Energy Weekly Review 2026-05-29

Week In Review

This week’s developments traced the full arc of a low-carbon energy system, from the fuel that goes in to the machines that burn it and the grid that moves the result. On the nuclear side, the United States moved on two ends of the fuel cycle at once: the Nuclear Regulatory Commission accepted Orano’s Project Ike enrichment plant for an accelerated review, aiming to rebuild domestic enrichment capacity, while the Department of Energy opened negotiations to turn surplus weapons plutonium into advanced-reactor fuel. Meanwhile, Commonwealth Fusion Systems completed the steel vacuum vessel for its SPARC tokamak, crossing the 75%-built mark on a machine meant to demonstrate net energy gain in 2027. Fuel supply and fusion hardware are the unglamorous prerequisites that determine whether the headline ambitions of the decade are actually buildable.

Grid storage continued its shift from a lithium monoculture toward chemistry diversity and very large deployments. Inlyte Energy advanced its iron-sodium long-duration batteries aimed squarely at data centers, pitching an abundant-materials, non-flammable alternative to both diesel backup and lithium-ion. At utility scale, the Ameresco–Atura joint venture brought a 250 MW / 1,000 MWh battery online in Ontario, and Contact Energy switched on its first grid-scale battery at a New Zealand steel mill. The common thread is that storage is no longer a demonstration category; it is firm capacity being procured through tenders and paired with both nuclear baseload and heavy industry.

On the generation and fuels front, the cost curve kept bending. TotalEnergies filed for authorization of a 1.5 GW offshore wind project off Normandy, and analysts projected that China’s solar capacity will overtake coal for the first time in 2026. Two laboratory breakthroughs attacked the stubborn cost of green hydrogen from opposite directions: a Washington University team replaced precious-metal catalysts in membrane electrolyzers, while a University of Hong Kong group engineered a corrosion-resistant steel that could make seawater electrolysis affordable.

If a single demand signal connects these stories, it is the surge in firm, around-the-clock power required by AI data centers. Inlyte is explicitly targeting that market; the advanced-reactor fuel and enrichment moves underpin the nuclear buildout that hyperscalers are bankrolling; and the storage deployments are what make variable wind and solar dispatchable enough to serve loads that never sleep. The week was less about any one breakthrough than about the simultaneous maturation of every layer in the stack.

Items

Commonwealth Fusion Systems Completes SPARC’s Vacuum Vessel, Reaching 75% Build

Commonwealth Fusion Systems lowered the second 48-ton half of SPARC’s vacuum vessel into place at its Devens, Massachusetts campus this week, completing the roughly 96-ton steel chamber that will eventually contain plasma heated to around 100 million degrees Celsius — several times hotter than the core of the Sun. With the vessel finished, the company reports the overall machine is now about 75% built, marking the transition from major-component fabrication to final assembly.

SPARC is a compact tokamak whose central bet is that high-temperature superconducting magnets, which CFS spun out of MIT research, can confine fusion plasma in a machine far smaller and cheaper than legacy designs like the international ITER project. The vacuum vessel is the heart of that machine: a sealed, ultra-clean steel chamber held at near-vacuum so that injected hydrogen fuel can be heated and magnetically squeezed without contamination. CFS has already installed the first of eighteen D-shaped toroidal field magnets that will wrap around the vessel to cage the plasma.

The company is targeting first plasma and the start of operations in 2027, with the central goal of demonstrating net energy gain — the long-sought threshold, denoted Q greater than 1, at which a fusion reaction releases more energy than is pumped in to sustain it. No tokamak has yet crossed that line in a commercially relevant configuration. SPARC is explicitly a demonstration machine rather than a power plant; its successor, ARC, is intended to actually deliver electricity to the grid in the early 2030s.

What makes the milestone notable is its tempo. Fusion has a long history of receding timelines, but the past two years have seen private developers convert capital into physical hardware on schedules measured in months rather than decades. Whether SPARC achieves Q greater than 1 on its first attempts or not, completing the vessel on a public timeline is the kind of concrete, falsifiable progress the field has historically lacked.

Source: Commonwealth Fusion Systems

NRC Accepts Orano’s Project Ike Enrichment Plant for Accelerated Review

The U.S. Nuclear Regulatory Commission accepted Orano’s license application for its proposed Project Ike uranium enrichment facility in Oak Ridge, Tennessee, committing to an accelerated 12-month review with a target completion date of April 30, 2027. The acceptance, which the company announced on May 21, moves one of the largest proposed industrial investments in Tennessee’s history past an early procedural hurdle.

