Under the terms of the agreement, Dominion shareholders will receive 0.8138 shares of NextEra Energy for each share of Dominion they hold. Upon closing, NextEra shareholders will retain approximately 74.5% ownership of the combined company, while Dominion shareholders will hold the remaining 25.5%.

The combined entity would serve approximately 10 million customer accounts and operate 110 gigawatts of generation capacity spanning nuclear, natural gas, renewables and battery storage assets. More than 80% of the business would remain regulated, providing a substantial base of rate-backed infrastructure investment opportunities as utilities scale capital spending in response to load growth and grid resiliency requirements.

The merged utility would carry a combined regulated rate base of approximately $138 billion, with management projecting annual growth of around 11% through 2032. Executives also highlighted a development pipeline featuring more than 130 gigawatts of large-load opportunities, underscoring the accelerating influence of hyperscale computing facilities, advanced manufacturing and electrification-driven demand on long-range utility planning.

NextEra Energy CEO John Ketchum noted that the utility merger is being driven not by scale alone but by operational efficiencies, supply-chain leverage and construction capability as the industry confronts increasingly complex generation and transmission buildouts.

The transaction meaningfully expands NextEra’s regulated utility footprint beyond its Florida base while extending its reach into some of the country’s fastest-growing electricity markets. Dominion contributes regulated operations across Virginia, North Carolina and South Carolina, including infrastructure directly tied to high-growth data center corridors and large industrial energy users. This positions the combined company squarely at the intersection of power grid expansion and digital infrastructure demand.

The NextEra and Dominion Energy merger reflects a wider restructuring taking shape across the U.S. power sector. Utilities are increasingly seeking larger balance sheets and integrated infrastructure platforms capable of financing multibillion-dollar transmission, generation and grid modernization programs. At the same time, the industry is contending with supply-chain bottlenecks, transformer shortages, permitting complexity and rising construction costs associated with the rapid growth of electricity-intensive industries.

Management pointed to expanded capabilities in data analytics, supply-chain management and AI-driven operational planning as tools intended to improve project deployment and overall grid operations within the combined organization.

The operational structure of the utility merger is designed to preserve existing local regulatory relationships. Dominion’s utility businesses will continue operating under their established names, including Dominion Energy Virginia and Dominion Energy South Carolina. The combined company will maintain dual headquarters in Juno Beach, Florida and Richmond, Virginia, alongside Dominion Energy South Carolina’s operational headquarters in Cayce.

Robert Blue, Dominion’s current chairman and chief executive, will transition into the role of president and CEO of regulated utilities for the combined company and will join its board of directors. John Ketchum will continue as chairman and CEO of the parent company.

As part of the transaction, the companies are proposing $2.25 billion in bill credits for Dominion customers across Virginia, North Carolina and South Carolina over the two years following the deal’s close. Management indicated that greater scale and combined procurement capabilities are expected to lower long-term operating and capital costs across the combined regulated electric utility.

The transaction is expected to close within 12 to 18 months, subject to shareholder approval and a series of regulatory reviews. Required clearances include approvals from the Federal Energy Regulatory Commission, the Nuclear Regulatory Commission and utility commissions in Virginia, North Carolina and South Carolina.

Once completed, the merged company would rank among the industry’s leading infrastructure investors by annual capital expenditure, regulated rate base and total generation capacity in the power grid expansion landscape.

Subject to a final investment decision expected in 2027, the first plant is planned for a Blue Energy site in Texas, with the primary aim of supplying power to a nearby data center campus.

A Two-Phase Approach to Power Delivery

The two companies have already signed a slot reservation agreement for the delivery of two GE Vernova 7HA.02 gas turbines to the Texas site in 2029. These turbines are intended to support what the companies refer to as “early site energization,” establishing an initial power foundation before nuclear capacity comes online.

Blue Energy expects the gas turbines to provide approximately 1 gigawatt of power as early as 2030. The steam supply would then transition and scale up to deliver approximately 1.5 gigawatts of nuclear power as the BWRX-300 small modular reactors come online, targeted for as early as 2032.

Eric Gray, CEO of GE Vernova’s Power Segment, stated, “Combining our industry-leading HA gas turbines with the BWRX-300, the only small modular nuclear reactor under construction in the Western world today, provides an effective solution aimed to meet the demands of rapid AI expansion in the United States while decreasing time to power.”

