To support the move, President Trump invoked the Defense Production Act, a legal mechanism that allows the US president to expand production in industries deemed critical to national security. The announcement coincided with the effective blockade of the Strait of Hormuz since early March and rising energy prices in the US linked to the ongoing conflict with Iran.

Of the total $700 million committed, $500 million has been earmarked to establish a new export centre in California and to preserve 14 existing coal plants operating across Kentucky, North Carolina, Indiana, Tennessee, Arkansas, Arizona, Oklahoma, North Dakota, Wisconsin, and West Virginia. The remaining $200 million will fund the construction of new coal plants in Alaska and West Virginia the first such new facilities to be built in the US since 2013. Earlier this year, the US had also directed existing coal plants to continue operating beyond their originally planned retirement dates, a significant development for the North American energy sector.

Similar policy shifts are also unfolding in Europe. Italy has announced it will delay the permanent closure of its coal-fired power plants until 2038, pushing the original deadline back by 13 years. In Germany, Chancellor Friedrich Merz has indicated the country may also need to delay planned shutdowns. “We may even have to keep existing coal-fired power stations connected to the grid for longer, should the energy crisis continue, and a shortage actually arise,” Merz stated.

While the ongoing Middle East conflict has accelerated coal’s redeployment in the energy mix, its broader resurgence can also be traced back to the COVID-19 pandemic and the intensification of the Russia-Ukraine conflict in 2022. Both events exposed significant supply chain vulnerabilities across Europe and the wider world, prompting governments to reassess their long-term energy strategies. Data from the International Energy Agency (IEA) confirms that global coal consumption has only grown since 2020, reversing a previous decline.

No assessment of global coal consumption is complete without examining the roles of China and India. According to the IEA’s Global Energy Review 2024, China’s coal demand rose by 1.2%, setting a new record. The country now consumes approximately 40% more coal than the rest of the world combined, largely for electricity generation, with Chinese power plants accounting for more than one-third of global coal use.

India, the world’s second-largest coal consumer, recorded an all-time high growth in coal demand of 5.5% in 2024. Coal power generation in India grew by 5% the same year, directly in line with rising electricity demand.

Southeast Asia emerged as the world’s third-largest coal-consuming region in 2023. In 2024, coal consumption in the region increased by over 8%, driven primarily by Indonesia, Vietnam, and the Philippines. Indonesia’s growth was largely linked to coal’s expanding role in the metallurgical industry, while coal power generation served as the primary driver in Vietnam and the Philippines.

A critical, and perhaps surprising, factor in the coal industry revival is the accelerating global demand for electricity, with artificial intelligence and data centres playing a central role. Research from Lawrence Berkeley National Laboratory projects that by 2028, more than half of all electricity consumed by data centres will be dedicated to AI workloads.

The IEA reports that data centre electricity use reached 415 terawatt-hours (TWh) in 2024, representing nearly 1.5% of total global power consumption. This figure reflects a sustained growth trend, with data centre electricity usage expanding at a rate of 12% per year over the past five years a trajectory that continues to place upward pressure on overall energy demand worldwide and, by extension, on coal consumption as a reliable baseload power source.

At full operation, the BigBeau facility generates enough electricity to serve up to 64,000 typical households across California. The project is expected to avoid more than 315,000t of carbon dioxide emissions annually, an amount comparable to the yearly emissions produced by 67,000 passenger vehicles. The development forms part of a wider partnership between EDF and Masdar that includes seven renewable energy projects across the US with a combined capacity of 1.1GW. Over more than 35 years, EDF power solutions North America has developed 26GW of wind, solar and energy storage projects, spanning utility-scale renewable developments and electric vehicle charging infrastructure.

EDF power solutions North America origination and power marketing associate director Jacqueline de Fresart said: “We are very pleased to support Southern California Edison’s clean energy goals and provide reliable and efficient energy to its customers from our operating BigBeau project.

“We are excited to partner with SCE again and look forward to more opportunities together.”

Masdar, which has been active in the US since 2019 and has invested several billion dollars in the country, is targeting the development of up to 25GW of projects across the US over the next decade. Masdar Americas director asset management Dustin Priemer said: “This agreement forms a part of Masdar’s growing portfolio in the US, reflecting our focus on scaling reliable, utility-scale clean power.

“We are appreciative of our growing partnership with Southern California Edison and our shared commitment to investing in new generation capacity to meet growing energy demand in California.”

The transaction involves the assumption of $750 million in senior secured project debt along with $250 million in equity. To fund the cash component of the deal, TransAlta has launched a concurrent C$350 million bought deal common share offering, which involves the issuance of 18.2 million common shares priced at C$19.20 per share. The equity offering is being underwritten by CIBC Capital Markets and RBC Capital Markets, with closing expected on or around 9 June 2026, subject to customary approvals.