According to Orano, the plant would sit on a 624-acre parcel of former Manhattan Project land recently transferred from the federal government to the city of Oak Ridge, and the roughly 750,000-square-foot facility is projected to create more than 1,000 construction jobs and 300 permanent positions. The design draws on Orano’s centrifuge enrichment experience at its Georges Besse 2 plant in France, which already supplies enriched uranium to American reactors.

The strategic logic is supply-chain security. The United States retired most of its domestic enrichment capacity decades ago and has relied heavily on imports — including, until recently, a substantial share from Russia. Rebuilding domestic enrichment is widely seen as a precondition for the advanced-reactor buildout now underway, since many next-generation designs require fuel enriched to higher levels than the legacy fleet uses, and that fuel cannot be sourced at scale without new facilities like this one.

A 12-month NRC timeline is itself a signal. Licensing reviews for nuclear facilities have historically stretched for years, and the commission’s stated intent to move faster reflects a broader policy push to compress regulatory timelines without abandoning safety review. Construction approval is not guaranteed, and the project still faces environmental review and financing milestones, but acceptance for an accelerated review is a meaningful step toward closing a gap that has constrained the entire domestic nuclear sector.

Source: World Nuclear News

DOE Opens Talks to Turn Surplus Weapons Plutonium into Advanced-Reactor Fuel

The Department of Energy has selected the advanced-reactor company Oklo and four other firms to begin advanced negotiations over access to its Surplus Plutonium Utilization Program, according to reporting this week. If the arrangements are finalized, private companies would for the first time gain access to surplus weapons-grade plutonium to fabricate fuel for advanced reactors.

The premise is to treat a Cold War liability as a resource. The United States holds a large inventory of surplus plutonium from dismantled weapons that must otherwise be dispositioned at considerable cost. Several advanced-reactor designs — particularly fast reactors that operate on a different neutron spectrum than conventional light-water plants — can use plutonium-bearing fuel, which would convert a costly stockpile into a usable energy feedstock and shrink the disposal burden in the process.

The approach is not without controversy, and handling weapons-origin material carries obvious security and nonproliferation considerations that any final agreement would have to address. Those safeguards, and the chain-of-custody requirements around such material, are part of what the negotiations must resolve. The selection of multiple companies rather than a single recipient suggests DOE is testing several deployment models in parallel.

For the advanced-reactor sector, the appeal is fuel certainty. The same enrichment bottleneck that motivates projects like Orano’s Oak Ridge plant means that any alternative fuel pathway is valuable to developers trying to lock in supply for first-of-a-kind reactors. Repurposing surplus plutonium would not replace commercial enrichment, but it could help bridge the early years of a fleet that is being built faster than the fuel infrastructure around it.

Source: CNN

Inlyte Energy Advances Iron-Sodium Long-Duration Batteries for Data Centers

Inlyte Energy, a California-based startup, is moving its iron-sodium battery technology toward two pilot deployments in 2026, positioning the chemistry as a safe, long-duration backup option for the fast-growing data center market. The company is pitching its systems as an alternative to both the diesel generators that traditionally provide data-center backup power and the lithium-ion batteries increasingly used for grid storage.

Inlyte’s chemistry belongs to the sodium-metal-halide family — a high-temperature design using iron and sodium, both cheap and abundant, rather than the lithium, cobalt, and nickel that dominate today’s cells. The pitch is durability and safety: the chemistry is non-flammable and tolerant of deep, repeated cycling, which suits the multi-hour discharge profiles that lithium-ion handles less economically. Among the planned projects, the company has described a 600 kWh pilot with Swiss operator NTS Colocation at a high-reliability data center in Bern, Switzerland, slated for the end of 2026.

The data center angle matters because of where electricity demand is growing fastest. AI training and inference workloads are driving unprecedented load growth, and operators need power that is both firm and resilient. Batteries that can ride through multi-hour outages without fire risk — and without the emissions and maintenance of diesel — are attractive if the economics hold.

Iron-sodium and related long-duration chemistries remain earlier in their commercialization than lithium-ion, and pilot-scale deployments are exactly the stage where real-world cost and reliability get tested. But the broader trend is unmistakable: storage is diversifying away from a single chemistry as different duration needs — seconds, hours, and days — pull the market toward purpose-built designs.

Source: pv magazine

Ameresco–Atura Bring 250 MW / 1,000 MWh Ontario Battery Online

The Napanee battery energy storage system in Ontario, a 250 MW / 1,000 MWh installation developed by a joint venture involving Ameresco and Atura Power, has begun commercial operations. Ontario’s Minister of Energy and Mines, Stephen Lecce, announced the milestone on May 19; the project reportedly came in on budget and roughly five weeks ahead of schedule.

