Google signed a long-term deal to buy electricity from Constellation Energy, the biggest owner of nuclear power plants in the United States. The total is roughly what three large nuclear reactors produce.
The surprise: only about a quarter of it is described as new power that does not exist today. The companies have not said whether the rest is new.
That matters because the giant computer buildings that run artificial intelligence are straining the power grid across a large part of the eastern United States. New plants add electricity for everyone. Buying power that already exists mostly changes who gets it.
Google has entered a long-term power agreement with Constellation Energy that Reuters reported totals 3.6 gigawatts (GW), a gigawatt being a thousand megawatts, or roughly the output of one large nuclear reactor. Google’s announcement says the agreement will bring 890 megawatts (MW) of new nuclear capacity to the PJM grid, the regional power system covering the Mid-Atlantic and parts of the Midwest. Bloomberg, which reported the talks before the announcement, put the deal’s value at roughly $1 billion or more.
Executive Summary
The headline number is 3.6 GW, which makes this one of the larger power agreements a technology company has signed for its data centers. But Google’s own framing singles out a smaller figure: 890 MW of new nuclear capacity on PJM. That is about a quarter of the total. The companies have not described the remaining roughly 2.7 GW as new supply.
The distinction matters because data centers built for artificial intelligence (AI) are adding electricity demand faster than grid operators are adding generation, and PJM is where that pressure is most visible. New capacity increases the amount of power the grid can deliver to everyone. A contract for output from plants that already run changes who is credited with that power, but does not, on its own, add megawatts to the system.
So the useful question about this deal is not how large it is, but how much of it is additive. On current disclosures, the answer is 890 MW, with the composition of the rest still unexplained.
The 890 MW Is the Only Slice Labeled as New Supply
Subtract the new nuclear capacity from the total and roughly 2.7 GW of the 3.6 GW agreement remains without a public description. If that remainder is drawn from reactors already running and already selling into the grid, it is a reassignment: the same electrons are produced, but a contract now ties their output, or the clean-energy credit attached to it, to Google rather than to the open market. Energy analysts call the difference ‘additionality’, meaning whether a purchase causes new generation to exist that would not otherwise have been built.
The 890 MW is different in kind. Whether it comes from upgrading existing reactors to produce more power (known as ‘uprates’), restarting idle capacity, or something else, the companies describe it as new, which means it should expand what PJM can actually supply once it comes online. For the utilities, data center developers and households that share that grid, the 890 MW is the part of this deal that eases supply. The rest primarily determines who holds a claim on supply that was already there.
That is why the 890 MW, not the 3.6 GW, is the operationally meaningful number. It is the portion that shows up as added capacity in grid planning, and it is the portion other large power buyers on PJM will feel.
Why PJM Is Where Additionality Matters Most
PJM Interconnection coordinates wholesale electricity for 13 states and Washington, D.C., and its territory includes Northern Virginia, the densest concentration of data centers in the world. PJM runs an auction that pays power plants to commit capacity years in advance, and prices in recent auctions rose sharply as forecasts of data center demand climbed. Meanwhile, new generators wait in an ‘interconnection queue’, the line of projects seeking permission to connect to the grid, which has been slow to clear.
In that setting, contracts that lock up existing output for one large buyer can tighten the market for everyone else, because the total available supply does not change while one claimant’s share does. Co-location arrangements involving existing nuclear plants in PJM have already drawn regulatory scrutiny over who pays for grid services. A deal anchored in new capacity sidesteps much of that argument, which may be one reason Google’s announcement leads with the 890 MW figure.
The Case for Contracting Existing Nuclear Output
Reassignment is not worthless, and it is fair to say so. Long-term contracts give a plant owner price certainty, which can justify the spending needed to extend a reactor’s licensed life or fund the very uprates that create new capacity. A reactor kept online through a contract is supply the grid does not lose. For Google, which has set a goal of running on carbon-free energy around the clock by 2030, contracted nuclear output also supports that target in a way intermittent wind and solar cannot fully match.
Constellation has used this model before, with Microsoft for the restart of a reactor at the former Three Mile Island site, now called the Crane Clean Energy Center, and with Meta for output from its Clinton plant in Illinois. The pattern suggests technology companies are willing to pay a premium for firm, carbon-free power, and that Constellation can convert that willingness into investment in its fleet. The open question is how much of each contract funds new megawatts versus securing existing ones, and this deal is the clearest case yet where the split is visible in the headline numbers.
What the $1 Billion Figure Cannot Yet Explain
Bloomberg’s figure of roughly $1 billion or more has not been broken down publicly. It is unclear whether it represents total contract value, annual spending, or capital tied specifically to the new capacity. Without a contract length or price per megawatt-hour, readers cannot judge whether Google is paying a premium for new supply, a market rate for existing output, or a blend.
That matters to investors comparing Constellation’s tech-sector contracts, and to other buyers trying to benchmark what firm, carbon-free power now costs on PJM. Until the companies disclose more, the dollar figure is best read as a signal of scale rather than a basis for valuation.
Background
Technology companies have become some of the largest buyers of electricity in the United States as they build data centers to train and run AI models. Nuclear power is attractive to them because it runs around the clock without carbon emissions, unlike wind and solar, which vary with the weather. Google has set a goal of matching its electricity use with carbon-free energy every hour of every day by 2030, and has previously signed a deal for future small modular reactors with Kairos Power.
Constellation Energy, spun off from Exelon in 2022, owns the largest fleet of nuclear plants in the country, much of it inside PJM. It has signed long-term agreements with Microsoft and Meta, making it a central player as AI-driven demand collides with a grid that is slow to add new generation.
The American government is reportedly backing about $4 billion in loans for nuclear power plants owned by Vistra, a Texas power company. Its shares recovered from the day’s lows on the news.
Why it matters: the computer warehouses that run artificial intelligence need huge amounts of electricity around the clock, and nuclear plants are one of the few sources that run day and night. Vistra recently paid about 7% interest to borrow $1.5 billion from investors. Government-backed loans usually cost less, and if things go wrong, the government carries more of the risk.
The Trump administration plans to back roughly $4 billion in loans for Vistra Corp.’s nuclear facilities, GuruFocus and Investing.com reported, and Vistra shares (NYSE: VST) recovered from their session lows on the news. Vistra, based in Irving, Texas, owns four nuclear plants: Comanche Peak in Texas, Beaver Valley in Pennsylvania, and Davis-Besse and Perry in Ohio.
The reported backing arrives days after a separate, market-priced financing. In an 8-K filed September 24, Vistra said its subsidiary Vistra Operations Company LLC completed a $1.5 billion offering of junior subordinated notes due 2057: $850 million at 7.000% and $650 million at 7.250%, guaranteed by Vistra.
Executive Summary
A federal loan or loan guarantee changes who absorbs the downside if a borrower cannot repay. For Vistra, the reported $4 billion in federal backing would put the government, rather than bond investors, in the lender’s seat on a meaningful slice of nuclear-related financing. The specific plants, uses, interest rate and term have not been publicly detailed.
The comparison point is Vistra’s own recent borrowing. The company’s September 24 filing shows it paid 7.000% and 7.250% on 31-year junior subordinated notes, which is debt that ranks behind its other obligations. Federally backed debt is generally priced much closer to the government’s own borrowing costs. That spread is the economic value of the backing, and it matters because nuclear power is a business where the cost of capital dominates the cost of output.
That is why the story reaches beyond one utility. Existing reactors are among the few sources of firm, around-the-clock, carbon-free power that large data-center operators are signing long-term contracts for. Cheaper capital for those plants makes such contracts easier to price. Whether the benefit flows to power buyers, shareholders or both is still an open question.
What Federal Backing Actually Moves
When the government lends money directly or guarantees a private loan, it takes on the credit risk. That is the chance the borrower fails to repay. In a normal bond deal, that risk sits with investors, and they price it into the interest rate. Vistra’s September 24 8-K shows what that price looks like today: $1.5 billion of junior subordinated notes at 7.000% and 7.250%, maturing in 2057. “Junior subordinated” means these holders are paid after nearly every other creditor if things go wrong. Markets often call this kind of long-dated, low-ranking debt “hybrid” capital, and investors demand a premium for it.
