It’s possible that I shall make an ass of myself. But in that case one can always get out of it with a little dialectic. I have, of course, so worded my proposition as to be right either way (K.Marx, Letter to F.Engels on the Indian Mutiny)
For half a century, the Gulf’s geopolitical influence travelled in tankers of crude oil; today, it is beginning to move in cargoes of liquefied gas, molecules of hydrogen, clean-energy carriers, carbon management solutions, and electrons transmitted across borders. Rather than abandoning hydrocarbons, Gulf states are repositioning themselves as multi-energy exporters, seeking to convert resource endowments, sovereign capital, and strategic geography into long-term influence across the next generation of global energy trade.
This emerging export model rests on three enduring advantages. First, the Gulf combines vast hydrocarbon reserves with some of the world’s most competitive solar and wind resources, enabling parallel investment in both legacy and low-carbon energy systems. Second, sovereign wealth funds and state-owned energy companies provide patient capital capable of financing large-scale infrastructure, from LNG trains and nuclear plants to hydrogen hubs and carbon-capture networks. Third, the region’s geography, situated between Europe, Asia, and Africa, positions it as a natural corridor for energy trade. Together, these allow the Gulf not merely to adapt to the energy transition but to shape its emerging commercial architecture.
LNG: Enduring Baseline of Gulf Energy Exports
LNG remains the most mature and commercially secure pillar of the Gulf’s evolving export model, providing both continuity with the hydrocarbon era and the financial foundation for diversification into lower-carbon energy systems.
Qatar’s North Field expansion is expected to nearly double LNG production capacity from 77 million tonnes per annum (mtpa) to about 142 mtpa by 2030, reinforcing its position among the world’s dominant gas exporters. In parallel, ADNOC’s Ruwais LNG project in the UAE will add about 9.6mtpa, with more than 80 percent of capacity already secured through long-term agreements ahead of its planned 2028 start-up. Designed as one of the region’s lowest-carbon LNG facilities, Ruwais will be powered by clean electricity and advanced digital optimisation.
Together with enduring long-term contracts with major Asian buyers, these developments underscore LNG’s continued role as the Gulf’s most bankable export channel even amid global decarbonisation pressures.
From a feasibility perspective, LNG differs from emerging clean-energy exports in one crucial respect: the infrastructure, shipping networks, and contractual frameworks are already established. This maturity allows Gulf producers to monetise existing gas reserves while financing investments in hydrogen, ammonia, and carbon management. Yet it also exposes LNG to long-term uncertainty. Competition from the United States and Australia, evolving climate policy, and the risk of demand plateauing beyond the 2030s mean that LNG is best understood not as the endpoint of Gulf export strategy, but as the stabilising bridge enabling the transition toward a broader multi-energy portfolio.
Hydrogen: Next Strategic Export Frontier
Hydrogen is being positioned to extend the Gulf’s energy influence into a decarbonising global system. Across the region, governments and state-backed developers are advancing large-scale projects that link abundant renewable resources, existing industrial infrastructure, and export-oriented energy strategy.
Saudi Arabia’s NEOM green hydrogen project is expected to produce around 600 tonnes per day of green hydrogen once operational, supported by more than 4 GW of dedicated solar and wind capacity. In the UAE, Masdar and ADNOC are advancing green and blue hydrogen initiatives tied to domestic industry and future export corridors, while Oman’s Hydrom framework and the Sur hydrogen cluster aim to position the country as a major
exporter of green fuels to Europe and Asia.
Despite this momentum, hydrogen exports remain structurally more uncertain than LNG. Large-scale deployment depends on falling electrolyser costs, reliable water supply through desalination, and bankable long-term offtake agreements in importing regions. Transport logistics, certification standards, and price competitiveness against alternative decarbonisation pathways will ultimately determine commercial viability. As a result, hydrogen is viewed as a long-term strategic extension of Gulf export capability, one that could reshape global energy trade if technological, financial, and geopolitical conditions align.
Ammonia: First Scalable Hydrogen Export
Ammonia is emerging as the most commercially viable pathway for exporting low-carbon hydrogen from the Gulf, enabling producers to utilise existing global shipping, storage, and industrial-use infrastructure while hydrogen markets mature. Several flagship Gulf projects are therefore structured around ammonia rather than direct hydrogen trade.
Saudi Arabia’s NEOM project is designed to produce roughly 1.2 mtpa of green ammonia, positioning the Kingdom among the earliest large-scale suppliers of hydrogen-derived fuels. It also successfully shipped 40 tonnes of blue ammonia to Japan, marking one of the world’s first cross-border trades in low-carbon ammonia and signalling early demand from Asian importers. In parallel, UAE-linked producer Fertiglobe has secured European offtake through Germany’s hydrogen-import tenders, while Oman is advancing integrated hydrogen-to-ammonia zones such as Hyport Duqm to anchor future clean-fuel exports.
Ammonia, unlike pure hydrogen, has existing transport logistics and end-use markets. Yet long-term competitiveness will depend on falling hydrogen production costs, large-scale renewable deployment, credible certification systems, and sustained import demand. Ammonia could represent a bridge between Gulf hydrocarbons and a future clean-molecule export economy, shaped by global policy and market environment. Regional Grid: Transmitting Clean Electrons
While still at a nascent stage, clean-power trade represents a potential long-term extension of the region’s energy-export model. The GCC Interconnection Grid already links national power systems, providing resilience, reserve sharing, and a foundation for future electricity trade. Historically used primarily for emergency balancing rather than commercial exchange, the same infrastructure could enable higher penetration of renewables and eventual cross-border clean-power flows as solar and wind capacity expands across Saudi Arabia, the UAE, and Oman.
Looking outward, several concepts under discussion envision high-voltage direct current (HVDC) connections transmitting renewable electricity from the Gulf toward neighbouring regions, including South Asia, North Africa, and potentially Europe. These proposals remain technically feasible but commercially complex, requiring multilateral coordination, long-distance subsea transmission, stable regulatory frameworks, and bankable long-term power-purchase agreements.
Compared with LNG or ammonia, direct electricity export faces higher geopolitical and infrastructure barriers, yet it also offers a compelling strategic logic. Where renewable generation costs are low, exporting electrons rather than fuels could ultimately provide a more efficient decarbonisation pathway for importing regions.