Rethinking Nuclear Construction Timelines

A central element of this collaboration is Blue Energy’s proprietary construction methodology, which received approval from the U.S. Nuclear Regulatory Commission in December last year. The NRC approved the company’s licensing topical report covering an approach to “resequencing” the traditional phases of nuclear plant construction.

Under this model, Blue Energy separates the construction of nuclear and non-nuclear portions of the gas-plus-nuclear plant. The process begins with off-site fabrication and on-site installation of non-nuclear, non-safety-significant infrastructure. This sequencing allows fabrication and site energization to begin while the nuclear components continue through their respective licensing and construction phases.

Blue Energy claims this approach can accelerate deployment of new nuclear power plants by trimming at least five years off the conventional nuclear construction timeline, targeting a time to power of 48 months or less, supported by a natural gas bridge to full nuclear capacity.

Modular Construction to Reduce Costs

Beyond the construction timeline, GE Vernova and Blue Energy are also exploring contracting and off-site construction methods for large power plant modules consistent with the BWRX-300 design. The goal is to reduce capital costs and accelerate off-site prefabrication supply chains, making the nuclear power plant model more financially accessible and replicable.

Regulatory Milestones Ahead

The two companies anticipate entering into a further agreement to conduct preliminary safety analysis work at the Texas site. This work, along with development and site characterization activities, is intended to support a nuclear construction permit application that Blue Energy expects to file with the NRC in 2027.

Blue Energy co-founder and CEO Jake Jurewicz said, “Blue Energy and GE Vernova can unlock a blueprint for how to scale nuclear energy, power American communities, and fuel global AI leadership faster, more affordably, and without burdening ratepayers.”

GE Vernova CEO Scott Strazik added, “Innovative projects like this one will help advance the future of nuclear power and meet the surging demand for electricity. We are proud that our collaboration with Blue Energy and others in the entrepreneurial community will play an increasingly important role in accelerating America’s next era of energy leadership.”

The Texas-based gas-plus-nuclear plant, leveraging the BWRX-300 small modular reactor alongside proven gas turbine technology, represents a closely watched development in the effort to bring new nuclear power plant capacity online faster and at lower cost in the United States.

Strategic Framework and Policy Direction

The forthcoming Canada nuclear strategy, being developed by Natural Resources Canada, is expected to be released by the end of 2026. It is structured around four core pillars designed to accelerate nuclear deployment and industrial growth:

• Enabling new nuclear builds across Canada, including both small and large-scale projects
• Positioning Canada as a global supplier and exporter of nuclear technology and services
• Expanding uranium production and strengthening nuclear fuel supply capabilities
• Advancing next-generation nuclear technologies, including small modular reactors (SMRs), microreactors, and fusion

The government highlighted that the global nuclear market could grow by up to CAD200 billion annually by 2030, reinforcing the strategic importance of scaling domestic capabilities while capturing export opportunities.

From an industry standpoint, Power Info Today observes that the structured multi-pillar approach aligns capital deployment, trade strategy, and innovation pathways into a unified policy framework, reducing fragmentation across Canada’s nuclear value chain.

Investment and Financial Commitments

A key component of the strategy is targeted public investment to support both infrastructure and innovation. The federal government has committed CAD2.2 billion over 10 years to modernise research infrastructure at Chalk River Laboratories. This includes development of the Advanced Materials Research Centre and upgrades to critical laboratory facilities to support reactor technology, fuel development, and safety research.

In parallel, the Department of National Defence is allocating over CAD40 million in the 2026–2027 fiscal year to evaluate the feasibility of deploying Canadian-controlled microreactors. This builds on earlier investments, including CAD6 million in 2025–2026 directed toward research and development activities.

Microreactor Deployment and Operational Impact

The microreactor feasibility programme, delivered in collaboration with Department of National Defence and Atomic Energy of Canada Limited, is designed to assess whether next-generation reactors can provide reliable heat and electricity to remote and northern defence installations.

This initiative reflects operational priorities tied to energy resilience in off-grid regions, where energy costs remain high and supply stability is limited. The programme also has potential applications beyond defence, including industrial sites and remote communities requiring continuous, low-emission power.

Supply Chain and Export Positioning

The strategy places strong emphasis on leveraging Canada’s uranium resources to support allied nuclear expansion. Canada accounted for approximately 24% of global uranium production in 2024, with around 90% of output exported for use in nuclear power generation.