Federal backing works the other way. The lender of record is effectively the Treasury, or private lenders protected by it. Rates on that debt are typically set off government borrowing costs rather than off a company’s credit rating. On the reported $4 billion, then, the risk of non-repayment moves from bondholders to the public balance sheet. The size of the saving to Vistra depends on terms that have not been made public. But the direction is clear, and the scale, at well over twice the hybrid offering, is material.
Several groups are affected. Vistra shareholders gain cheaper funding for capital-heavy nuclear work. Existing creditors may see a stronger overall position, or more senior claims ahead of them, depending on structure. Taxpayers take on a contingent exposure. And customers buying nuclear output could get a lower price if the savings are passed through.
Why Nuclear Capital Costs Flow Into AI Power Prices
A nuclear plant’s fuel is a small share of its cost. The large items are the capital spent to build, maintain, extend the licence of, or uprate the plant (squeeze more megawatts from the same reactor). When a generator signs a 15- or 20-year contract to sell that output, the price has to recover that capital plus a return. A lower financing rate therefore lowers the break-even price on the investment behind the contract. That is the mechanism by which a federal loan can make firm nuclear output cheaper to underwrite.
This matters for AI infrastructure because large data-center operators want electricity that runs 24 hours a day and carries no carbon emissions. Few sources deliver both. Vistra has already signed long-term agreements to sell nuclear output to large technology buyers. Its reactors are existing assets with operating histories. That makes them a lower-risk lending target than new construction, which helps explain why public lenders are willing to step in here first.
The interpretation has a limit. The reports do not say the backed loans are tied to any data-center contract, and the plants serve the wider grid as well. The defensible claim is narrower: whatever the money funds, it lowers the cost of capital on a fleet whose output is now priced partly by AI demand.
Two Financing Tracks at Once
Within the span of weeks, Vistra raised money on two very different terms. One is the $1.5 billion market offering. Barclays, BofA Securities, Mizuho, MUFG and Truist led the underwriting, and investors accepted subordinated status in exchange for a coupon above 7%. The other is the reported federal backing. A company with access to both will naturally route its longest-lived, most capital-intensive projects to the cheapest source. Nuclear is the clearest example of that kind of asset.
The share-price reaction should be read cautiously. A recovery from intraday lows says the market welcomed the news, but it does not reveal how investors valued the terms, which were not disclosed. The more durable signal will come when the loan’s rate, seniority and covenants become public.
The Case For and Against Public Support Here
Supporters of federal nuclear lending argue that keeping existing reactors running, and expanding them, is the fastest way to add firm, low-carbon supply to a grid facing rising demand. They also argue that loans, unlike grants, are expected to be repaid with interest. The government has used this tool before for existing plants, including support tied to the Palisades plant in Michigan.
Critics raise fair questions too. Vistra is a profitable, investment-market-funded company, and some of the eventual buyers of its output are among the best-capitalized firms in the world. That raises the question of whether public credit is needed, or whether it mainly improves returns that private markets would have financed anyway. The answer depends on details not yet public: what the money funds, whether it adds new capacity, and what conditions come attached. Both arguments should be tested against those terms when they appear.
Background
Vistra emerged in 2016 from the bankruptcy of Energy Future Holdings, the former parent of Texas utility TXU. It has since grown into one of the largest competitive power generators in the United States. Its 2024 acquisition of Energy Harbor added three nuclear plants in Ohio and Pennsylvania to its Comanche Peak plant in Texas. That made nuclear a central part of a business that also includes gas, coal, solar, batteries and retail electricity sales.
Nuclear plants have become strategically valuable as data-center demand grows, because they deliver steady, carbon-free power regardless of weather. Federal lending programs have previously supported keeping or returning existing reactors to service. The reported Vistra backing extends that public-financing approach to a large operating fleet, alongside the company’s own market borrowing.
Amazon has signed a 20-year deal to buy about a third of the electricity from Calvert Cliffs, Maryland’s only nuclear power plant, which today produces enough for more than 1.3 million homes. The plant’s owner, Constellation Energy, says the deal unlocks more than $3 billion of investment.
The twist: most of that power already exists. Just over a quarter of Amazon’s share will come from new equipment, due between 2030 and 2032. The plant’s two reactors have federal operating licenses that expire in 2034 and 2036, long before the contract ends. The power also stays on the shared grid rather than being walled off for Amazon.
Constellation Energy and Amazon signed a 20-year agreement on Sept. 30, 2026 under which Amazon will buy 690 megawatts (MW) of output from the Calvert Cliffs Clean Energy Center in Maryland, Mugglehead Investment Magazine reported. The 690 MW includes a planned 190 MW capacity increase at the 1,790 MW station, expected to come online between 2030 and 2032. Constellation says the agreement is expected to enable more than $3 billion in Maryland infrastructure investment.
Amazon said electricity from Calvert Cliffs will continue flowing to the PJM regional grid. The companies also signed a separate retail supply agreement covering Amazon operations across PJM’s 13 states and the District of Columbia. Constellation did not disclose a price per megawatt-hour or a spending schedule for the investment.
Executive Summary
Amazon, one of the hyperscalers (the largest cloud and AI computing operators), has committed to two decades of nuclear power from Maryland’s only nuclear plant. The contract covers 690 MW, roughly a third of the station’s output once a planned 190 MW uprate is complete. Constellation ties the deal to more than $3 billion of state investment, to relicensing the plant for another 20 years, and to potential new clean energy plants at the site.
The deal is less about new megawatts than the headline suggests. About 500 MW of the contract comes from reactors already running, and the new 190 MW will not arrive until 2030 to 2032. The larger consequence is financial: a 20-year revenue stream for a station whose two reactor licenses expire in 2034 and 2036 strengthens the case for keeping all 1,790 MW running into the 2050s. The structure matters too. The plant stays connected to the shared grid instead of being dedicated to an Amazon campus built on site.
What remains open is the economics. There is no disclosed price, start date, investment schedule, or relicensing application date. Constellation has also named no design or budget for the new plants it says the deal will help advance.
Most of the 690 Megawatts Already Exists
A megawatt measures generating capacity. Calvert Cliffs’ current 1,790 MW supplies the equivalent of more than 1.3 million homes and about 80 per cent of Maryland’s clean energy, by Constellation’s count. Amazon’s 690 MW contract includes the planned 190 MW increase, so roughly 500 MW of it is output from reactors that are already operating. The 190 MW is an uprate, meaning engineering changes that let existing reactors produce more power. It is not a newly ordered reactor.
For anyone modeling new electricity supply for data center growth in PJM, the timing is the point. In the near term, the deal assigns existing carbon-free output to a named buyer. The net addition to the grid, about a tenth more capacity at the station, arrives between 2030 and 2032.
Amazon’s earlier PJM nuclear agreement follows a similar pattern. Talen Energy’s June 11, 2025 contract covers 1,920 MW from the existing Susquehanna plant in Pennsylvania, reaching full quantity no later than 2032 and running through 2042. Talen treats any extra output from uprates as a separate possibility. Two contracts with one buyer do not make a market-wide trend. Still, both of Amazon’s disclosed PJM nuclear deals are anchored on reactors that already exist, with new capacity small or optional.
Why the 2034 License Date Is the Bigger Stake
The U.S. Nuclear Regulatory Commission (NRC) lists Unit 1’s operating license as expiring July 31, 2034 and Unit 2’s as expiring Aug. 13, 2036. Both licenses were renewed in 2000. A 20-year contract signed in 2026 runs into the mid-2040s at the earliest. If deliveries begin soon after signing, more than half of the term falls after Unit 1’s current license ends. The contract can be fully performed only if the NRC grants subsequent license renewal. That process extends reactor operation from 60 to 80 years and requires its own safety and environmental reviews.
The arithmetic shows where the stake lies. The uprate adds 190 MW. Operation beyond the mid-2030s depends on relicensing for all 1,790 MW, more than nine times as much capacity. Constellation says the agreement helps provide the revenue certainty needed to relicense the plant for another 20 years. That is the mechanism: long-dated contracted revenue is what justifies the cost of a renewal application and the plant investment that goes with it. “Amazon’s commitment supports the long-term operation of Calvert Cliffs for generations to come,” chief executive Joe Dominguez said.
Several parties depend on that outcome. Amazon needs the plant running to receive its contracted supply. Maryland gets most of its clean electricity from this one station. PJM would lose far more capacity if the plant closed than the uprate adds. A power sale does not renew a license, though, and Constellation has given no date for an application. The deal’s most consequential effect is a stronger financial case for keeping the station open. The regulatory decision is still years away.