Carbon Management: A Low-Carbon Hedge
Carbon capture, utilisation, and storage (CCUS) is emerging as a parallel export logic for the Gulf, sustaining the competitiveness of hydrocarbon value chains in a carbon-constrained world. Qatar’s large-scale capture facilities at Ras Laffan, the UAE’s operational Al Reyadah and upcoming Habshan project, and Saudi Arabia’s Jubail CCS Hub collectively signal a shift toward embedding carbon management within core export infrastructure.
CCUS builds directly on existing industrial systems, allowing Gulf producers to preserve hydrocarbon revenues while lowering lifecycle emissions. Yet its long-term viability depends on policy credibility beyond the region, robust carbon-pricing mechanisms, trusted monitoring and verification frameworks, and sustained demand for low-carbon fuels in Europe and Asia. If these conditions materialise, carbon management could evolve into a distinct export service, anchoring hydrogen, LNG, and industrial decarbonisation partnerships. In this sense, CCUS represents not a departure from the Gulf’s hydrocarbon foundations, but their strategic adaptation to the economics and geopolitics of deep decarbonisation.
Emerging Multi-Energy Order
Rather than replacing hydrocarbons, the region is layering new export vectors onto an existing foundation, using gas revenues, sovereign capital, and industrial infrastructure to finance entry into lower-carbon energy systems. This transition is therefore evolutionary rather than disruptive, defined by sequencing, scale, and strategic hedging rather than abrupt transformation.
Whether this emerging multi-energy model succeeds will depend on bankable offtake, water and land availability, grid and shipping infrastructure, and credible carbon-accounting frameworks, to determine which export pathways mature commercially. At the same time, geopolitical stability and sustained demand from Europe and Asia remain preconditions for long-term influence.
If realised, the Gulf’s shift from exporting barrels of crude to exporting molecules, electrons, and carbon solutions could reshape the architecture of global energy trade. The question is not whether the Gulf will remain central to the energy system, but how that centrality will be redefined in a decarbonising world.
About the author: Parul Bakshi is Fellow – Energy and Climate at the Observer Research Foundation (ORF) Middle East.
ORF was established on 5 September 1990 as a private, not for profit, ’think tank’ to influence public policy formulation. The Foundation brought together, for the first time, leading Indian economists and policymakers to present An Agenda for Economic Reforms in India. The idea was to help develop a consensus in favour of economic reforms.
Tuesday, March 03, 2026
NASA announces a big shake‑up of the Artemis Moon program
The next mission, Artemis III, will now no longer land humans on the surface of the moon, but will instead feature a series of technology tests in Low Earth orbit. Artemis IV will then be the first human landing on the moon, sometime in 2028.
The Artemis II crew. NASA astronauts Reid Wiseman, commander; Victor Glover, pilot; Christina Koch, mission specialist; and Canadian Space Agency astronaut Jeremy Hansen, mission specialist are seen as they depart for a test in December 2025, at NASA’s Kennedy Space Center in Florida. (NASA/Aubrey Gemignani)
Following an initial setback due to a liquid hydrogen leak encountered during a wet dress rehearsal on Feb. 3, further issues for Artemis II arose during the second wet dress rehearsal from Feb. 19 to 20. As a result, the earliest launch date is now April 1.
This would make it over three years since the first Artemis mission. Such long gaps between missions limit the ability to refine systems quickly and mean that the same issues (for example, fuel leaks) keep recurring. With the loss of more than 4,000 employees — approximately 20 per cent of its workforce — in 2025, NASA is also dealing with significant workforce challenges, causing further strain to the Artemis program.
These challenges appear to have been recognized by NASA’s new administrator, Jared Isaacman, who wrote in a recent social media post that “the days of NASA launching Moon rockets every 3 years are over.”
A big part of the plan involves standardizing the Space Launch System (SLS) rocket “upper stage” — this is the part of the rocket that propels the spacecraft from Low Earth orbit toward the moon.
NASA’s crawler-transporter 2, carrying the Artemis II SLS (Space Launch System) rocket and Orion spacecraft, heads back to the vehicle assembly building at NASA’s Kennedy Space Center in Florida on Feb. 25, 2026. (NASA/Kim Shiflett)
A reinvigorated Artemis program
There have been lots of news stories circulating since NASA’s announcement about the shake-up of the Artemis program, many of them referring to the “cancellation” of the Artemis III mission. This is not a fair or accurate representation of the new plans. Many people, including myself, think the new plans are not only more realistic, but also exciting in their own right.
It’s true that Artemis III will now not be the first human landing on the moon since Apollo 17 in 1972. Instead, the mission will launch the Orion crew capsule with astronauts on board into Low Earth orbit, where they will conduct in-space testing of critical technologies, including life support, propulsion and communications systems.
While in orbit, it’s also hoped that Orion will rendezvous and dock with one, or both, of the commercially developed lunar landers built by the companies SpaceX and Blue Origin. This makes sense as the original Artemis plan went from Artemis II straight to the surface without testing out these critical aspects of the mission
. The Artemis spacesuit prototype, the AxEMU, developed by Axiom Space.
The crew may also test the new spacesuits designed by Axiom Space, which is important because these suits haven’t yet been worn for an actual space mission.
This new plan, therefore, actually reduces the risks and increases the likelihood of a successful human mission to the surface of the moon in 2028 — Artemis IV instead of Artemis III.
The most exciting, and surprising, part of the recent announcement was that NASA will try for not just one, but two moon landings in 2028, and then a mission every year thereafter. Suddenly, this is becoming much more like the Apollo program, which launched 11 crewed missions in four years
. A graphic illustrating NASA’s increased cadence of Artemis missions. NASA
What about the Lunar Gateway?
There was a notable absence in last week’s announcement — a mention of the Lunar Gateway. This is the small space station that will orbit the moon as part of the Artemis program.
In the original plans, the second lunar landing, Artemis IV, was meant to go to the surface of the moon via the Lunar Gateway.
Artist’s concept of the full Gateway configuration. (NASA)
It builds on Canada’s robotics heritage from Canadarm and Canadarm2, but is far more advanced, featuring artificial intelligence — which is necessary due to the distance it will operate from Earth. As NASA works out the plans for the second and subsequent lunar surface missions, I hope for the sake of the Canadian space program that the Lunar Gateway with its Canadarm3 will still be in the mix.
