Amazon agreed to buy backup generators from Generac, the company best known for the generators that keep homes running during blackouts. These machines do the same job for the giant computer buildings behind online services, starting up when the regular power fails.
About $2.4 billion worth is expected to be delivered in 2027 and 2028. Amazon also gets the right to buy Generac stock at a fixed price, and that right grows the more generators Amazon buys, up to $8 billion.
The first $2.4 billion has a date on it. The rest only happens if Amazon keeps building.
On September 16, 2026, Generac Holdings (NYSE: GNRC) and Amazon.com signed a long-term supply agreement for backup power generators for Amazon data centers, according to an 8-K Generac filed the same day. Initial deliveries are expected to total $2.4 billion across 2027 and 2028. Alongside the supply deal, Generac issued an Amazon subsidiary a warrant to buy up to 1,693,745 Generac shares at $200.9266 each. Some of those shares vested immediately, and the rest vest as Amazon’s generator payments accumulate, up to a total of $8 billion.
Yahoo Finance reported that Generac shares rallied on the news.
Executive Summary
Generac’s filing makes Amazon a named buyer of data-center backup power, the generators that carry a facility through a grid outage once its batteries run down. It puts two numbers on the relationship. The first is $2.4 billion in expected deliveries over two years. The second is an $8 billion ceiling on the purchases that can unlock Amazon’s equity stake.
Those two figures measure different things. The $2.4 billion is a delivery expectation with dates attached. The $8 billion is the spending level at which Amazon’s warrant fully vests, and the warrant runs until September 2033. Most of the headline figure is therefore contingent: it turns into revenue only if Amazon keeps building data centers that need Generac equipment.
The structure also shows who is paying for what. Generac is giving its customer equity upside in return for volume. For Generac shareholders, that is a trade of some future dilution for a large anchor buyer. For the wider data-center supply chain, it signals that backup generation is now valuable enough to be locked in years ahead with financial ties that go beyond a purchase order.
The $8 Billion Is a Ceiling, Not an Order
The 8-K describes two separate instruments. The long-term supply agreement governs what Amazon buys, and the only scheduled volume it discloses is the $2.4 billion in initial deliveries expected in 2027 and 2028. The warrant governs what Amazon earns, and it vests in tranches “contingent upon aggregate gross payments, net of certain offsets” from Amazon for data-center backup generators, “up to a total of $8 billion.” The $8 billion is the point where the incentive stops growing. It is not a commitment to spend that much.
Scheduled deliveries cover 30% of that ceiling. The remaining $5.6 billion has no timetable in the filing, only an outer boundary: the warrant can be exercised on or before September 16, 2033. Every new hyperscale data center needs its own backup generation, sized to its electrical load. Whether Generac’s revenue approaches the $8 billion mark therefore depends on how many facilities Amazon builds over the next seven years, how large they are, and how much of that generator demand Generac wins against other suppliers.
This matters to three groups. Investors should model $2.4 billion as the disclosed baseline and treat anything above it as dependent on Amazon’s construction pace. Generac’s factory planning has to support a two-year delivery ramp without knowing what comes after 2028. Other generator suppliers now face a buyer that has a financial incentive to direct its volume toward one vendor.
Generac Is Paying for Volume in Equity
A warrant is the right to buy shares later at a fixed price. Here the supplier grants it to the customer. That makes it a volume incentive paid in stock rather than cash. Of the 1,693,745 warrant shares, 307,954 (about 18%) vested at signing, which works as an upfront signing incentive. The other 1,385,791 unlock only as Amazon’s payments grow. Spread evenly across $8 billion, that would be roughly one share for every $5,770 of generator purchases. The filing says only that vesting occurs in “multiple tranches” and does not give the actual schedule.
The economics favor Amazon when Generac’s stock trades above the $200.9266 strike price. Buying all 1,693,745 shares would cost about $340 million at that price. However, Amazon can choose a cashless exercise, receiving the net value in shares without paying cash. Generac has also granted registration rights, which make it easier for Amazon to sell those shares later. The result ties part of Amazon’s return to Generac’s share price, and that price should rise as Amazon buys more generators. Existing Generac shareholders bear the cost through potential dilution. The warrant’s strike price and share count are also subject to anti-dilution adjustments.