A Hyperscaler Pays for Nuclear Without Taking It Off the Grid
Amazon said Calvert Cliffs’ electricity will keep flowing to PJM, the operator of the regional grid serving 13 states and Washington, D.C. That footprint includes Northern Virginia, the world’s largest data center market. The main alternative is co-location, in which a data center is built at the plant and draws power directly, “behind the meter,” before it reaches the grid. Co-location has drawn regulatory scrutiny in PJM over its effect on other customers.
Calvert Cliffs instead uses what the industry calls a grid-side power purchase agreement (PPA), a long-term contract to buy a plant’s output. The plant sends its electricity into the grid, and Amazon’s facilities are served through a separate retail supply agreement. Under a structure like this, the buyer underwrites the plant’s revenue while its output stays available to the regional system. That reduces the friction co-location attracts.
The trade-off is that Amazon’s sites still depend on the grid’s ability to deliver power where its data centers are located. The nuclear contract secures a source of electricity, but it does not settle questions of local grid connections or transmission capacity.
The $3 Billion Figure Still Needs a Schedule
Constellation says the deal will “enable” more than $3 billion of Maryland investment. That figure is not described as Amazon’s direct spending, and no spending timeline was given. It is also unclear how the sum divides among the uprate, relicensing work, and the potential new clean energy plants, for which Constellation named no design, equipment order, budget, or completion date.
Without a price per megawatt-hour, outside observers cannot compare the contract with market power prices or judge how much of the plant’s future revenue it locks in. Constellation’s shares rose after the announcement, which suggests investors value the long-term revenue certainty. Overall, the announcement is concrete on duration, volume, and the uprate window, and thin on economics.
Background
Constellation Energy, spun off from Exelon in 2022, operates the largest fleet of nuclear plants in the United States. Calvert Cliffs, on Maryland’s Chesapeake Bay shore, has two reactors totaling 1,790 MW. The company is also working to restart an 835 MW reactor in Pennsylvania under a separate long-term agreement with Microsoft. That unit received an NRC environmental finding on Sept. 25, 2026.
Since 2024, hyperscalers have turned to existing nuclear plants for around-the-clock, carbon-free power for cloud and AI data centers. Many of these deals sit inside PJM, the grid serving 13 states and Washington, D.C., where data center demand has grown fastest. Amazon’s 1,920 MW contract with Talen Energy’s Susquehanna plant, signed in June 2025, is the closest comparable.
Talen Energy, a company that owns power plants including a large nuclear station in Pennsylvania, has lined up about $1.2 billion in payments from the grid operator serving much of the eastern United States.
The money is not for electricity sold. It pays Talen to keep its plants ready for the grid’s busiest days. Those payments are set in advance, and they have climbed because the grid expects many new artificial intelligence data centers. So power plants get paid before many of those data centers exist.
Electricity customers ultimately cover the bill. The same week, Talen named a new chief executive and a $1.5 billion plan to buy back its own shares.
ScanX reported that Talen Energy (NASDAQ: TLN), the Houston-based independent power producer, has secured $1,208 million in capacity revenues from PJM Interconnection, the operator of the largest power grid in the United States. Capacity revenues are payments a generator receives for committing its plants to be available during a future delivery year, separate from what it earns selling electricity.
The figure lands the same week as an 8-K filed September 29 in which Talen named President Terry Nutt as chief executive effective January 1, 2027, succeeding Mac McFarland, and announced $1.5 billion of accelerated share repurchases inside an upsized $3.0 billion buyback authorization running through the end of 2028.
Executive Summary
Talen’s $1,208 million in PJM capacity revenue is money earned for availability, not output: PJM pays generators a fixed price for each megawatt they commit to have ready during a delivery year, and the size of that payment is set by an auction that buys enough supply to cover forecast peak demand. That forecast has been pushed sharply higher by expected data-center growth, much of it tied to artificial intelligence.
The practical consequence is that AI demand is already turning into cash for existing merchant power plants, ahead of the data centers it anticipates. For Talen, which sells into wholesale markets rather than earning regulated rates, a large, pre-set revenue line behaves much like a contract. In the same week, the company’s board committed $1.5 billion to an accelerated share repurchase that Talen said would retire more than 10% of its shares at the current stock price, and handed the chief executive role to its former chief financial officer.
Talen has not explicitly linked the capacity revenue to the buyback, and important details, including delivery period, cleared megawatts and plant mix, remain open. But taken together, the two announcements illustrate how the AI power story is flowing through grid market design and into generator balance sheets.
Paid on the Forecast, Not the Plug-In
PJM’s capacity market works through an auction, known as the Base Residual Auction, held ahead of each delivery year. PJM estimates how much generation it needs to cover forecast peak demand plus a safety margin, then buys that commitment from power plants. Every plant that clears receives the auction price for each megawatt, for every day of the delivery year, as long as it is available when called. Total revenue is simple arithmetic: cleared megawatts times the price times the days in the year. Talen’s $1,208 million is the product of that arithmetic applied to its fleet.
The demand side of that auction is a forecast, and PJM’s recent load forecasts have been revised upward largely on expected data-center growth. PJM’s independent market monitor has attributed a large share of recent capacity price increases to forecast data-center demand, and prices for the 2026/27 and 2027/28 delivery years reached a temporary ceiling approved by federal regulators. In other words, a meaningful part of what generators are being paid reflects servers that are planned, not yet running.
That is the operational point. Once an auction clears, the commitment and the price are locked for that delivery year. If some forecast data-center campuses slip or are never built, the payments still flow. The forecast risk sits largely with the utilities and customers who fund capacity through their bills, while generators such as Talen hold a cleared price. This is how a fleet anchored by the Susquehanna nuclear plant can bank revenue tied to the AI buildout without signing a data-center contract for every megawatt it owns.
Contract-Like Cash for a Merchant Fleet
Talen is a merchant generator: it sells power at market prices rather than under regulated utility rates, so its energy revenue rises and falls with natural gas prices, weather and demand. Capacity revenue is different because it is known before the delivery year begins. For lenders and shareholders, that predictability makes it behave more like a contract than a commodity bet.
Talen’s September 29 disclosures show how it is deploying its cash. The company entered $1.5 billion of accelerated share repurchases, in which a bank delivers shares up front and the final count is settled later based on the average stock price. Talen said the ASRs are uncollared, meaning there is no price band limiting how many shares the fixed dollar amount ultimately buys, and that at the current stock price they would retire more than 10% of shares outstanding by the end of the first quarter of 2027. The board also raised remaining buyback capacity to $3.0 billion through December 31, 2028, leaving $1.5 billion beyond the ASRs.
Nutt described the ASRs as buying stock at “an attractive free cash flow yield” while “preserving liquidity and strategic flexibility.” Talen did not tie that decision to the capacity figure in its release. Still, a large revenue line fixed in advance is exactly the kind of visibility that lets a board commit a fixed dollar amount to an uncollared buyback with confidence.
The Price-Signal Debate, Asked of Both Sides
Generators and PJM have argued that high capacity prices are a legitimate scarcity signal: they keep existing plants from retiring and encourage new supply as demand grows. Consumer advocates and state officials, including Pennsylvania’s governor, whose challenge preceded the temporary price cap and floor, have argued that customers are paying elevated prices on forecasts that may prove too high, and that payments to existing plants do not add new supply quickly.
Both positions deserve pointed questions. For generators: how much of the elevated capacity revenue is going into new or uprated megawatts, rather than returned to shareholders? Talen’s most recent capital-allocation announcement is a buyback, not a construction program. For critics: if prices were held well below scarcity levels, what would keep existing plants running as load grows, and how confident can anyone be that a lower forecast would be more accurate? The reliability of large-load forecasts has itself become contested, because a single data-center project can appear in more than one utility’s plans.
A Finance-Led Succession for a Capital-Allocation Story
The incoming chief executive’s résumé fits the business the capacity figure describes. Nutt, 50, has been Talen’s President since December 2025 and was chief financial officer from July 2023 through December 2025. Before Talen he was chief financial officer of EDF Trading North America and held risk-management and controller roles at Vistra. Capacity auctions, hedging and capital returns are core skills in that background.