Author
Gordon Osinski Professor in Earth and Planetary Science, Western University
Disclosure statement Gordon Osinski founded the company Interplanetary Exploration Odyssey Inc. He receives funding from the Natural Sciences and Engineering Research Council of Canada and the Canadian Space Agency.
Monday, March 02, 2026
Local water supply crucial to success of hydrogen initiative in Europe
Map of a simulated risk of water stress in 2050 where hydrogen is used in transport and industry. Baseline risk (regardless of hydrogen use) is represented by the background color in each area. Dashed areas show water use exceeding available resources due to hydrogen production. Blue dots show areas where the risk of water stress increases by more than 50 percent in the simulation.
Credit: Joel Löfving, Chalmers University of Technology
Green hydrogen is considered to be an important part of the global climate transition, especially as a fuel and energy carrier for heavy transport and industry. However, large-scale green hydrogen production requires sustainable ways of managing water resources to avoid giving rise to water shortages and conflicts with agriculture over access. This has been shown in a unique study from Chalmers University of Technology in Sweden, that connects local water supply with a range of scenarios for future hydrogen needs in Europe.
Replacing fossil fuels with hydrogen in the heavy-duty automotive and industrial sectors has the potential to greatly reduce emissions of the greenhouse gas carbon dioxide. This is especially true if the hydrogen gas is ‘green’, meaning that it is produced by electrolysis, a process whereby water is spit into hydrogen and oxygen using renewable electricity. A new study from Chalmers shows that planning where hydrogen will be manufactured, and the use of new technology solutions, is vital in order to avoid the large-scale production of green hydrogen leading to local water shortages in some parts of Europe.
In the study, published in Nature Sustainability, the researchers were able to explore different scenarios for how Europe’s hydrogen production might affect water resources, electricity prices and land use in 2050 – a year by which many countries have agreed to reduce their carbon emissions, which could mean the widespread use of hydrogen technology.
"Water is a resource that is often taken for granted in the energy transition. Our study is unique because we have connected the local perspective to the European perspective. We can show that even if hydrogen production does not require very much water in total compared to say agriculture, the local effects can be significant. This is because it’s better to produce hydrogen in close proximity to industry and access to renewable electricity, which generally means areas where water resources are already under strain. The conclusion is not that hydrogen production should be avoided, but that we must understand different perspectives and cooperate on many different levels – between government agencies, industry and local communities – to plan for the local effects of the transition,” says Joel Löfving, doctoral student at the Division of Transport, Energy and Environment at Chalmers.
Sörmland and Roslagen are high-risk areas
If hydrogen starts being widely used in industry and transport, the water supply might be severely impacted in multiple regions if the choice is to produce hydrogen locally, which is advantageous for economic reasons. For Sweden, it is anticipated that the water supply in the Sörmland and Roslagen regions, for example, is going to be hard pressed even without hydrogen production in 2050.
“In Sörmland there is already a steel mill and a refinery. If they were to switch to hydrogen and use local water sources to produce it, this could exacerbate the projected water shortage. Also in the Roslagen region northeast of Stockholm, we can see that it might be difficult to source local water for the production of green hydrogen, and in the Bohuslän region on the Swedish west coast, and parts of Norrland in the north, large-scale hydrogen production could increase water withdrawal by more than 50 per cent. Although the water supply there is considered to be good, there is a risk that this production could have a significant impact on the natural environment” he says.
The study analysed over 700 local water sub-basins in Europe, and similar patterns to those seen in Sweden could be identified in multiple locations. In southern and central Europe, where favourable conditions for generating electricity with solar and wind power make green hydrogen production particularly attractive, access to water is estimated to be very limited by 2050, as local water resources are already under strain and vulnerable to climate change. Major industry clusters in Spain, Germany, France and the Netherlands, for example, could thus face a conflict with agriculture, for example, over water resources.
“There are many potential conflicts around water as a resource, but also many solutions, such as seawater desalination or the reuse of water from wastewater treatment plants. There are also interesting synergies, as the oxygen that remains from the hydrogen production could be used in the processes that treat the wastewater. Hydrogen has great potential to contribute to the climate transition, but we need to find sustainable ways to manage water resources – for the production of fuel and for agriculture,” says Joel Löfving.
Electricity prices impacted less than expected
In addition to water use, the researchers studied how a large-scale hydrogen economy could affect Europe’s electricity prices. By plugging the hydrogen model into Chalmers’ Multinode model – a model developed for optimising the costs of Europe’s energy system in different scenarios – they were able to estimate changes in electricity prices between different regions.
The results show that electricity demand increases significantly in line with the amount of hydrogen produced, since it takes a lot of electricity to replace the energy in the fossil fuels that so far we have simply taken out of the ground. Despite this, the results show that the impact on average electricity prices in Europe is relatively small. In regions with good access to renewable energy sources, such as northern Europe, the price impact is the smallest. In southern Europe, where some regions are dependent on a higher proportion of electricity from gas or nuclear power, for example, bigger price increases were seen.
“Electricity prices are a sensitive issue, but our modeling shows that increased investment in electricity production for producing hydrogen does not necessarily lead to higher prices for consumers. This is an important message to decision-makers – to cope with the energy transition, all fossil-free energy sources are needed and we must have the courage to invest in new, green electricity production,” says Joel Löfving.
Broad patterns and local consequences
Large-scale green hydrogen production would require a big expansion of solar and wind power. But the expansion would only take up a few per cent of the land currently used for agriculture, according to the study. And this area is significantly less than would be required to replace the same amount of energy with biofuels.
The researchers argue that, taken together, the results provide an important holistic perspective on Europe’s energy transition. Previous studies have often focused on either local effects or effects at overarching system levels, but rarely combined both.
“It was this connection that we wanted to make. If we are going to build the future’s energy system, we need to understand both the broad patterns and the local consequences. By considering risks, we will be able to manage them, and thus create more certainty for investments in green technology,” says Joel Löfving.
Green hydrogen
Produced by electrolysis when water is split into hydrogen and oxygen using electricity. The electricity used must come from renewable sources such as solar, wind or hydro power for the hydrogen to be labelled ‘green’.