The government aims to strengthen its position across the nuclear supply chain by aligning trade policy tools, including export financing and international market development support. This includes coordination with agencies such as the Trade Commissioner Service and Export Development Canada to target high-growth markets.

Market Relevance and Strategic Outlook

Canada’s nuclear sector currently contributes CAD22 billion annually to the national economy and generates approximately 13% of electricity through 17 CANDU reactors operating in Ontario and New Brunswick. The strategy is expected to further integrate nuclear energy into national electrification efforts while supporting grid expansion and long-term energy security.

As global momentum builds toward tripling nuclear capacity by 2050, Canada’s policy direction signals a dual focus on domestic deployment and international competitiveness. The Canada nuclear strategy is positioned to play a central role in aligning infrastructure investment, innovation, and export growth within the country’s broader energy transition framework.

The method works by analysing a 360° equirectangular image taken at the installation point of a solar panel. From this single visual input, the system extracts information about sky visibility, surrounding structures, and illumination conditions. According to corresponding author Shree K. Nayar, the technique can be applied both before installation to estimate annual energy output and after installation to optimise panel orientation, particularly in dense urban environments such as rooftops or narrow urban canyons.

Conventional forecasting methods rely heavily on 3D city models and simulation tools, but these often fail to capture smaller environmental details that significantly influence energy generation. “Unfortunately, these 3D models are simply not accurate enough to provide precise energy estimates,” Nayar explained, noting that elements such as vents, signage, and window structures can affect light reflection and shadowing as much as larger buildings. The new system instead leverages visual cues such as textures, edges, and lighting patterns captured in the image, bypassing the limitations of inertial sensors, which are often unreliable in urban settings.

At the core of the technique is a neural network trained to determine sun direction and gravitational orientation directly from the image. These outputs are aligned with real-world coordinates using time, date, and GPS data. The model then calculates irradiance by combining three components: direct sunlight, sky illumination, and reflected light from surrounding structures. Notably, the “scene irradiance” contribution derived from nearby buildings accounts for approximately 12% of total energy received, highlighting the importance of environmental context in Solar Irradiance Forecasting.

The system has been validated across multiple urban environments using real-world pyranometer measurements. Results show that it accurately tracks daily irradiance patterns under varying weather conditions, including clear and overcast skies, while effectively capturing rapid fluctuations when the sun moves in and out of visible sky regions. Researchers emphasise that the solution is both portable and cost-effective, offering a practical tool for homeowners and commercial developers to improve solar project planning. The approach also opens opportunities for vertical solar installations, as building facades often receive substantial sunlight exposure.

In New Jersey, Governor Mikie Sherrill has approved legislation that removes a long-standing permitting constraint which had effectively acted as a nuclear moratorium. The decision was announced alongside the formation of a Nuclear Task Force following a visit to PSEG’s Salem nuclear power plant. “For costs to come down, we need more energy supply. New Jersey is well-positioned to be a leader in next-generation nuclear energy to help bring that supply, and we are open for business,” Sherrill said. “By lifting outdated barriers and bringing together leaders across government, industry, and labour, we’re setting the stage for our state to pursue new advanced nuclear power. This will help New Jersey secure a stronger, cleaner, more affordable, and reliable energy future – while keeping the state at the forefront of innovation, job creation, and economic growth.”

The change addresses provisions under the Coastal Area Facility Review Act, which had required an approved radioactive waste disposal method from the Nuclear Regulatory Commission—an obligation the state considered impractical. Under the revised framework, permits can now be issued based on safe, NRC-compliant waste storage, effectively clearing the path for new projects. The newly formed task force will focus on financing, supply chains, workforce development, regulatory structures, and public confidence to ensure readiness for deployment. Existing facilities, including Salem and Hope Creek, currently supply about 42% of New Jersey’s electricity.

In Kentucky, Governor Andy Beshear has signed legislation creating the Kentucky Nuclear Energy Development Authority, alongside a Nuclear Reactor Site Readiness Pilot Program. The initiative aims to support applications for early site permits, construction approvals, and combined operating licences from the Nuclear Regulatory Commission. “Every step makes a difference when it comes to helping our people save their hard-earned dollars,” Beshear said, noting the potential for long-term reductions in utility costs. Kentucky does not currently operate any nuclear generation capacity.