TransAlta projects that the Colorado gas plants acquisition will contribute approximately $80 million in adjusted earnings before interest, taxes, depreciation and amortisation on an annual basis, along with free cash flow of around $33 million per year. The company also noted the potential for further increases through availability incentive payments. The deal is expected to deliver immediate low-to-mid single-digit accretion to free cash flow per share.

Mountain Peak Power has been operational since September 2025, while Canyon Peak Power is expected to reach commercial service in the third quarter of 2026. Both Colorado gas plants are secured under long-term tolling agreements with investment-grade customers for more than 25 years, with full pass-through provisions covering fuel, operations and maintenance, and capital costs a structure that significantly reduces operational risk for TransAlta.

TransAlta president and CEO Joel Hunter commented on the deal, stating: “This acquisition adds new, high-quality, low-risk assets in a core market for us. It strengthens our business risk profile, is immediately accretive to our free cash flow per share and establishes a strategic foothold in Colorado, a state we believe has accelerating growth potential.”

Hunter further noted: “These assets will generate long-term contracted cash flows for redeployment into other growth prospects such as Centralia and Alberta data centres, and I am pleased with the continued meaningful progress on both projects.”

Completion of the natural gas acquisition remains contingent on Canyon Peak Power achieving commercial operation status and on receiving customary regulatory approvals. TransAlta expects to close the purchase early in the fourth quarter of 2026.

The newly released Request for Qualifications builds on Requests for Information issued by the authority last year, to which more than 30 entities responded among them 23 potential developers or partners and eight Upstate New York communities. The RFQ is designed to identify a qualified set of developers capable of delivering an advanced nuclear generation project through two possible technology pathways: a large-scale reactor, “such as the AP1000,” and/or a small modular reactor “such as the BWRX-300.”

Respondents are required to present “credible pathways” to deliver at least 1 GW of advanced nuclear capacity in Upstate New York. These submissions must address technology readiness, siting and permitting strategy, schedule and cost assumptions, ownership structures, and partnership models. Firms that are successfully qualified will subsequently be invited to take part in a future Request for Proposal process.

The authority confirmed it would consider so-called nth-of-a-kind Generation III+ or Generation IV technologies, on the condition that a first-of-a-kind project either by the respondent or by another owner or developer is “at or beyond First Nuclear Concrete by early 2030.” The selected pathway must also “demonstrate a credible path to both produce 1+ GW of energy and start construction before 2033,” a requirement tied to eligibility for investment tax credits under the US Inflation Reduction Act. First-of-a-kind technologies and micro modular reactors fall outside the scope of this initiative. All bidders are expected to hold “commensurate experience,” and the submission deadline is 26 June.

The second solicitation takes the form of a Request for Applications directed at eligible training providers based in New York State. Selected providers will be able to apply for funding to develop and deliver technical training programmes under the Nuclear Energy Workforce Training initiative. The deadline for submissions under this RFA is 31 July.

New York Governor Kathy Hochul commented on the announcements, stating: “Nearly a year ago, I called on the Power Authority to lay the groundwork for the next era of emissions-free power in New York as part of my all-of-the-above approach to energy. The solicitations announced today will help ensure New York is poised to lead the nation in new nuclear development, that along with renewables, will provide needed power in the face of increasing demand to keep the lights on while helping keep costs down. By taking a proactive approach, we are preparing our state to take advantage of the opportunities associated with advanced nuclear, which will provide round-the-clock reliable clean energy while cultivating the partnerships needed to bring the project from concept to concrete.”

New York Power Authority President and Chief Executive Officer Justin Driscoll added: “New York needs reliable, around-the-clock clean power to meet growing energy demand, sustain economic momentum, and achieve a clean energy economy. These solicitations will help NYPA establish the roadmap for deploying the first new nuclear facility in New York in a generation that will deliver the dependable, emissions-free power we will rely on for decades to come.”

New York currently has four nuclear reactors in operation, all run by Constellation Energy, which together account for approximately 21.4% of all electricity generated in the state and 41.6% of its carbon-free electricity supply, according to data from the Nuclear Energy Institute. The State of New York has already backed the continued operation of these facilities two units at Nine Mile Point and the single-unit Ginna and Fitzpatrick plants by formally recognising their zero-carbon attributes within its clean energy mandate.

The two pressurised water reactors at the Indian Point plant were shut down ahead of schedule in 2020 and 2021 respectively, following a settlement agreement between the plants’ then-owner Entergy and the State of New York. Earlier this year, New York Congressman Mike Lawler called for those units to be returned to service.

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.