More about the research:
The study “Resource requirements and consequences of large-scale hydrogen use in Europe”has been published in Nature Sustainability. The authors are Joel Löfving, Selma Brynolf, Maria Grahn, Simon Öberg and Maria Taljegard, all working at Chalmers University of Technology. The research was carried out within the competence centre TechForH2 and the Division of Transport, Energy and Environment in collaboration with the Division of Energy Technology.
For more information, please contact:
Joel Löfving, doctoral student at the Division of Transport, Energy and Environment, Chalmers University of Technology: +46 31 772 16 47, joel.lofving@chalmers.se
Maria Grahn, Associate Professor at the Division of Transport, Energy and Environment, Chalmers University of Technology: +46 31 772 31 04, maria.grahn@chalmers.se
Caption: Map of a simulated risk of water stress in 2050 where hydrogen is used in transport and industry. Baseline risk (regardless of hydrogen use) is represented by the background color in each area. Dashed areas show water use exceeding available resources due to hydrogen production. Blue dots show areas where the risk of water stress increases by more than 50 percent in the simulation. Illustration: Joel Löfving, Chalmers University of Technology
Canada to offer training as part of IAEA Rays of Hope initiative
The Canadian Nuclear Isotope Council is planning training programmes for low- and middle-income countries in areas such as radiation safety and isotope production as part of the International Atomic Energy Agency's cancer-tackling Rays of Hope programme.
(Image: X/IAEA)
James Scongack, Chair of the Canadian Nuclear Isotope Council (CNIC), and IAEA Director-General Rafael Mariano Grossi - see picture above - discussed the proposed contributions in a meeting in Vienna on Friday.
Rays of Hope is an IAEA intiative which aims to expand access to cancer care and radiotherapy infrastructure to low- and middle-income countries (LMICs). Such countries experience 70% of global cancer deaths but receive just 5% of spending in this area.
The Canadian contribution will include: an isotope production and radiation safety training programme to be primarily hosted at Bruce Power in 2026 to welcome a class of regulators from LMICs to learn about technical fundamentals of nuclear isotope production, processing, and radiation safety culture; a proposed multi-disciplinary technical training programme hosting at London Health Sciences Centre and St Josephs' Hospital, leading Canadian hospitals, that covers hands-on training in radiochemistry and production, radiolabelling, quality control, dosimetry, medical imaging, patient delivery; and the development of an IAEA- and Canadian-made collaboration on e-learning and virtual training packages.
Grossi said: "By combining Canada's strengths in isotope production, processing, and quality control with the reach and expertise of the IAEA Rays of Hope initiative, we are helping countries build the professional competence needed to deliver safe and effective treatments."
Scongack said: "Today’s announcement reflects the next step in our committed, forward-looking partnership between Canada and the IAEA. While we recognise Canada’s current leadership in the global medical isotope community, we also must acknowledge that we face a responsibility to take an active role in supporting increased access to life-changing isotopes for patients around the world."
The CNIC and IAEA have established a technical working group which will work towards delivering the training programmes and e-learning materials towards the end of this year.
Background
Nuclear medicine uses radiation to provide diagnostic information about the functioning of a person's specific organs, or to treat them. Diagnostic procedures using radioisotopes are now routine. Radiotherapy can be used to treat some medical conditions, especially cancer, using radiation to weaken or destroy particular targeted cells. More than 50 million nuclear medicine procedures are performed each year, and demand for radioisotopes is increasing.
Environmental approval for Saskatchewan uranium project
Australia-headquartered Paladin Energy Limited has received approval from the Government of Saskatchewan for its Environmental Impact Statement for development of its Patterson Lake South project, located in the Athabasca Basin, Canada.
Patterson Lake South (Image: Paladin)
The Saskatchewan Minister of Environment formally approved the company's Environmental Impact Statement (EIS) for the shallow, high grade Patterson Lake South (PLS) project on 18 February. The approval follows technical acceptance of the document in June 2025 and an extensive public review period from July to September last year.
Paladin is proposing to construct, operate and decommission underground and surface facilities to support the mining and processing of uranium ore at the PLS project, which it acquired in 2024 through its acquisition of Canadian uranium project developer Fission Uranium Corporation. The main components include an underground mine, an onsite mill to process an average of 1,000 tonnes of ore per day, surface facilities to support the short- and long-term storage of waste rock and ore, an underground tailings management facility, water-handling infrastructure and an effluent treatment circuit, and additional infrastructure to support mining activities.
"The Environmental Assessment approval is an important regulatory milestone for the PLS Project and a prerequisite for permits and licences issued by provincial and federal authorities leading to construction and operation," Paladin said.
The company said it continues to work closely with the Canadian Nuclear Safety Commission (CNSC) to progress the project within its licensing process at the federal level. Paladin is advancing the technical detail needed to support the application for a construction licence submitted to the CNSC by Fission Uranium Corporation in April 2023.
"The Patterson Lake South Project supports the province's Growth Plan and Saskatchewan's role as an energy supplier," added Minister of Environment Darlene Rowden. "I am pleased to see this project moving forward with strong environmental safeguards. The environmental and sustainability aspects of the PLS Project have been subject to our robust Environmental Assessment process including scrutiny of our review panel of subject matter experts and having undergone considerable public and indigenous consultation. I commend Paladin on its approach to the approval process and congratulate their team on achieving this important milestone in their development."
Paladin Managing Director and CEO Paul Hemburrow said: "Paladin is delighted that the Minister, the Saskatchewan Government and its environmental regulatory agency have formally recognised that our approach to delivering a sustainable and safe development at the PLS Project is both environmentally and socially appropriate and achievable. The PLS Project is an economically and strategically important development within Canada and we will continue to progress the construction licencing process with the CNSC."
PLS is on the southwest margin of the Athabasca Basin and incorporates the Triple R deposit, which is both high grade and shallow - mineralisation starts just 50 metres below the surface. The deposit has indicated mineral resources of 114.9 million pounds U3O8 (44,196 tU) at an average grade of 1.94% U3O8, inferred resources of 15.4 million pounds at an average grade of 1.10% and probable reserves of 93.7 million pounds at an average 1.41% U3O8, all reported at a cut-off grade of 0.25%.
In 2023, Fission Uranium Corporation filed an NI 43-101 technical report summarising the feasibility study for the project, including a construction timeline of 3 years with an estimated initial capital cost of CAD1.155 billion (USD840 million) for a ten-year life-of-mine with total production of 90.9 million lbs U3O8 (35,000 tU), and an average unit operating cost of CAD13.02 per pound U3O8.