A Home-Standby Brand Takes a Hyperscale Test
Generac built its name on home standby generators. Data-center backup is a different business. The units are larger, reliability requirements are strict, and a hyperscaler’s construction schedule does not move because a supplier fell behind. Having Amazon as a named, contracted buyer is the clearest external validation of Generac’s data-center push so far. It also exposes Generac to a direct test: delivering $2.4 billion of equipment within two calendar years, to a customer that can measure its performance precisely.
Amazon’s broader funding shows how much money is flowing into these projects. Two days before the Generac agreement, Amazon’s own 8-K reported that it closed a £4.25 billion sterling bond sale, with coupons ranging from 5.200% on notes due 2029 to 6.650% on notes due 2045. Nothing in that filing links the proceeds to Generac or to data centers in particular. What it does show is a buyer raising capital at a scale where multi-year equipment commitments are routine. For Amazon, a warrant that pays off only if Generac performs is an inexpensive way to secure a supply chain it will need regardless.
Background
Generac Holdings, which trades as GNRC, is best known for home standby generators, the units that switch on automatically when a house loses power. Data-center backup power is a larger, more demanding version of the same product. Each facility needs enough on-site generation to carry its full electrical load through a grid outage, and hyperscale operators such as Amazon buy these systems in volume as they build new campuses.
Warrants tied to a customer’s purchases are an established way for suppliers to secure large buyers. The supplier grants equity upside that grows as the customer spends. Generac’s agreement follows that model, pairing a long-term supply contract with a warrant that vests against Amazon’s generator payments.
A small energy and data center developer, New Era Energy & Digital, agreed to buy electricity from Vistra, one of the largest private power generators in the United States, for the next twenty years.
The amount is 207 megawatts — roughly the electricity a small city uses, running day and night.
New Era’s share price jumped 16 percent on the news.
Why it matters: computer warehouses that run artificial intelligence need enormous, uninterrupted power. Locking in a supply for two decades is increasingly what banks require before they will lend the money to build one.
New Era Energy & Digital has signed a 20-year power purchase agreement with Vistra Corp. covering 207 megawatts of electricity, the company announced in a release distributed through GlobeNewswire. A power purchase agreement, or PPA, is a long-term contract under which a buyer commits to purchase a set volume of electricity from a generator, usually at a pre-agreed price structure.
Investing.com reported that New Era’s stock rose roughly 16% on the announcement. Vistra, an NYSE-listed independent power producer with a large fleet of generating plants and a retail electricity business, sits on the supply side of the contract. The announcement disclosed the counterparty, the contract term and the contracted capacity; it did not attach a price, a delivery start date or a named end user for the power.
Executive Summary
Two numbers define this deal: 207 and 20. The first is the capacity — enough to power a campus-scale data center, not a pilot. The second is the term, and it is the one that matters more to anyone financing digital infrastructure. Twenty years sits at the long end of the range for corporate power contracts, which more commonly run ten to fifteen years.
The significance is structural. Over the past two years, the binding constraint on new AI-capable data center capacity has moved from chips to land to interconnection to, now, contracted electricity. A developer that can show a lender a two-decade supply agreement with a creditworthy generator has converted its single largest and most volatile operating input into something closer to a fixed cost. That is the document that makes a construction loan underwritable.
For Vistra, the transaction is an example of the trade that has re-rated the independent power sector: selling long-dated output to digital load instead of leaving it exposed to wholesale market swings. For New Era — a far smaller company, judging by the size of the share-price reaction — it is a credential as much as a commodity purchase.
Why the Term Sheet, Not the Megawatts, Clears the Financing
Lenders to data center projects underwrite two things above all: revenue certainty on the customer side and cost certainty on the input side. Power is typically the largest recurring operating expense in a high-density computing facility, and in wholesale markets it is also the most volatile. A project that buys electricity at spot or on a short rolling contract carries an open-ended cost exposure across a 15-to-20-year debt tenor — precisely the mismatch that credit committees discount hardest.