Texas has also advanced nuclear expansion by opening applications for USD350 million in funding through the Texas Advanced Nuclear Development Fund. Administered by the Texas Advanced Nuclear Energy Office, the programme supports both construction reimbursement and project design and supply chain activities. Eligible applicants must demonstrate, or expect to have, a docketed construction permit or licence application with the Nuclear Regulatory Commission by 1 December 2026, with submissions due by mid-May.

BKV is evaluating both greenfield development and acquisitions of gas-fired power assets, with the objective of adding roughly 1GW of capacity. The company’s focus remains firmly on Texas, where it already operates two gas-fired facilities via its publicly listed US arm. These assets, secured in 2021 and 2023, each deliver approximately 1.5GW and serve the state’s power market. As demand from AI-driven and cloud-based data centres intensifies, Banpu sees tightening supply conditions as a catalyst for new investments.

“The US power business will be a core earnings driver, supported by sustained demand from data centres and AI,” said Vongkusolkit in an interview. “Valuations have increased, but the long-term growth outlook continues to justify investment.” The Banpu US expansion plan reflects a broader strategic pivot, as the company gradually reduces its reliance on coal and builds a more diversified energy mix anchored in gas and renewables.

While this transition is underway, Banpu continues to benefit from external market dynamics. Supply disruptions in the Middle East have supported coal demand, prompting the company to increase output across its mining operations in China, Indonesia and other regions. Alongside its US ambitions, Banpu maintains a global power portfolio spanning China, Laos, Vietnam and Australia, with a combined generating capacity of 3GW.

The approved projects are structured to address increasing power requirements from data centers and advanced manufacturing, while ensuring residential electricity costs remain unaffected. As part of the agreement, the developments will be jointly owned by Japan and the United States, with NextEra Energy responsible for building and operating the facilities. The initiative includes the company’s previously disclosed Texas hub, developed in coordination with Comstock Resources, and is intended to reinforce the U.S. industrial base while supporting high-demand energy users through this gas power expansion strategy.

John Ketchum, chairman, president and CEO of NextEra Energy, stated, “America needs more power, and NextEra Energy is ready to deliver. For more than a century, we have built the energy infrastructure that powers America’s growth. Our hub strategy is designed to scale quickly and support rising demand while strengthening America’s energy security without increasing electricity costs for American households. We are pleased that our Texas and Pennsylvania hubs have been selected to advance the President’s goal of American energy dominance.”

The selected developments originate from NextEra Energy’s existing portfolio of hub assets, reflecting its scale-driven approach to project execution. The company currently maintains close to 30 hubs at different stages of development and is working toward a target of approximately 40. By leveraging this hub strategy, NextEra Energy aims to streamline timelines, reduce execution risk, and ensure cost efficiency while meeting the country’s expanding energy needs.

The funding initiative, launched through the Department’s Office of Electricity (OE), will support projects under the Speed to Power through Accelerated Reconductoring and other Key Advanced Transmission Technology Upgrades (SPARK) program. The effort is designed to rapidly increase transmission capacity by upgrading existing infrastructure rather than constructing entirely new transmission lines, a process that can often take a decade or longer due to permitting requirements and land-use disputes.

According to the Department of Energy, the program will focus on reconductoring, which involves replacing existing transmission wires with higher-capacity conductors capable of carrying greater volumes of electricity. When combined with other Advanced Transmission Technologies (ATTs), these upgrades are intended to expand grid capacity, improve operational efficiency, and strengthen the reliability and security of the U.S. electric system.

The initiative comes as electricity consumption in the United States is expected to rise significantly in the coming years. Rapid expansion of AI and cryptocurrency data centers, along with broader electrification of heating and transportation, is pushing power demand higher after two decades of relatively flat consumption. Utilities across the country have already begun expanding transmission infrastructure and other grid components to accommodate this shift.

Officials say the SPARK program aims to help utilities respond to these pressures while controlling costs and improving system resilience.

“For too long, important grid modernization and energy addition efforts were not prioritized by past leaders,” said Chris Wright. “Thanks to President Trump, we are doing the important work of modernizing our grid so electricity costs will be lowered for American families and businesses.”

The funding opportunity aligns with President Donald Trump’s Executive Order “Unleashing American Energy,” which aims to expand domestic energy production and modernize infrastructure supporting the nation’s power system.