Denison granted licence for Wheeler River
The Canadian Nuclear Safety Commission has issued a licence to Denison Mines Corp to prepare a site and construct a uranium mine and mill at its Wheeler River project in Saskatchewan. The project is the first uranium mine in Canada to use the in-situ recovery mining method.
Wheeler River (Image: Denison Mines)
The Canadian Nuclear Safety Commission (CNSC) released the decision of its administrative tribunal approving the Environmental Assessment (EA) and issuing the Licence to Prepare Site & Construct a Mine and Mill for the Wheeler River Uranium Project. Denison Mines noted that with the Environmental Assessment having previously been approved by the Province of Saskatchewan, and other provincial approvals necessary to commence construction already received, federal approval of the Environmental Assessment and the issuance of the licence represent the final regulatory approvals required to commence construction of the Phoenix in-situ recovery uranium mine.
Phoenix - part of the Wheeler River project - is described by Denison as the largest undeveloped uranium project in the infrastructure-rich eastern portion of the Athabasca Basin region, in northern Saskatchewan. The project is host to the high-grade Phoenix and Gryphon uranium deposits, discovered by Denison in 2008 and 2014, respectively, and is a joint venture between Denison (90%) and JCU (Canada) Exploration Company Limited (10%). Denison is the operator. Permitting efforts for the planned Phoenix in-situ recovery (ISR) operation began in 2019.
In June 2023, the company reported an updated mineral resource estimate of 70.5 million pounds U3O8 (27,118 tU) for Phoenix, with 30.9 million pounds in the measured resources category and 39.7 million pounds of indicated resources.
In-situ recovery - also referred to as in-situ leach - is a method of recovering uranium minerals from ore in the ground by dissolving them in situ, using a mining solution injected into the orebody. The solution is then pumped to the surface, where the minerals are recovered from the uranium-bearing solution. More than half of the world's uranium production is now produced by such methods. The technique - which requires a geologically suitable orebody - has not so far been used in Canadian uranium operations, although in addition to the Phoenix deposit Denison has been investigating the potential for using ISR at other Canadian projects including the Heldeth Túé uranium deposit at Waterbury Lake and the Midwest Main project.
The licence granted by the CNSC is valid until the end of February 2031 and authorises site preparation and construction activities under the Nuclear Safety and Control Act. The licence does not authorise the operation of the facility to be constructed. Authorisation to operate the facility would be subject to a future CNSC licensing hearing and decision, should Denison submit a licence application to do so.
"The Commission decision to approve the EA and issue the Licence represents a landmark achievement for Denison, as well as our staff, shareholders, Indigenous partners, and other stakeholders in the project, said Denison President and CEO David Cates. "I'd like to recognise the efforts of Denison's talented teams, which have worked together tirelessly over a seven-year period to engage with Indigenous and non-Indigenous communities, comply with applicable laws and regulatory requirements, build trust with regulators and the public, and ultimately advocate for the approval of this ground-breaking project.
"Phoenix is the first uranium mine in Canada to be approved for ISR (In-situ recovery) mining and is the first large-scale Canadian uranium mine approved for construction in more than 20 years. It is a nation-building project that reflects the best of Canadian ingenuity and determination. Owing to the use of the ISR mining method, Phoenix has the potential to generate strong economics while also achieving a superior standard of sustainability when compared to conventional mining methods. With an approximately two-year construction timeline, the timing of this approval means that the project remains on track for first production by mid-2028."
Kairos, DOE enhance collaboration on advanced reactor design
The US Department of Energy's Oak Ridge National Laboratory and Kairos Power have entered into a USD27 million strategic partnership to accelerate the technology needed to deploy a new generation of advanced nuclear reactors.
TRISO fuel pebbles (Image: Kairos Power)
Under the partnership, over the next five years Oak Ridge National Laboratory (ORNL) will provide expertise and access to specialised facilities to review and evaluate various aspects of Kairos Power's novel fluoride salt-cooled high-temperature reactor design, which uses molten fluoride salt coolant with TRISO (tri-structural isotropic) fuel to generate reliable energy with robust inherent safety. ORNL will also manufacture components for reactor development and testing, and assess the performance of coated particle fuel following irradiation under conditions relevant to their planned reactor operation.
The scope of work includes: assessing fuel manufacturing and synthesis methods to evaluate product quality and production methods for TRISO fuel particles; understanding the properties of TRISO fuel pebbles to support a fabrication capability and quality control infrastructure; completing a comprehensive used fuel pebble management plan to include on-site cask storage, transportation and final disposition; producing components using advanced manufacturing techniques to better understand how materials that come into contact with the salt, such as ceramics, carbon composites, and metallic materials, perform in extremely high temperatures; and enabling remote maintenance systems capable of operating under high temperatures with simultaneous exposure to radiation and corrosive salts.
"Ultimately, the project's outcomes will support the design, construction and eventual operation of Kairos Power's planned Hermes demonstration reactors under construction in Oak Ridge, Tennessee, and subsequent commercialisation of its planned fluoride salt-cooled high-temperature reactor," ORNL said.
Kairos is building the Hermes Low-Power Demonstration Reactor - known as Hermes 1 - in Oak Ridge, Tennessee. Hermes 1, a scaled demonstration of Kairos's KP-FHR fluoride salt-cooled high-temperature reactor technology, is the first non-light-water reactor to be approved for construction by the US Nuclear Regulatory Commission. Kairos Power broke ground at the Hermes 1 site in Oak Ridge in July 2024 and began nuclear safety-related construction in May 2025. It will not produce electricity - Kairos's iterative development approach will see lessons learned from the project feeding into the Hermes 2 commercial-scale demonstration plant - a 50 MWe plant powered by a single commercial-scale reactor. Hermes 2 will include a power generation system.
DOE is investing up to USD303 million of risk reduction funding in Kairos Power's Hermes demonstration reactors under the Advanced Reactor Demonstration Program to mature the company’s molten salt reactor design. The latest project marks the fourth partnership between ORNL and Kairos Power since 2020.