The board framed the transition as continuity in strategy, operations and capital allocation. McFarland stays chief executive through December 31, 2026, then serves as senior advisor until his retirement on March 1, 2027. Rubric Capital Management, which described itself as Talen’s largest actively managed shareholder, and Energy Capital Partners both publicly backed the choice, signaling that the shareholder-return emphasis is likely to persist.
Background
Talen Energy is a Houston-based independent power producer whose fleet is anchored by the Susquehanna nuclear plant in Pennsylvania, one of the largest nuclear stations in the United States. The company emerged from a Chapter 11 restructuring in 2023 and has since become one of the most closely watched power stocks of the AI era, after selling a data-center campus adjacent to Susquehanna to Amazon and later expanding its power-supply relationship with the company.
PJM Interconnection runs the grid and wholesale market for 13 states and Washington, D.C. Its capacity market, which pays plants to be available rather than only for power they produce, has become a focal point in the debate over who should bear the cost of AI-driven load growth, after recent auctions cleared at a temporary ceiling approved by federal regulators.
Lawmakers are moving a bill that would make large data centers pay the full cost of the power lines and grid upgrades they need, rather than spreading that cost across everyone’s electricity bills.
Shares of small nuclear companies jumped when the bill advanced, then handed the gains straight back. NuScale Power finished down about 7 percent, Oklo about 5 percent and Centrus Energy about 3 percent.
Why it matters: these companies pay for new reactors and fuel plants largely by selling shares. When the share price swings on a vote, so does the money available to build.
Shares of small-reactor and nuclear fuel companies rallied and then reversed around a House bill that would require data centers to cover the power costs their own loads create. According to reporting on the session that followed, NuScale Power fell about 7%, Oklo about 5% and Centrus Energy about 3%, giving back the gains the group had made when the measure advanced.
The move landed in a week in which two of the three companies were actively raising money against their share prices. Oklo disclosed in an 8-K filed September 11 that it had entered an at-the-market equity program of up to $1 billion, and Centrus disclosed in an 8-K filed the same day that it had priced a $500 million offering of stock and warrants on September 9. Centrus followed on September 17 with an 8-K reporting a multi-year high-assay low-enriched uranium supply contract with Antares Nuclear.
Executive Summary
The underlying policy question is narrow and consequential: when a data center of several hundred megawatts connects to the grid, who pays for the transmission upgrades, generation reserves and network reinforcement that load requires — the data center, or the utility’s general ratepayer base? A House bill assigning those costs to the load itself reads, at first glance, as a tailwind for dedicated on-site generation, including small modular reactors, because it raises the cost of taking power from the public grid.
The market tested that logic and then partly withdrew it inside a session. That is worth taking seriously rather than dismissing as noise, because the same rule that makes grid power more expensive also makes the buyers of small-reactor power more expensive to operate — and a bill that has cleared one chamber is not a tariff, a rule or a contract.
What makes the swing operationally relevant is that valuation in this sector is not a scoreboard. It is working capital. Oklo’s $1 billion at-the-market program converts share price directly into build funding, and roughly $2 billion of Centrus’s potential proceeds sits in warrants that only pay out if the stock trades well above where the September offering priced.
Cost Allocation Is the Real Variable Behind AI’s Power Demand
Interconnecting a large load is not simply a matter of running a wire. A multi-hundred-megawatt data center — a megawatt is roughly the steady draw of several hundred homes — typically triggers network upgrades, new substations and reserve capacity that cost hundreds of millions of dollars and take years to build. The question of who pays for that has, until recently, been handled case by case by state regulators and grid operators, often with a meaningful share landing in the rates everyone pays. A federal rule assigning those costs to the load that caused them changes the arithmetic of every site selection decision in the industry.
That is why the initial read was bullish for nuclear developers. If grid-delivered power carries the full loaded cost of the upgrades it requires, plus the multi-year queue wait, then dedicated generation sited at or near the campus stops competing against the cheap headline price of grid power and starts competing against the true all-in cost. Small modular reactors — factory-built units in the tens to few hundreds of megawatts, designed to be sited next to the customer — are positioned precisely for that comparison.
The give-back is the part worth explaining, because it is where the simple version of the thesis breaks. NuScale’s roughly 7% decline, Oklo’s 5% and Centrus’s 3% came without any company-specific bad news attached to them. The plainest reading is that the same rule cuts in two directions at once: it raises the cost of grid supply, but it also raises the total cost of building and operating the data centers that are the presumed offtakers for on-site nuclear. A hyperscaler facing a larger interconnection bill has less budget, not more, and may respond by siting fewer campuses rather than buying more reactors. Whichever way that nets out, the affected parties are the same: data center developers pricing new sites, utilities and their regulators deciding what the general ratepayer absorbs, and the reactor and fuel companies whose demand case is built on the gap between those two answers.
A Bill That Passed One Chamber Is Not a Tariff
There is a second reason a policy rally can evaporate in a session. Legislation of this kind does not usually land as a self-executing rule. Cost responsibility for large loads sits across federal and state jurisdictions, and translating a statutory instruction into actual large-load tariffs, deposit and collateral requirements, minimum-take terms and network upgrade cost assignments is a rulemaking-and-litigation process measured in years — comfortably longer than the development timeline of most of the reactors being valued against it.
None of that makes the bill unimportant. It means the market is pricing a direction of travel, not a set of terms, and direction-of-travel trades are exactly the ones that reverse when the second-order effects get counted. For readers evaluating these companies, the useful discipline is to ask what changed in contracted capacity, licensing position or customer commitments on the day — and in this case, for the reactor developers, nothing did.
When Share Price Is the Construction Budget
Here is where a one-session swing stops being abstract. Pre-revenue nuclear developers and capacity-expanding fuel suppliers fund themselves substantially by issuing equity, which makes the share price an input to the build, not a commentary on it.
Oklo’s 8-K filed September 11 discloses an equity distribution agreement with ten sales agents — Goldman Sachs, BofA Securities, Citigroup, J.P. Morgan, Morgan Stanley, Barclays, Cantor Fitzgerald, Guggenheim, Canaccord Genuity and B. Riley — permitting up to $1 billion of Class A common stock to be sold at the market over time, at a commission of up to 1.5%, off a shelf registration declared effective December 4, 2025. An at-the-market program dispenses stock into the open market at prevailing prices at the company’s discretion; the dollar ceiling is fixed, so the number of shares required to reach it moves inversely with the price. A 5% lower share price means roughly 5% more dilution for the same construction dollar.
Centrus shows the sharper version. Its September 11 filing and the accompanying release disclose an offering priced September 9 at a combined $199.64 per share of Class A common stock and accompanying warrants, comprising 500,000 shares, pre-funded warrants over 2,005,513 shares and common warrants over as many as 6,992,382 shares, for gross proceeds of approximately $500 million. The common warrants come in four series struck at $226.8625, $272.2350, $317.6075 and $362.9800 — between roughly 14% and 82% above the offering price — each series carrying an aggregate exercise price of about $500 million. That is roughly $2 billion of additional funding for domestic enrichment capacity that arrives only if the stock trades and holds well above where it priced, within tranches expiring between the second and fifth anniversaries of September 10, 2026. Policy-driven round trips of 3% to 7% do not decide that outcome on their own, but they are the increments that determine whether a strike price is reached, and they are the reason the grid cost-allocation debate has a direct line to how much enrichment and reactor capacity actually gets financed.
The Part of the Chain That Isn’t Priced on Votes
Centrus’s September 17 8-K and the attached release describe a different kind of event: a definitive multi-year contract to supply Antares Nuclear with high-assay low-enriched uranium — fuel enriched above the level used in conventional reactors, which most advanced designs require — with deliveries commencing before the end of the decade and prepayments from Antares to support expanded capacity. Prepayments are the operative detail. They are customer cash committed ahead of delivery, which is a materially firmer demand signal than a legislative headline.
Two caveats keep this even-handed. First, the release positions the contract around defense and space missions: Antares, founded in 2023 and described as backed by over $600 million in funding, was selected for the U.S. Army’s Janus Program at Fort Bragg, the Air Force’s Advanced Nuclear Power for Installations program at Joint Base San Antonio and a Space Force award, with initial military deployments stated for 2028. It is not evidence of data center demand. Second, the contract’s value, volumes and prepayment amounts are not disclosed, so “adds another HALEU customer to the backlog” cannot yet be sized.