At a four-hour duration and a billed value of about CA$600 million (roughly US$435 million), Napanee is among the larger battery deployments in Canada. It comprises 284 battery storage units alongside transformer stations and transmission connection facilities. Atura Power, a subsidiary of the provincially owned Ontario Power Generation, developed the project, while Ameresco holds a roughly 10% stake and contracted to provide engineering and construction services.

The project’s operating logic is a neat illustration of how storage complements a low-carbon grid. Ontario draws heavily on nuclear generation, which runs most efficiently at a steady output rather than ramping up and down with demand. The battery charges on inexpensive surplus power during low-demand periods and discharges when demand climbs — effectively time-shifting firm nuclear energy to match the daily load curve, and reducing the need to fire up gas peakers at the margin.

Napanee originated in the 2023 Independent Electricity System Operator long-term procurement, which awarded a record volume of storage contracts in the province, and the venture is already proposing a much larger second phase at the same site. The progression from competitive tender to on-budget, ahead-of-schedule commissioning is the kind of execution that turns policy targets into delivered capacity.

Source: Energy-Storage.News

Contact Energy Switches On Its First Grid-Scale Battery at a New Zealand Steel Mill

Contact Energy has brought online its first grid-scale battery energy storage system, a 100 MW / 200 MWh installation at New Zealand Steel’s Glenbrook site in South Auckland. Named the Glenbrook Ohurua Battery 1, the system is built from 56 Tesla Megapack 2XL units and can respond to grid signals in roughly 0.2 seconds.

The two-hour battery is designed to do several jobs at once — storing surplus renewable energy during off-peak periods, discharging rapidly when demand spikes, and providing the fast frequency response that helps stabilize a grid as it takes on more variable wind and solar. Contact Energy’s chief executive, Mike Fuge, likened the system to “the Swiss Army Knife of the electricity system,” capturing the way modern grid batteries stack multiple revenue and reliability services onto a single asset.

Siting the battery at a steel mill is significant in itself. Heavy industry represents large, steady electrical loads and existing high-capacity grid connections, making industrial sites attractive locations for storage that can both serve the host facility and provide services back to the wider system. New Zealand’s grid is already heavily renewable — dominated by hydro, geothermal, and wind — which makes fast-responding storage especially valuable for smoothing the variability that the country’s growing wind fleet introduces.

For Contact Energy, one of the country’s largest generators and retailers, the Glenbrook battery is a first move into a category it intends to expand. As hydro-dominated systems push toward fully renewable operation, the binding constraint shifts from energy to flexibility — the ability to absorb and release power on demand — and grid batteries are the most readily deployable answer.

Source: Energy-Storage.News

TotalEnergies Files for Authorization of 1.5 GW Centre Manche Offshore Wind Farm

TotalEnergies filed for authorization of its Centre Manche Energies offshore wind project, a roughly 1.5 GW development sited off the coast of Normandy that the company describes as among the largest renewable energy undertakings in France. The filing is a formal milestone in the multi-year permitting process that precedes construction of a project of this scale.

At 1.5 gigawatts, the project would rank among the larger offshore wind farms anywhere — enough nameplate capacity to power on the order of a million-plus homes, depending on the turbines and capacity factors ultimately deployed. Offshore wind off the French Atlantic and Channel coasts benefits from strong, consistent winds and high water depths that increasingly favor large modern turbines, and the Centre Manche zone has been designated by French authorities for offshore development as part of the country’s renewable expansion.

For TotalEnergies, a company historically anchored in oil and gas, the filing is another marker of a deliberate pivot into electricity and renewables. Major European energy companies have been reallocating capital toward offshore wind, solar, and storage, betting that integrated power businesses — generation paired with trading and retail supply — will be the growth engine of the coming decades even as legacy hydrocarbon demand persists.

Permitting remains the long pole in offshore wind: authorization, environmental review, grid connection agreements, and final investment decision can take years before steel goes in the water. But moving a gigawatt-scale project into the formal authorization phase is a concrete commitment, and it adds to a European offshore pipeline that continues to expand despite the cost and supply-chain pressures the sector has navigated in recent years.

Source: TotalEnergies

China’s Solar Capacity Set to Overtake Coal for the First Time

Analysts project that 2026 will be the year China’s installed solar capacity surpasses its coal capacity for the first time, a symbolic inflection point for the world’s largest energy consumer and emitter. By some estimates, cumulative solar capacity will exceed 1.38 terawatts — on the order of 150 gigawatts more than coal — though capacity and actual generation are distinct measures, and coal still produces a larger share of China’s electricity because it runs at higher utilization.