"DOE's support has been instrumental in helping Kairos Power accelerate our path to technological maturity," said Ed Blandford, chief technology officer and co-founder of Kairos Power. "By collaborating with Oak Ridge National Laboratory, we gain access to decades of expertise and a unique set of capabilities that we couldn't find anywhere else. We are pleased to partner with the lab as we work to deploy safe, reliable advanced reactor technology that builds on Oak Ridge's nuclear legacy."
"Providing the scientific basis for new technology is what we do at Oak Ridge National Laboratory," said ORNL Director Stephen Streiffer. "With energy demand expected to increase substantially by 2050, our continued partnerships with US industry, including Kairos Power, are how we will bring more reliable, affordable energy to market."
Russian regulator issues operating licence for second Zaporizhzhia unit
Rostekhnadzor has issued a 10-year operating licence for Unit 2 at the Zaporizhzhia Nuclear Power Plant, which has been under Russian military control since early March 2022.
(Image: IAEA)
Russia's state nuclear corporation Rosatom said that obtaining the licence "confirms that the power unit's equipment, safety systems, and personnel qualifications fully comply with the strict requirements of Russian nuclear energy standards and regulations".
It added that Rostekhnadzor's backing of the operational safety of the unit "paves the way for the future development of nuclear power generation in the region".
Alexey Likhachev, Rosatom Director General, said that "all necessary work, maintenance, and scheduled preventive maintenance are carried out in strict accordance with schedules and at a high professional level. Our goal remains unchanged - to prepare all units for future generation".
An application has been submitted to Rostekhnadzor for an operating licence for Unit 6 and Rosatom aims to submit similar applications by the end of 2026 for units 3, 4, and 5.
The six-unit Zaporizhzhia nuclear power plant has the largest capacity of any nuclear power plant in Ukraine, and Europe, but all six units have been shut down since shortly after the start of the war, which is when it came under Russian military control.
Existing licences issued pre-war by the Ukrainian nuclear regulator were temporarily recognised, and extended where necessary, by Russia pending its regulator issuing licences.
Since September 2022 there have been teams of International Atomic Energy Agency experts stationed at the plant as part of efforts to ensure nuclear safey and security at a site which is located close to the frontline of Ukrainian and Russian forces.
Ukraine says that the best way to ensure nuclear safety and security is for the plant to return to its control, and regulatory system. Russia says that it aims to restart units at the plant under its legal and regulatory framework, when conditions are right. A Rostekhnadzor licence for Unit 1 was issued in December.
Background
At talks in June last year between IAEA Director General Rafael Mariano Grossi and Likhachev, the issue of potentially restarting the units was discussed. Grossi told a press conference at the time that there was a "common view" that it would be inadvisable to restart the plant in the current military situation, adding: "There are other more technical aspects like, for example, the availability of enough water to cool down the reactors or also the availability of sufficient, stable, external power so you can rest assured that if it's started there will be no blackout and the plant will be able to operate."
Russia's Tass news agency's coverage of those talks reported Likhachev as saying said the plant could only be restarted once there was no military threat, and quoted him as saying "we have already started construction of a floating modular pumping station with a capacity of up to 80,000 cubic metres per hour, which will address all problems related to water supply in the event that the units are brought to their design capacity".
Zaporizhzhia Nuclear Power Plant has six VVER-type reactors which entered commercial operation between 1985 and 1996. The combined operating capacity of the plant is 5.7 GW.
Serbia and Russia discuss nuclear energy cooperation
Serbian Energy Minister Dubravka Đedović Handanović says that the country - already cooperating with France's EDF on the preparations for a nuclear energy programme - "is ready to establish cooperation with other technology providers from whom we can learn".
(Image: Serbian Energy Ministry)
The minister was speaking after talks - see picture above - with Alexei Likhachev, Director General of the Russian state nuclear corporation Rosatom, about cooperation between the two countries in the field of nuclear energy.
According to the Serbian government's account of the meeting, Đedović Handanović said Serbia's government should approve the formation of the National Nuclear Programme Implementation Organisation by the end of the month. She said Serbia plans "to complete the first and second phases of the nuclear programme by 2032, and in the preparatory phase we are cooperating with the French company EDF".
It reports that Đedović Handanović said that by 2032 "the technology of small modular reactors will be more developed than today and we will be able to consider them as an option. Once we are institutionally, regulatorily and staff-wise equipped, we will be able to choose a partner, a technology carrier, and enter the construction process so that after 2040 we can have a nuclear power plant on the grid".
Rosatom later reported that in meetings on Monday, Likhachev also held talks with Serbian President Aleksandar Vučić "during which they discussed expanding cooperation in nuclear energy, attracting Serbian companies to Rosatom's international projects, and training Serbian applicants in nuclear fields at Russian universities".
It quoted Likhachev as saying: "The Serbian leadership is currently considering the possibility of constructing the country's first nuclear power plant. Rosatom State Corporation is offering its Serbian partners comprehensive cooperation. Nuclear energy offers Serbia an opportunity to ensure energy sovereignty and security for decades to come. Rosatom is the largest player in the foreign nuclear power plant construction market, holding over 90% of the global market share. We are ready to offer Serbia our full range of nuclear energy projects, from small to large-scale".
Background
Serbia had a longstanding law banning the construction of nuclear power plants, but in December 2024 the National Assembly voted through amendments to the energy law ending that 35-year prohibition.
In October 2024 EDF and French engineering consultancy Egis were awarded a contract by Serbia's Ministry of Mining & Energy to conduct a preliminary technical study on the potential use of nuclear power in the country, and the country has previously held talks with Russia's Rosatom about non-energy applications of nuclear technologies. President Aleksandar Vučić has also discussed the option of Serbia acquiring 5 to 10% of Hungary's Paks nuclear power plant.
Vučić said at 2024's multinational Nuclear Energy Summit in Brussels, that the country was seeking support from other countries in terms of know-how and financing to achieve its aim of getting 1,200 MW of capacity from small modular reactors.
Earlier this month Đedović Handanovic held talks with the Agence Française de Développement about cooperation related to the energy transition "especially in the development of nuclear energy applications in Serbia".
Blue Capsule begins building sodium test loop
French small modular reactor developer Blue Capsule Technology has announced the start of construction of ELISE - a full-size test rig for sodium at high temperatures - at Peyrolles-en-Provence, in collaboration with France's CSTI Groupe.