Still, the contrast is the useful takeaway for anyone underwriting this sector. Centrus operates the American Centrifuge Plant at Piketon, Ohio, described in its release as the only licensed HALEU production facility in the western world, and is converting that position into binding orders with cash attached. That is a different asset class from a valuation that moves 3% on a chamber vote — and over time it is the one that determines whether AI-adjacent nuclear capacity gets built.
Background
The three companies sit at different points of the same chain. NuScale Power and Oklo are developers of small modular and advanced reactors, pre-revenue businesses whose value rests on licensing progress and future customer commitments. Centrus Energy is a fuel supplier, operating the American Centrifuge Plant in Piketon, Ohio, which its release describes as the only licensed high-assay low-enriched uranium production facility in the western world; the company says it has supplied more than 1,850 reactor years of fuel since 1998 and launched a multi-billion-dollar enrichment expansion last year.
All three have been repriced repeatedly over the past two years by the same underlying story: data center electricity demand growing faster than grids can be upgraded, and hyperscale operators signing power agreements with nuclear suppliers to secure firm, carbon-free capacity. Because reactor and enrichment capacity takes years and large capital outlays to build, and because these companies fund much of that through equity issuance, policy headlines that move sentiment also move the practical cost of building.
Shares in two companies building small, factory-made nuclear reactors jumped on Thursday. Oklo rose about 13% and NuScale about 10%.
The trigger was a vote in the US House of Representatives on how to power the huge computer warehouses behind artificial intelligence. The bill does not require anyone to use nuclear power.
That gap matters. Oklo had just arranged to sell up to $1 billion of new stock to fund its reactors. A higher share price means it can raise that money while handing out fewer new shares.
Shares of small modular reactor developers Oklo and NuScale Power rose sharply on Thursday after the U.S. House voted on legislation addressing electricity supply for data centers. Yahoo Finance and 24/7 Wall St. reported Oklo up 13% and NuScale up 10%. TechStock² put the gains at 11% and 9% and reported that the measure stops short of ordering the use of nuclear power. Other nuclear names, including NANO Nuclear Energy and fuel supplier Centrus Energy, also rose.
The rally came one week after Oklo disclosed, in an 8-K filed September 11, an equity distribution agreement with ten banks. The agreement lets it sell up to $1 billion of Class A common stock “at the market,” meaning gradually and at prevailing share prices.
Executive Summary
The House vote gave nuclear equities a policy signal, not a purchase order. The bill as reported does not compel data centers or utilities to buy nuclear power. It does not fund a reactor. It does not change how quickly the Nuclear Regulatory Commission licenses one. Even so, investors marked up the whole small-reactor group in a single session. That shows how much of these companies’ value rests on expectations about Washington’s direction rather than on operating assets. Neither Oklo nor NuScale yet runs a commercial reactor in the United States.
For Oklo, the timing turns a sentiment move into a financing variable. Its new at-the-market program sells shares at whatever the market is paying. A higher price lets the company raise the same dollars while issuing fewer shares, which means less dilution for existing holders. The company can also choose to raise more. For AI data-center developers hoping small reactors will eventually supply firm power, a well-funded developer matters. The capital to build is the first thing between a reactor design and a delivered megawatt.
A Rally on a Signal, Not a Mandate
The central fact of Thursday’s trade is the mismatch between the policy and the price move. The House measure concerns power for data centers, the warehouse-scale computing sites whose electricity demand has climbed with AI training and inference. The measure reportedly does not order that any of that power come from nuclear plants. Investors bid the sector up anyway. The best reading is that the market is pricing direction: Congress is treating data-center power as a legislative priority, and nuclear is the carbon-free, always-on source most often named alongside it.
That is a reasonable thing to be optimistic about, but it is not a revenue event. Small modular reactors (SMRs) are nuclear units far smaller than conventional plants, designed to be built in factories and installed in modules. They still have to clear licensing, secure fuel, finance construction and sign binding power contracts before they produce anything a data center can buy. A vote that addresses none of those steps directly moved the stocks by roughly a tenth. That tells readers more about how these valuations are built than about how soon reactors will run.
Why the Jump Matters Most to Oklo’s Share Sales
Oklo’s September 11 8-K sets out the mechanism. Under the equity distribution agreement, ten banks, including Goldman Sachs, BofA Securities, Citigroup, J.P. Morgan and Morgan Stanley, can sell Class A shares for Oklo in ordinary market trades, block trades or negotiated deals. Sales happen “at market prices prevailing at the time of sale,” up to $1 billion in gross proceeds. Oklo sets a daily maximum and a minimum acceptable price, and pays commissions of up to 1.5%. On the full $1 billion, that would be up to $15 million.
Because the price floats, the share price directly sets the cost of this capital to existing owners. Take any fixed dollar amount raised at a price 13% higher: it requires about 11.5% fewer new shares than it would have the day before (1 divided by 1.13). A policy-driven rally therefore does something concrete for Oklo that it does not do for a company without an open program. It cuts the dilution attached to funding reactor development, or lets Oklo raise more for the same dilution. The 8-K describes the shares as issued off a shelf registration declared effective in December 2025. That means Oklo can act on the higher price without a fresh registration process.
Two caveats keep this honest. Oklo has not said whether it has sold any shares under the program or at what prices. And a price gain built on a signal can reverse as quickly as it came. The benefit is real only for sales made while the higher price holds. Existing shareholders are the other affected party. Every share sold dilutes them, whatever the price.
A Basket Move, Not Company News
The breadth of the rally points to sector sentiment rather than company-specific developments. NuScale filed no material report with the SEC in the days around the vote. NANO Nuclear Energy’s most recent 8-K, filed September 17, reports only routine results from its September 15 annual meeting: six directors re-elected and Withum ratified as auditor. Nothing in that filing concerns the House bill, customers or reactors. When developers at different stages, and a fuel supplier, rise together on the same day, the market is repricing the theme, not the individual businesses.
For data-center developers and hyperscalers, the largest cloud operators, the practical lesson is to separate equity momentum from procurement reality. The gating items for nuclear-supplied AI capacity have not moved: licensed designs, fuel supply, construction financing and signed offtake agreements. Offtake agreements are long-term contracts to buy a plant’s output. A stronger share price can help with one of these, financing, and only for companies positioned to tap it.
Background
Oklo went public in 2024 through a merger with AltC Acquisition Corp., a blank-check company co-founded by Sam Altman. It is developing the Aurora, a compact fast reactor. Its first combined license application was denied by the Nuclear Regulatory Commission in 2022, and it has since been working back through licensing. NuScale Power’s design was the first small modular reactor design certified by the NRC. Its flagship Carbon Free Power Project with Utah municipal utilities was cancelled in 2023 after subscriptions fell short.
Both companies have positioned themselves as future suppliers of firm, carbon-free electricity to data centers, whose power needs have grown quickly with AI workloads. Both remain pre-revenue on commercial reactor sales. That leaves their share prices sensitive to policy news, to financing conditions and to any sign that large power buyers will commit.
A startup called Blue Energy asked federal nuclear regulators for permission to build a power plant on the Texas coast that runs on both natural gas and small nuclear reactors.
The electricity would feed a computing site built by Crusoe for artificial intelligence — buildings full of computers that need power around the clock.
Here is the catch: the gas part gets built first, by around 2030. The reactors come later, in the 2030s.
So the plant sold as nuclear will spend its early years running mostly on gas.
EnergyTech reported that North Carolina-based startup Blue Energy has submitted its first construction permit application to the U.S. Nuclear Regulatory Commission for a hybrid gas-and-nuclear generating station at the Port of Victoria, Texas. The project would pair a GE Vernova 7HA.02 gas turbine with the GE Vernova-Hitachi BWRX-300 small modular reactor, building toward a 2.5-gigawatt plant by the early 2030s that would serve an AI data center — an “AI factory” — developed by Crusoe, along with other loads.
The build is staged. Phase one centers on the gas turbines, which the company says are the quickest to install and commission, targeted for the end of this decade. Phase two would add perhaps five BWRX-300 units, each generating close to 300 megawatts at capacity, with the gas units eventually phased out or reduced. Blue Energy estimates project cost at more than $6 billion, with Société Générale acting as lead financial advisor.
Executive Summary
The filing is a procedural milestone rather than a construction start, and that distinction matters. No small modular reactor has been fully approved or begun construction in the United States. Federal applications of this kind typically take years to move through technical and environmental review before a permit issues. Blue Energy is entering a queue that also contains the Tennessee Valley Authority’s BWRX-300 application at Clinch River — which GE Vernova Hitachi says is approaching a decision — and applications from other developers including X-energy.
