electric grid is stable and reliable, said Dave Callahan, the group’s president.

Despite the lack of details, Shapiro’s plan drew statements of support from renewable energy trade associations and environmental advocates.

“Even what the governor has proposed is not enough to meet the needs of addressing the climate crisis, but it’s a huge step forward from where Pennsylvania is now,” said Alex Bomstein, executive director of the Clean Air Council.

Meanwhile, environmental advocates worry about abandoning the plan produced by Shapiro’s predecessor, former Gov. Tom Wolf.

For the time being, a state court has blocked Wolf’s regulation that authorizes Pennsylvania to join the multistate Regional Greenhouse Gas Initiative, which imposes a price and declining cap on carbon dioxide emissions from power plants.

As a candidate for governor, Shapiro had distanced himself from Wolf’s plan — although critics said Shapiro’s plan is similar — and Shapiro wouldn’t say Wednesday whether he’d enforce Pennsylvania’s participation in the regional consortium should the courts uphold it and the Legislature do nothing.

“I’m focused on getting these things passed,” Shapiro said.

The request includes $694.2 million in research and development activities meant to help advance reactor and fuel technologies, address gaps in the domestic nuclear fuel supply chain and utilize the latest artificial intelligence and machine learning tools to optimize performance.

The DOE broke down five areas where the requested budget would be spent:

1. Access to HALEU

NE is requesting $188 million to secure a near-term supply of high-assay low-enriched uranium (HALEU) for DOE-supported research and demonstration projects. 

These efforts include the recovery and downblending of government-owned legacy uranium and ramping up enrichment operations in Piketon, Ohio to help make limited quantities available.  

The funding is meant to complement the DOE’s longer-term strategy to expand its domestic enrichment capacity through purchase agreements with industry partners to help spur demand for additional HALEU production.  

The recently passed FY24 spending bill directed $2.72 billion to further build out a low-enriched uranium and advanced nuclear fuel supply chain.

2. Developing new reactor technologies

The FY25 request includes $142.5 million to support the continued execution of five advanced reactor projects supported through DOE’s Advanced Reactor Demonstration Program.  

NE is also requesting $56 million to establish new testing facilities at the national labs, including $12 million to finish the construction of the NRIC DOME at Idaho National Laboratory.  

DOME will be the world’s first microreactor test bed and could start testing designs as soon as 2026.

The funding also includes $16.5 million for DOE’s MARVEL microreactor testing platform to complete the fabrication of its fuel and key components.  

NE is also requesting more than $18 million to initiate construction of the LOTUS testbed that will be used to test new technologies to generate data required for design and licensing.  

3. Boosting university R&D

NE is requesting $143 million to support emerging technologies developed by U.S. universities, colleges, and small businesses. 

The funding will also be used for university infrastructure improvements and fuel services, along with workforce development activities such as scholarship and fellowship opportunities.  

NE is getting closer to eclipsing the $1 billion funding mark with more than $990 million awarded to colleges and universities across the country since 2009.  

4. Additive manufacturing and AI

The FY25 request also includes $32 million to advance the use of digital tools and manufacturing methods to strengthen nuclear supply chains and help optimize reactor performance.

This funding includes $17 million to support the qualification of additively manufactured materials for use in nuclear reactors and $9 million to develop and demonstrate sensors, instrumentation, and control systems, including potential ways to apply artificial intelligence and machine learning tools to advanced reactor designs and operations.

DOE says the two technologies combined could drastically reduce the time it takes to test, qualify, and deploy new reactor components and fuels. 

The remaining $6 million will address high-priority supply chain needs for the near-term deployment of advanced reactors. 

5. Deploying U.S. reactors internationally

Finally, the FY25 request includes $8 million to support several U.S. international projects, including providing workforce development, training, and technical expertise to new and emerging nuclear energy countries in Africa, Asia, and Central and Eastern Europe.  

The funding will be used to establish regional clean energy training centers in key markets to provide capacity-building and professional development opportunities in regions looking to develop or grow their civil nuclear programs. 

The full budget request can be read here.