A Blue Capsule plant for end users (Image: Blue Capsule)
Aix-en-Provence-based Blue Capsule is developing a sodium-cooled, high-temperature SMR which can provide 150 MW of heat at 700°C, steam/vapour to 650°C, and 50 MW of electricity. The company - a spin-off from France's Alternative Energies & Atomic Energy Commission (CEA) - aims to decarbonise sites used for energy-intensive industries such as cement and metal refining, hydrogen production, and chemical production, with subterranean capsules co-located onsite, close to demand. The reactor is designed to operate for 60 years. Blue Capsule is targeting a cost to the end user of USD60 per MWh for industrial heat.
Blue Capsule is planning to build a proof-of-concept sodium loop and a non-nuclear prototype by 2030. ELISE is the first installation on the company's development roadmap and is set to run for several years.
"ELISE will replicate the conditions of the Blue Capsule high-temperature reactor (HTR), with temperatures reaching 750°C," said the company's Technical Director, Domnin Erard. "This full-size installation will stand at nine metres high when completed, and provide valuable data on thermo-hydraulics and the natural circulation of liquid sodium at high temperatures."
Edouard Hourcade, President of Blue Capsule, said the ELISE installation would be the "first of its kind" in France, and will be opened to other players in the field, "either institutional or commercial ... it is important that the broader nuclear energy sector can benefit from ELISE. But it's also a milestone for our company and a sign of steady progress".
Blue Capsule says the sodium-cooled reactor is to use tristructural isotropic - or TRISO - fuel for optimal safety, while the design is also optimised for more favourable economics due to the lower volume of building materials compared with traditional high-temperature gas-cooled reactors.
In November last year, Blue Capsule announced an agreement with Framatome to advance cooperation on TRISO fuel. Blue Capsule aims to deploy low-enriched (less than 5% enriched) TRISO fuel in its reactors, "given the wide use of low-enriched uranium in the industry, and the export potential of reactors that use LEU".
To date, Blue Capsule has announced partnerships with the CEA, Framatome, Egis, CSTI Groupe, DigIntel and Robatel, and key suppliers such as Laborelec and Mersen.
In May last year, Blue Capsule advanced to Phase 2 (the Preparatory Review) of its technical dialogue with the French Nuclear Safety and Radiation Protection Authority.
Construction of a non-nuclear prototype is scheduled to begin in 2027-28, with construction of the first-of-a-kind Blue Capsule reactor expected to begin in 2029-30, with deployment in the early 2030s.
Urenco installs innovative heat network at Dutch site
Uranium enrichment services provider Urenco has broken ground for a new net-zero project at its facility in Almelo in the Netherlands that will recycle waste heat from the enrichment process.
(Image: Urenco)
The company said an internal heat network will provide a contained, thermal energy distribution system, taking residual heat from the cooling of its uranium cylinders. Hot water will be generated and then circulated via insulated pipework throughout multiple buildings on-site to heat them.
The initial phase of the project will see the construction of a heat grid and utility building, with the remaining infrastructure to connect the network across the site being completed at a later date.
Urenco said the project will enable it to significantly reduce its natural gas consumption in Almelo and lower Scope 1 emissions - the result of the direct combustion of fossil fuels by a given company - by about 671 tonnes per year.
The network is expected to be operational by 2029 and is fully aligned with Urenco's 2030 net-zero objectives.
Meanwhile, Urenco said the construction of a new office building at its Almelo site has focused efforts on choosing materials with a lower environmental impact to strengthen overall sustainability. Under Dutch legislation on the Environmental Performance of Buildings (MPG), buildings are given a score reflecting its environmental impact per square meter per year. The use of solar panels, low-carbon concrete, and other sustainable materials resulted in the building being given an MPG score of 0.7 - an improvement of 30% on the legally required score of 1.0 for all new office buildings in the Netherlands.
Furthermore, the building is BREEAM certified, meaning its sustainability has been independently assessed across nine different categories. The building received an Excellent rating, the second-highest possible level in the internationally recognised BREEAM system.
"Together, these measures make the new Almelo office building a leading example of sustainable office design, demonstrating how thoughtful planning, material choice, and construction techniques can significantly reduce environmental impact," Urenco said.
In addition to the Almelo plant, Urenco also operates enrichment facilities in Eunice, New Mexico in the USA, Gronau in Germany, and at Capenhurst in the UK.
Reactor vessel installed at Lufeng 6
The reactor pressure vessel has been hoisted into place at unit 6 of the Lufeng nuclear power plant in China's Guangdong province. It is the second of two HPR1000 (Hualong One) units under construction at the site, where four CAP1000s are also planned.
(Image: CGN)
"At 08:07 (local time) on 21 February, the reactor pressure vessel of unit 6 of Lufeng nuclear power plant officially began hoisting operations and was precisely positioned on the heavy-duty trolley at 09:12, marking the official start of the installation of the first main nuclear island equipment of the unit," China General Nuclear (CGN) announced.
The reactor pressure vessel is the high strength steel cylinder that will house the reactor core and all associated components, including the reactor vessel internals which support and stabilise the core within the reactor vessel, as well as providing the path for coolant flow and guiding movement of the control rods.
"Its installation quality directly affects the long-term safe and stable operation of the power plant," CGN said. "The successful hoisting of the pressure vessel lays a solid foundation for the subsequent installation of main equipment and the advancement of the project for unit 6 of the Lufeng nuclear power plant."
The construction of Hualong One reactors as units 5 and 6 at the Lufeng plant was approved by the State Council in April 2022. First concrete for unit 5 was poured on 8 September 2022, with that for unit 6 following on 26 August 2023. Units 5 and 6 are expected to be connected to the grid in 2028 and 2029, respectively.
The proposed construction of four 1250 MWe CAP1000 reactors (units 1-4) at the Lufeng site was approved by China's National Development and Reform Commission in September 2014. However, the construction of units 1 and 2 did not receive State Council approval until 19 August 2024. The first safety-related concrete for the nuclear island of unit 1 was poured on 24 February last year, with that of unit 2 following in December. Approval for units 3 and 4 is still pending. The CAP1000 design is the Chinese version of the Westinghouse AP1000.
According to CGN, once all six units are in operation, the Lufeng plant will generate about 52 TWh, which will reduce standard coal consumption by almost 16 million tonnes and reduce carbon dioxide emissions by more than 42 million tonnes.