What makes the Victoria project analytically interesting is not the reactor. It is the sequencing. A 2.5-gigawatt site whose first phase is combustion turbines and whose second phase is five reactors is, for the first several years of its operating life, a gas plant with a nuclear option attached. If roughly five units at close to 300 megawatts each eventually arrive, that implies on the order of 1.5 gigawatts of nuclear capacity and the balance from gas — meaning the gas fleet is not a token bridge but a substantial share of the nameplate.
For GE Vernova, the strategic value is fleet economics: the same reactor design, the same licensing work and the same supply chain applied across multiple sites, so that each project is cheaper and faster than the last. For data center developers, the practical value is that a credible nuclear pathway may make a gas-first interconnection easier to defend to customers and communities that have made carbon commitments.
The Permit Is Nuclear. The First Electrons Are Gas.
Read the phasing literally. Blue Energy says phase one focuses on the gas turbines because they are the quickest to install and commission, with a target of the end of this decade. Phase two would add perhaps five BWRX-300 reactors, each producing close to 300 megawatts — a megawatt being roughly the power draw of a few hundred homes, and 300 megawatts being enough for a serious data center campus on its own. The total plant is described as 2.5 gigawatts by the early 2030s. Subtract the nuclear arithmetic from the total and roughly a gigawatt of gas-fired capacity is carrying the site before the reactors show up, and continuing alongside them after.
That is the operational conclusion buried in an otherwise routine regulatory filing. Crusoe’s AI factory, if it energizes on the announced schedule, will be a nuclear-adjacent load long before it is a nuclear-powered one. Nobody has misstated this — the release is explicit that gas comes first and that the gas units would later be “phased out or reduced.” But the framing of hybrid gas-nuclear projects generally, and the headlines they generate, tend to lead with the reactor rather than with the turbine that will actually be spinning in 2030.
Who this affects: any hyperscaler or AI developer signing power agreements against projects like this one needs to price two different assets. The near-term asset is dispatchable gas generation with commodity and emissions exposure. The long-term asset is a first-of-a-kind reactor deployment with schedule and licensing risk. Blending them into one “clean firm power” line item on a sustainability disclosure understates the first and overstates the certainty of the second. The honest version is that gas is buying time for nuclear to clear regulatory review — which is a defensible strategy, just not the same claim.
Fleet Licensing Is the Product GE Vernova Is Actually Selling
Jason Cooper, CEO of GE Vernova Hitachi Nuclear Energy, framed the Blue Energy filing around repeatability: “This is what fleet deployment looks like: projects advancing on common technology, licensing work and supply chain capabilities, allowing us to apply lessons from one project to the next.” That sentence is the commercial thesis of the entire small modular reactor category, compressed.
Conventional nuclear construction in the United States has been defeated less by physics than by one-off engineering. Every plant a bespoke design, every licensing review starting near zero, every supply chain assembled and then dispersed. The BWRX-300 bet is that if the same design goes through the Nuclear Regulatory Commission repeatedly — Clinch River with the Tennessee Valley Authority, now Victoria with Blue Energy — the review gets shorter, the vendors keep their tooling, and the crews carry experience forward. Blue Energy’s Jake Jurewicz echoed the point, saying the team moved from technology selection to construction permitting “in a matter of months.”
The claim is plausible and, so far, unproven at the only point that counts: a completed unit. Nothing in the release establishes that the second application will be reviewed faster than the first, or that fabrication cost falls on unit two. Investors and buyers should watch the Clinch River decision closely, because it is the first real data point on how much of the fleet argument the regulator is prepared to credit.
More Than $6 Billion, and the Project-Finance Test
Blue Energy puts the project above $6 billion and has engaged Société Générale as lead financial advisor. Kim Hill, the bank’s transaction lead, described the mandate as a step toward deploying private capital markets for advanced nuclear “just like it has for wind, solar, and battery technologies.” That comparison is the tell. Wind, solar and storage became bankable because their capital costs are predictable, their construction windows are short, and their revenue is typically locked to long-term contracts before anyone breaks ground.
Advanced nuclear does not yet satisfy the first two conditions in the United States — no unit has been built to prove them. Which is another reason the gas-first phasing is more than an engineering convenience: turbines are a financeable, well-understood asset class with an established construction schedule, and early cash flow from gas generation changes the risk profile a lender sees when it underwrites the reactors behind it. The strategic investor list, which includes Constellation Technology Ventures, VXI, Engine Ventures, At One Ventures and Tamarack Global, reflects venture-stage risk tolerance; a $6 billion project needs a different class of capital entirely.
Why the Load Growth Argument Has Real Force — and Its Limits
Nuclear supplies about 18% of the U.S. utility-scale electricity mix, and the fleet spent years under pressure from operating costs, cheap gas, renewables and, critically, flat demand. Data center growth has reversed the demand assumption, and the industry’s argument is that carbon-free baseload — power that runs continuously rather than when the wind blows — is the natural answer for loads that run at high utilization around the clock.
The counterargument, which the release also records, is that nuclear projects remain expensive, slow and contested on health and safety grounds. Both positions can be evaluated on evidence rather than assertion, and the evidence arrives on a schedule: permit decisions, construction starts, and the first concrete date. Until then, the sharpest thing to say about Victoria is that it is a credible attempt at a genuinely difficult sequencing problem — build generation fast enough for AI load that exists now, while licensing generation clean enough for the commitments that load has already made.
Background
Blue Energy is a North Carolina-based startup pursuing what it describes as a repeatable, rapidly built approach to new nuclear construction — EnergyTech has previously reported the company raised $380 million to advance prefabricated reactor construction. It selected the BWRX-300 design earlier this year for co-location with gas turbines and, by its own account, moved from technology selection to federal construction permitting within months.
The BWRX-300 is a boiling water small modular reactor from GE Vernova Hitachi Nuclear Energy, a joint venture between GE Vernova and Hitachi. It is the design furthest along in the U.S. licensing process, through the Tennessee Valley Authority’s Clinch River project, and has been selected by several developers internationally. The broader context is a U.S. power sector that spent a decade planning around flat demand and is now contending with data center and AI load growth that has made firm, round-the-clock generation scarce and valuable again.
A company that wants to build very small nuclear reactors — small enough, in principle, to be trucked to a site rather than built as a giant power station — has signed an agreement with a partner called Enveniam to work on the groundwork those reactors need: land, permits, and a way to move the electricity.
Nothing has been built yet. It is an agreement, not a power plant.
Why care? The warehouses of computers that run artificial intelligence need huge amounts of steady electricity, and the grid is running short. Small reactors are one proposed answer.
Marketscreener.com reported that Nano Nuclear Energy Inc. (Nasdaq: NNE), an early-stage developer of microreactors, has signed an agreement with Enveniam covering microreactor infrastructure. The announcement frames the work around the physical and site-level groundwork that a deployed reactor requires, rather than around the reactor hardware itself.
Neither company has publicly set out the agreement’s commercial terms, its duration, whether it is binding, or which sites or customers it is intended to serve. No megawatt figure, delivery date or financial consideration accompanies the announcement.
Executive Summary
The signal in this agreement is where it sits in the value chain. Reactor developers spend their first years on physics, fuel and regulatory design certification. Infrastructure agreements point at the next stage: land, site characterisation, permitting, construction logistics and grid or behind-the-meter connection — the unglamorous work that determines whether a licensed design ever becomes delivered electricity.
That matters because the constraint on nuclear power for data centres is no longer primarily whether small reactors can be designed. It is whether they can be sited, licensed, financed, fuelled and built on a schedule that matches how fast computing demand is growing. An agreement aimed at infrastructure is at least addressed to the correct bottleneck.
What it is not is a purchase order. There is no disclosed capacity, no named offtaker, no construction start and no financing package. On the current record, this is a positioning step in a sector where positioning steps are common and completed reactors are not — the industry has yet to place a commercial microreactor into service in the United States.
The Hard Part Was Never the Reactor
A microreactor is generally understood in the industry as a unit producing up to roughly 20 megawatts of electricity — a fraction of a conventional nuclear plant, and small enough that the design intent is factory manufacture and transport to site. The broader small modular reactor, or SMR, category runs up to about 300 megawatts. For scale, a single large artificial-intelligence data centre campus can be designed around hundreds of megawatts of continuous demand, so microreactors are best understood as a modular building block, not a one-for-one replacement for a gas plant.