Officials also emphasized the operational benefits of upgrading existing transmission assets.

“The United States must increase grid capacity to meet demand, and ensure the grid provides reliable power—day-in and day-out,” said Katie Jereza. “Through this SPARK funding opportunity, we will stabilize and optimize grid operations to strengthen it for rapid growth.”

The SPARK Program builds on the Department’s Grid Resilience and Innovation Partnerships (GRIP) Program, which authorized up to $10.5 billion in competitive funding over five years to strengthen transmission infrastructure, deploy advanced grid technologies, and improve system resilience. Earlier GRIP funding rounds covered fiscal years 2022–2023 and 2023–2024.

Unlike conventional transmission expansion projects, the new funding specifically prioritizes rapid-deployment technologies capable of increasing transfer capacity using existing rights-of-way. By upgrading conductors and installing advanced transmission technologies on existing towers, utilities can expand grid capability more quickly than constructing entirely new lines.

The urgency behind the program reflects mounting operational pressures across the U.S. power system. As demand continues to climb and extreme weather events place additional strain on infrastructure, many regional grids are operating closer to their capacity limits. During peak heat or cold events, system operators often rely on every available megawatt to maintain system balance.

Programs such as SPARK aim to address these challenges by enabling faster infrastructure upgrades that expand transfer capability while enhancing reliability and resource adequacy.

The Department of Energy has set April 2, 2026 as the deadline for concept papers, with full applications due by May 20, 2026. The agency anticipates announcing selected projects in August 2026, while an informational webinar outlining program details is expected to be posted on the Office of Electricity website by March 19, 2026.

The funding effort represents one of the latest federal initiatives focused on strengthening transmission infrastructure as electricity demand accelerates and the U.S. power sector adapts to a more complex and energy-intensive economy.

The funding aligns with President Trump’s Executive Order, “Unleashing American Energy,” which prioritizes domestic energy development and innovation. By supporting field demonstrations and drilling activities, DOE intends to strengthen the technical and economic viability of geothermal systems and contribute to affordable, reliable, around-the-clock electricity supply.

Kyle Haustveit, DOE Assistant Secretary of the Hydrocarbons and Geothermal Energy Office, announced the grant opportunity on Feb. 25. “Work under this opportunity will directly support our commitments to advance energy addition, reduce energy costs for American families and businesses, and unleash American energy dominance and innovation,” Haustveit said. “These demonstrations and drilling activities will help us realize the enormous potential of geothermal to spur domestic manufacturing, enable data center growth, and provide affordable, reliable, and secure energy solutions nationwide.”

The funding opportunity includes six topic areas, with varied funding levels and awards anticipated across different rounds. In the first round, two topics will be open for applications: enhanced geothermal system field tests at sites with electricity generation potential, and drilling projects focused on next-generation and hydrothermal resource exploration, characterization, and confirmation.

Across all rounds, eligible project categories include:

• Enhanced geothermal field tests at prospective electricity-generating sites
• Closed-loop field tests requiring new or additional drilling
• Closed-loop field tests utilizing existing wells
• Super-hot/supercritical field tests at sites expected to exceed 375°C
• Direct use/thermal field tests for applications without electricity generation
• Drilling for next-generation and hydrothermal resource exploration and data collection

Geothermal energy is defined as heat energy from the earth using existing natural or artificial reservoirs of hot water at varying temperatures and depths. According to DOE, wells ranging from a few feet to several miles deep can access underground reservoirs to bring steam or hot water to the surface for electricity generation or other applications.

The United States currently leads the world in geothermal electricity capacity with approximately 4 gigawatts installed. In 2023, U.S. geothermal plants generated 17 billion kilowatthours, accounting for 0.4% of total utility-scale electricity generation nationally, according to the U.S. Energy Information Administration. Geothermal power plants are operating in California, Nevada, Utah, Hawaii, Oregon, Idaho, and New Mexico.

DOE analysis indicates that the United States could potentially deploy at least 300 gigawatts of reliable, flexible geothermal power to the national grid by 2050. Projects supported under this funding opportunity are expected to help de-risk geothermal development across diverse geologic settings, improving data availability and technical validation. The agency’s objective is to use federal financial assistance to encourage private investment, spur industry growth, and help realize the country’s geothermal potential.

Letters of Intent are due March 27, 2026, and full applications must be submitted by April 30, 2026.