The scale of recent additions explains the crossover. In 2025 alone, China installed a record of roughly 315 GW of solar and 119 GW of wind, which together accounted for over 80% of all new capacity added that year. That single-year solar figure exceeds the total installed solar capacity of most countries, and it reflects both the country’s dominant position in panel manufacturing and a domestic price environment that has made deployment extraordinarily cheap.

The transition remains genuinely mixed rather than triumphant. Even as renewables surged, China added a substantial amount of new coal and gas capacity in 2025, and many coal plants now run at a loss as cheap solar and wind undercut them in daytime hours. Under current policy guidance, coal is expected to shift toward a more limited role — increasingly serving as a flexible “peaker” that meets demand spikes and covers gaps when wind and solar fall short, rather than providing bulk baseload.

The significance for the rest of the world is partly about cost and partly about trajectory. China’s manufacturing scale has driven global solar prices to historic lows, accelerating deployment everywhere. And the capacity crossover, even with all its caveats, marks the point at which the largest energy system on Earth tips structurally toward renewables — with storage and grid flexibility, the themes running through the rest of this week’s items, as the determining factors for how fast generation follows capacity.

Source: Yale Environment 360

Washington University Catalyst Lowers the Cost of Green Hydrogen

Researchers at Washington University in St. Louis reported a new catalyst for anion-exchange membrane water electrolyzers (AEMWE), a class of device that uses renewable electricity to split water into hydrogen and oxygen. The advance targets one of the central cost drivers in green hydrogen: the expensive platinum-group metals that conventional electrolyzers rely on to accelerate the water-splitting reaction.

Electrolyzers are the linchpin of “green” hydrogen — hydrogen made from water and clean electricity rather than from natural gas. The dominant commercial technology, proton-exchange membrane electrolysis, depends on scarce precious metals like platinum and iridium, whose cost and limited supply constrain how cheaply and how widely the technology can scale. Anion-exchange membrane electrolyzers operate in an alkaline environment that, in principle, allows cheaper and more abundant materials to do the same job, but matching the performance and durability of the precious-metal systems has been the long-standing challenge.

The Washington University work focuses on a catalyst designed to deliver competitive activity without the precious-metal price tag. If such catalysts prove durable at scale, they would attack the capital cost of hydrogen production directly — the electrolyzer stack is a major share of a project’s expense — and help push green hydrogen toward the cost thresholds at which it becomes competitive for industrial uses like steelmaking, ammonia, and long-duration energy storage.

Laboratory catalyst results have a long road to commercial electrolyzers, and durability under industrial operating conditions is where many promising materials falter. But the direction of travel is consistent: a steady stream of advances aimed at stripping precious metals out of the hydrogen supply chain, lowering the floor on what clean hydrogen can ultimately cost.

Source: ScienceDaily

A New Stainless Steel Could Make Hydrogen from Seawater Affordable

A team at the University of Hong Kong, led by Professor Mingxin Huang, has developed a specialized stainless steel — designated SS-H2 — that resists corrosion under the brutally aggressive conditions of seawater electrolysis, conditions that normally degrade ordinary stainless steel rapidly. The researchers report that the material could enable seawater electrolyzers at a fraction of the cost of those built with corrosion-proof but expensive metals like titanium.

The appeal of splitting seawater is straightforward: fresh water is a constrained resource in many of the sunniest, windiest places best suited to renewable hydrogen production, and the oceans are effectively limitless. The problem is chemistry. Seawater is laden with chloride ions that attack metal components and trigger destructive side reactions, which is why most electrolyzers are designed for purified water and why seawater-tolerant hardware has historically required costly materials.

SS-H2’s reported corrosion resistance — described as dramatic enough to surprise the researchers — would let engineers build seawater electrolyzers from a steel that is far cheaper than titanium while still surviving the chloride-rich environment. By the team’s account, the cost advantage over titanium components is roughly fortyfold, which would remove one of the significant capital barriers to coastal and offshore hydrogen production.

Like any new structural material, SS-H2 will need to prove itself over the long service lifetimes that industrial electrolyzers demand, and scaling steel production with the required properties is its own engineering challenge. But it is a clarifying example of how progress in hydrogen often comes not from the electrochemistry alone but from the unglamorous materials science that determines whether a clean process can be built cheaply and run for decades.

Source: Fuel Cells Works