Designing such a machine is difficult but tractable. Deploying it involves a longer list: an approved site, a construction permit and operating licence from the Nuclear Regulatory Commission, environmental review, security and emergency-planning arrangements, a fuel supply, a construction workforce, and either a grid interconnection or a behind-the-meter arrangement that a utility and regulator will accept. Each of those is a separate multi-year process with its own gatekeepers.
An agreement explicitly about infrastructure is therefore aimed at the right target. The open question — unanswered by the announcement — is which of those items the two companies intend to take on together, and on whose balance sheet.
Why Data Centres Keep Calling the Nuclear Industry
Data centre operators want power that is large, firm and carbon-free. Firm means available around the clock, which is what separates nuclear from solar and wind without storage. Large means tens to hundreds of megawatts at a single point of delivery. And the timing is difficult: in several US markets, a new load asking to connect to the transmission system enters an interconnection queue — a waiting list for grid studies and upgrades — that can run for years.
That combination is why hyperscale operators have gone directly to nuclear counterparties rather than waiting for the grid to catch up, including agreements to restart retired reactors and to fund next-generation developers. Those deals validated the demand side. They did not solve the supply side, because restarting an existing reactor and building a new one are entirely different engineering and regulatory problems.
Microreactors are pitched into that gap: smaller increments, sited closer to load, potentially serving campuses that cannot get a timely grid connection. The pitch is coherent. The delivery record does not yet exist, and buyers evaluating it should price that distinction rather than assume it away.
Agreements Are Cheap; Concrete Is Not
The advanced nuclear sector runs on letters of intent, memoranda of understanding and framework agreements. Many are genuine early-stage commitments. Very few carry firm capacity, firm dates or firm money, and the distance between a signed framework and a poured foundation is where most of the sector’s announcements have historically stalled.
The tests that separate the two are specific and public. Has a construction permit application been docketed with the Nuclear Regulatory Commission, and accepted for review? Is there a secured fuel pathway — advanced designs frequently require high-assay low-enriched uranium, a fuel whose Western supply chain is still being built out? Is there a customer with a contract, rather than an interested party? Is there capital sized to a first-of-a-kind build, which by definition costs more than the units that follow?
None of those markers accompanies this announcement. That is not an accusation of anything; it is a statement of what an infrastructure agreement, on its own, establishes. Readers tracking the sector should treat it as a milestone in a long sequence, and watch for the filings and contracts that would convert it into something bankable.
Who Gains, and What It Would Take to Matter
If microreactor siting work matures, the beneficiaries are data centre developers in constrained markets who currently trade away site quality for available power, and industrial or remote loads that are expensive to serve from the grid. The losers, eventually, would be the incumbent solution — long-lead gas generation plus grid upgrades — though not this decade unless several nuclear projects reach operation first.
For an equity investor, the honest framing is that early-stage nuclear developers are optionality, not cash flow. Value accrues at discrete regulatory and contractual milestones rather than smoothly, and dilution risk is a normal feature of pre-revenue capital-intensive development. For a data centre buyer evaluating a nuclear-adjacent site today, the practical advice is unchanged: contract for power you can point to, and treat an advanced reactor as an upside case in the 2030s rather than a 2026 procurement.
Background
Electricity demand from data centres has grown sharply with the build-out of artificial-intelligence computing, after roughly two decades in which US power demand was broadly flat. That reversal collided with a grid that is slow to expand: transmission takes years to permit and build, and the queues for new connections in several regional markets are long. The result has been a scramble by hyperscale operators to secure firm, carbon-free generation directly, including agreements to restart previously retired nuclear plants and to fund next-generation reactor developers.
Advanced nuclear entered that opening. Small modular reactors and microreactors promise standardised, factory-built units that can be sited closer to load and added in increments, rather than the bespoke multi-gigawatt projects that dominated the last nuclear build cycle. Nano Nuclear Energy is one of a group of companies pursuing that thesis from an early stage, alongside developers backed directly by technology buyers. The sector’s central open question is not whether the designs are plausible — it is whether licensing, fuel supply, financing and construction can be compressed enough to serve data centre demand in this decade rather than the next.
NANO Nuclear Energy (Nasdaq: NNE) and Tillman Digital Gateway have signed a framework agreement under which NANO Nuclear would supply advanced nuclear power — specifically microreactors, factory-built reactors far smaller than conventional nuclear plants — to U.S. AI industrial zones being developed by Tillman Digital Gateway.
The announcement, carried by Energies Media and picked up by market commentary including Simply Wall St, describes the intended scope of the relationship. The material available does not state contracted capacity, named sites, pricing, financing, or a first-power date.
Executive Summary
The agreement pairs two halves of a problem the AI buildout keeps running into. Tillman Digital Gateway is assembling industrial-scale campuses for AI compute; NANO Nuclear is one of a cohort of U.S. developers designing microreactors intended to sit alongside large loads rather than feed a regional grid. On paper, that is a clean match: the data center needs firm, always-on power in one place, and a microreactor is designed to deliver exactly that.
What makes the news notable is less the technology than the sequencing. For two years, “behind-the-meter nuclear” — generation sited at the customer’s facility, bypassing the public grid — has functioned mostly as a directional statement in data center strategy decks. A named developer signing a framework with a named campus developer moves the conversation from category to counterparty.
It does not, however, move it to schedule. A framework agreement sets the terms on which later contracts might be written; it is not a power purchase agreement, an equipment order, or a construction commitment. The commercially decisive facts — how many megawatts, on which sites, by when, financed how, and licensed under what pathway — are the ones the announcement leaves open.
What a Framework Agreement Actually Buys
Energy procurement runs along a ladder of commitment. At the bottom sits the memorandum of understanding, which signals mutual interest and binds almost nothing. A framework agreement sits a rung up: it typically defines scope, roles, and the shape of future contracts, and it may include exclusivity or development obligations. Above it sit the documents that actually move money — definitive supply agreements, power purchase agreements with price and volume, and engineering, procurement and construction contracts.
The distinction matters because early-stage announcements in advanced nuclear are frequently read as orders. They are more accurately read as pipeline. For a pre-commercial reactor developer, a framework with a credible industrial counterparty is genuine progress: it demonstrates a customer willing to be named, and it gives the developer something concrete to show regulators, fuel suppliers, and capital markets. That is a real asset. It is simply a different asset from revenue.
The even-handed reading, then, is that this announcement substantiates commercial interest and a working relationship. It does not yet substantiate deployment. Both statements can be true at once, and coverage that collapses them into one another — in either direction — misreads the document.
Why AI Campuses Are Shopping for Their Own Reactors
The demand side of this story is not speculative. Large AI training and inference campuses want hundreds of megawatts in a single location, running near-continuously, with power quality that tolerates very little interruption. Grid interconnection — the process of getting a new large load or generator formally connected to the public network — has become the binding constraint in many U.S. markets, with queues and transmission upgrades measured in years rather than months.
That is what makes “behind-the-meter” attractive. If generation sits inside the fence, the campus avoids some of the interconnection wait, reduces exposure to congested transmission, and can present a cleaner load profile to the local utility. Microreactors extend the idea further: rather than a single large plant requiring a decade of site-specific construction, the design intent across the sector is factory fabrication, transport to site, and modular addition of units as a campus scales.
The economics are correspondingly attractive on paper and unproven in practice. Nobody yet has a fleet-scale cost curve for factory-built microreactors, because no U.S. commercial microreactor fleet exists to generate one. Buyers evaluating this option are, in effect, underwriting the assumption that serial manufacturing will do for small reactors what it has not yet done for large ones.
The Timeline Problem
Every advanced nuclear deal for AI infrastructure runs into the same arithmetic. Hyperscale capacity decisions operate on cycles of roughly two to four years from land to live racks. Nuclear operates on licensing, fuel, and fabrication cycles that are considerably longer. The U.S. Nuclear Regulatory Commission must license both the reactor design and each specific site; fuel — particularly the higher-assay low-enriched uranium many advanced designs require — depends on a domestic supply chain still being built; and first-of-a-kind manufacturing has a way of consuming schedule.