The Trump administration has committed major funding and regulatory reform to accelerate large-scale reactor construction and SMR deployment.
Private-sector investment, including from Japanese conglomerates and U.S. tech giants, is providing financial momentum to the nuclear buildout.
Despite renewed political and financial backing, workforce shortages, supply chain constraints, and historical cost overruns could delay meaningful capacity expansion.
The United States is doubling down on its plans for expanding nuclear power, as one of the few clean energies that President Trump appears to be supporting. Trump has stated ambitious aims for the rapid expansion of the country’s nuclear power capacity, to be supported by both public and private funding. A wide range of projects, from conventional reactor development to the deployment of small modular reactors (SMR), will support this aim. While it will likely take a decade or more to meaningfully grow the nuclear capacity in the U.S., 2026 is looking like the year when the country’s nuclear revival will really take off.
After years of stagnation, the United States is investing heavily in a nuclear renaissance, with the most nuclear projects planned for any decade since the 1970s. In October, the Trump administration committed to a partnership with Westinghouse Electric Company and its co-owners, Brookfield Asset Management and Camec,o to develop a fleet of new, large-scale nuclear reactors with a total value of at least$80 billion.
The funds will go towardsthe development of Westinghouse’s AP1000 pressurised water reactors, which are capable of generating around 1.1 GW of electricity. This type of reactor is currently being used at the Vogtle Nuclear Plant’s units 3 and 4. Due to previous project delays and the high cost of reactor production, private nuclear companies had been unwilling to commit to investing in new reactors. However, the government financing will support the rollout of several new nuclear reactors, with the hope that Westinghouse has learnt from its previous mistakes and that the development of the new reactors will be more streamlined.
In May last year, President Trump signed fourexecutive orders aimed at accelerating the licensing of new reactors and speeding up development, as well as reforming the country’s Nuclear Regulatory Commission (NRC). Trump also announced the aim of developing400 GW of nuclear power by 2050 and to have 10 large reactors under construction by 2030. In November, the NRC responded by publishingregulations on how to put Trump’s orders into action, with the planned removal of redundant and duplicative rules.
The SMR industry is also expected to expand development in 2026, after several years of delays due to licensing hold-ups and a lack of access to enriched uranium, following the Russian invasion of Ukraine and subsequent sanctions on Russian energy.
In July, the Japanese government committed to a$550 billion U.S.-Japan trade agreement, which will support nuclear development. The Japanese companies Mitsubishi Heavy Industries, Toshiba Group, and IHI Corp. have pledged up to $100 billion in investment in the U.S. for the construction of both AP1000s and SMRs.
Meanwhile, it appears that Bill Gates' nuclear company, TerraPower, is edging closer togaining approval for the development of its own fleet of SMRs. The firm hopes to build the Western hemisphere’s first Natrium nuclear reactor in Kemmerer, Wyoming, which would use liquid sodium rather than water to cool the reactor, making it safer and more efficient.
In December, theNRC completed its final safety evaluation, meaning that TerraPower is likely to advance SMR development this year, provided its permit is approved. The firm has already begun to prepare the non-nuclear part of the 44-acre site for development and hopes to be producing between 345 MW and 500 MW of clean power on site by 2030.
In recent months, several tech companies, including Facebook, Instagram, and Meta, havesigned contracts with nuclear power companies to supply the firms with new nuclear energy by the 2030s. This will help the tech companies to justify the rollout of their large-scale data centres by powering them with new clean energy. It will also help the tech companies to stay on the path to achieving their climate goals. The high levels of financing pledged by the tech majors will help nuclear energy firms to accelerate the development of new conventional reactors and SMRs, pending NRC approval.
However, to support the acceleration of the nuclear renaissance, staff training will be required to develop the nuclear power workforce, both for construction and the running of nuclear operations. In recent years, there has not been enough work in the sector to provide ongoing employment for trained professionals, meaning that many workers from Vogtle have since transitioned to other energy sectors.
In addition, following thestagnation of the nuclear power sector in recent years, it will likely take several years for the U.S. to once again develop its nuclear plant construction skills, drive down costs, and avoid delays. While other countries have been expanding their nuclear capacity, the U.S. has lost its competitive edge in nuclear development. Therefore, while 2026 may be the most promising year for the United States nuclear revival to date, it will likely still take several years to expand the country’s nuclear power capacity to anywhere near Trump’s aims.
By Felicity Bradstock for Oilprice.com
UK Consortium Proposes Floating Nuclear Plant for U.S. Military
An international consortium headed up by a British firm is pitching a proposal to the Pentagon to build a ship-borne nuclear power station, to be docked at a naval facility.
The concept seeks to exploit the nuclear regulatory environment enjoyed by the department, which has extensive experience of using small nuclear reactors afloat and well-established protocols which would enable a deployment far faster than civilian nuclear power plants can be built in most countries.
The Pentagon has an interest in facilitating such an endeavor, because AI and data centers on which the department depends cannot get access fast enough to the additional power sources needed to power them through the national power grid. The floating power station could be connected directly to a data center from the dockside, or into the national power grid for offtake elsewhere. Once grid supply catches up with local demand in the area being served, then the floating power station could be moved to an alternative location – even in another country in need of a power boost, for example in the aftermath of a natural disaster. So long as the vessel does not transport cargo between U.S. points in the course of its operations, the hull could be built overseas at reduced cost without triggering the requirements of the Jones Act.
The consortium led by Core Power brings together Terrapower, a US mini-rector start-up backed by Bill Gates; Japanese and Korean shipbuilders; and the French parastatal nuclear fuel company Orano, with fit-out to be completed in the United States. The consortium is aiming to use an existing shipborne nuclear reactor design initially, with an output of 300MW.
There should be a range of existing reactors to choose from: Nimitz Class aircraft carriers each have two 550MW reactors, and the output of the Rolls Royce PWR2 submarine design in service is estimated to be 150MW. These reactors are designed to run on weapons-grade uranium, which creates a security challenge for fuel handling and storage. Modern French naval reactor designs run on low-enriched uranium, like typical civilian reactors, and thus have less restrictive security requirements – but they require more frequent refueling, and the technology is subject to stringent export controls.
The Pentagon response to the multinational proposal is unclear. But in May 2025, the White House issued an order requiring the department to deploy an advanced nuclear reactor at military base before the end of the Trump administration’s second term.
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