This is not a criticism unique to NANO Nuclear or to this agreement. It is the structural condition of the entire advanced nuclear sector, and it is precisely why frameworks without dates deserve to be read carefully rather than dismissed. The honest question for any such deal is not “is nuclear real?” — it plainly is — but “which power source is actually carrying the load in year one, year three, and year seven of this campus?”
In most credible plans, the answer for the near term is something else: grid supply where it can be obtained, gas turbines, fuel cells, or storage-firmed renewables, with nuclear entering later as an addition rather than a substitute. A framework signed today is best understood as an option on the back half of a campus’s power stack, not the front half.
Who Gains, and What Would Confirm It
The clearest near-term beneficiary of announcements like this is narrative positioning. For a listed pre-revenue developer, a named industrial counterparty changes the investment story from “design in development” to “design with identified demand,” which is a materially different pitch to capital markets — and, as the accompanying market commentary notes, the question is whether it should shift the narrative that far on the evidence disclosed. For Tillman Digital Gateway, the agreement signals to prospective AI tenants that long-horizon firm power is being addressed, which is increasingly a leasing differentiator.
The parties with the most to prove are the same ones. Confirmation would look concrete: a definitive supply or power purchase agreement with stated capacity, a named site entering the NRC licensing process, a secured fuel pathway, and disclosed financing for units that cost far more than a typical data center power plant. Each of those is observable and checkable; none of them is present in this announcement.
Incumbent power options are not displaced by this news. Gas turbine manufacturers with multi-year order books, grid utilities negotiating large-load tariffs, and developers of storage-backed renewables all continue to serve demand that exists now. The competitive question microreactors must eventually answer is not whether they are cleaner or firmer, but whether they arrive in time and at a delivered cost per megawatt-hour that a hyperscale tenant will actually sign for.
Background
Microreactors and small modular reactors emerged as a response to the cost and schedule problems of gigawatt-scale nuclear construction. Instead of building a large custom plant on site over a decade, the premise is to manufacture standardized units in a factory, ship them, and add capacity in increments. A cohort of U.S. developers, NANO Nuclear Energy among them, has pursued this route with designs at varying stages of regulatory review; none has yet reached commercial fleet operation in the United States.
Demand arrived faster than the technology. From 2023 onward, AI compute buildouts pushed data center power requirements into a range that strained grid interconnection processes across major U.S. markets, prompting technology and infrastructure firms to look at generating their own firm power on site. That convergence — mature demand meeting pre-commercial supply — is the context for framework agreements like this one, and it is also why the gap between announcement and delivery deserves close attention.
Crusoe, a company that rents out computing power for artificial intelligence, will spend six months testing a small nuclear reactor from startup Aalo alongside one of its compact data centers.
Aalo’s reactor is sized to match the gas-fired generators many of these sites already run on. The test is about whether it can keep the computers running reliably, even as their demand for electricity swings up and down.
If it works, the two companies aim to start building for real in 2029, but first Aalo needs a green light from federal nuclear safety regulators.
Crusoe, a cloud provider built specifically for AI workloads (often called a neocloud), and reactor developer Aalo Atomics will pair Aalo’s small modular reactor (SMR) technology with Crusoe’s modular Spark AI data center for a six-month trial, Fierce Network reported on August 11, 2026. The test will examine the reactor’s capacity factor, meaning how consistently it can run without downtime, along with its ability to follow the fluctuating power draw of AI workloads when combined with battery storage.
Both companies are targeting commercial nuclear-powered AI data center deployments in 2029. Aalo’s first product is the Aalo One Reactor in a 50-megawatt Aalo Pod configuration. Commercial deployment in the United States depends on approval from the Nuclear Regulatory Commission.
Executive Summary
The Crusoe–Aalo trial is a small-scale engineering test, not a power purchase deal. The goal is to find out whether a factory-built reactor and a factory-built data center can be tightly coupled on one site. According to Aalo CEO Matt Loszak, this will be the first time the two types of infrastructure are so closely integrated. Crusoe co-founder Cully Cavness described the work as mostly electrical engineering: controls, monitoring, load profiles and fault conditions running in both directions.
The strategic significance lies in how the reactor is sized. The large nuclear deals signed by the major hyperscalers mostly secure output from existing large plants. Aalo, by contrast, has built its 50-megawatt pod to fit the 10-to-50-megawatt range where on-site gas turbines currently power many data centers, and says it can make nuclear’s economics very competitive with natural gas. If that holds, small reactors would be competing for the on-site generator slot rather than against utility-scale nuclear. That claim is still a target and has not been demonstrated.
The Benchmark Is a Gas Turbine, Not a Gigawatt Plant
Hyperscaler nuclear deals have mostly involved large legacy plants that deliver power over the grid. Aalo is aiming at a different market. Loszak said many data centers are being powered by gas turbines and small modular gas generators in the 10-to-50-megawatt range, and that this is the reason Aalo chose a 50-megawatt pod. He described the design as a balance between economy of scale, which argues for larger units, and economy of number, which argues for mass-producing many identical ones. He added that a reactor as small as 1 megawatt would suffer on economics.
This sizing decision identifies the real competitor. A 50-megawatt pod that can be stacked is meant to fill the same role in a site plan that on-site gas fills today: dedicated, behind-the-meter capacity, sized in blocks, added as a campus grows. It is not meant to replace a grid connection to a 1-gigawatt plant. The people affected are data center developers and neoclouds that currently use gas to get around grid interconnection delays. Crusoe is one of them, and Cavness said the company already pursues natural gas, solar and batteries as a portfolio.
The comparison also sets the standard the technology must meet. On-site gas is a known quantity with established supply chains. Aalo’s statement that it can be very competitive with natural gas is a stated goal, and neither company has published cost-per-megawatt-hour figures to back it up. The benchmark is clear. Whether Aalo can hit it has not yet been shown.
Why the Trial Is About Load Following, Not Reactor Physics
Loszak said the first priority is capacity factor: can the reactor run for months with very limited downtime? The second priority is load following, meaning how well the power supply tracks demand as it changes. AI workloads are not flat. Loszak said Crusoe may simulate the different fluctuation patterns it sees across training and inference jobs. The setup will include battery storage so the companies can test how nuclear and batteries share the job of absorbing those swings.
This is the practical challenge of tight coupling. When a data center draws from the grid, the grid absorbs its variability. When a reactor sits beside the load with no grid in between, any mismatch between supply and demand has to be handled on site, through controls, storage, or the reactor’s own response. Cavness’s emphasis on fault conditions in both directions points to the same problem: a disturbance on either the data center side or the reactor side has to be contained without taking down the other.
This is also where the gas comparison is tested in practice. On-site generators are often chosen because operators can dispatch them to match load. A nuclear pod paired with batteries needs to show similar operational behavior before a buyer will treat it as a replacement. Six months of data on that pairing is exactly what a prospective buyer would want to see.
Time Is the Cost Line Both Companies Are Trying to Cut
Cavness described nuclear’s historic problem as time and money. Build timelines of a decade or more lead to cost overruns, which raise the price per kilowatt-hour. The proposed solution is modular, mass-manufactured units that bring down both the timeline and the cost. Aalo reached criticality, a sustained nuclear chain reaction, within three years of its founding, which is fast by the standards of the nuclear industry. Crusoe’s modular data center approach follows the same manufacturing-led thinking.
The 2029 target is aggressive, and several dependencies stand in the way. Aalo needs Nuclear Regulatory Commission approval before any domestic commercial deployment. The companies also acknowledge they will need to win over local communities, which are increasingly skeptical of data centers even without a reactor involved. Their stated answer is careful site selection and public education. A successful trial would reduce engineering risk, but it would not settle licensing, siting or cost, and those are the factors that will determine whether small nuclear actually takes a share of the on-site power market from gas.
Background
Crusoe is a neocloud, a cloud provider focused on AI computing, that builds its own data centers, including its modular Spark design. It has pursued several energy sources, including natural gas, solar and batteries, to power those sites as grid capacity for data centers has become harder to secure. Aalo Atomics is a nuclear developer building factory-made reactor pods. Its first product is the Aalo One Reactor in a 50-megawatt Aalo Pod configuration, and the company reached criticality within three years of its founding.
Nuclear power has become a major topic in data center planning. All three major hyperscalers have signed nuclear supply agreements, mostly with large existing plants. Small modular reactors are a newer, largely unproven category. Proponents argue they can avoid the decade-plus build times and cost overruns of traditional nuclear, but they have yet to demonstrate that at commercial scale.