A 20-year PPA closes that gap. It matches the electricity contract to the useful life of the building and, more importantly, to the amortisation schedule of the debt. At 207 megawatts of contracted capacity, the annual electricity spend is large enough that a few cents per kilowatt-hour of price movement swings project economics materially; fixing or collaring that number is what allows a sponsor to model a debt service coverage ratio a lender will accept. This is the mechanism behind the headline: the deal that clears financing is not the one with the most megawatts, it is the one with the longest defensible price.
The people affected sit well beyond the two counterparties. Developers competing for the same capital are now benchmarked against this structure. Generators with dispatchable fleets gain a new class of long-duration offtaker. And prospective data center tenants — the hyperscalers and AI companies that ultimately lease the space — inherit whatever price the developer locked in, for two decades.
207 Megawatts Is a Campus, Not a Pilot
Capacity figures in this sector are easy to misread. A single enterprise server hall might draw a handful of megawatts. A 207-megawatt commitment is campus scale — the order of magnitude associated with multi-building developments serving large cloud or AI tenants, drawing power continuously rather than at a daytime peak.
Loads of that size cannot simply be requested from a utility on a normal timetable. Interconnection queues — the waiting lists grid operators maintain for new large connections — now run years in many US markets, and queue position has become a genuine asset. Contracting with an existing independent power producer that already owns generating plants is one of the few routes that does not begin with building something new. It does not eliminate the need for transmission and interconnection work, but it does change what the developer has to prove to get there.
What a 16% Move Prices In, and What It Doesn’t
A double-digit single-day move tells you something about relative scale: 207 megawatts is transformative for New Era in a way it is unlikely to be for Vistra’s consolidated results. Equity markets are reacting to the credibility conferred by the counterparty as much as to the contract’s economics, which were not disclosed.
It is worth stating plainly what a PPA is and is not. It is an obligation as well as an enabler. Depending on structure, the buyer may owe payment for contracted volumes whether or not the load materialises — the same term that protects the project against price risk creates exposure if the data center is delayed, downsized, or never leased. Until the price, the shape of delivery and the identity of the end customer are known, the market is pricing a durable input at an unknown cost against demand that has not been publicly contracted. That is a reasonable thing to be optimistic about; it is not yet a verified margin.
Background
Over the past two years, the constraint on building AI-capable data centers has migrated. First it was chips, then suitable land and buildings, then grid interconnection — the queue of applications that grid operators process before a large new load can be energised. The current binding constraint for many developers is securing firm, long-dated electricity at a price they can underwrite, which has pushed independent power producers into direct, multi-decade contracts with digital infrastructure companies.
Vistra is among the US generators that own dispatchable plants and sell their output into wholesale markets and to retail customers. For companies with that profile, contracting output to data centers trades merchant price upside for revenue visibility. On the other side, developers such as New Era Energy & Digital — which positions itself at the intersection of energy and digital infrastructure — treat a signed supply contract as a prerequisite for raising the capital to build.
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.
A batch of specially made salt just changed hands in Texas. The federal Department of Energy shipped it to Natura Resources, a company building a small nuclear reactor on a university campus in Abilene.
The salt is the reactor’s coolant. Instead of water held under enormous pressure, this design runs on hot liquid salt — made from a rare, highly purified form of lithium that hardly anyone produces.
Why care: Texas needs round-the-clock electricity for the giant computer warehouses that run artificial intelligence. Reactors like this are one proposed answer, and one of their hardest-to-source ingredients is now in hand.
Natura Resources LLC announced on September 18 that it has received FLiBE salt — a fluoride mixture of lithium and beryllium used as a molten-salt reactor coolant — from the U.S. Department of Energy’s Oak Ridge National Laboratory, routed through Idaho National Laboratory. The material is destined for the MSR-1, a molten salt demonstration reactor the company is building at Abilene Christian University in Abilene, Texas.
Natura said it won the salt through a competitive DOE solicitation facilitated by Idaho National Laboratory and issued in August 2025. The company said the salt contains 99.99% enriched lithium-7, an isotopic purity that suppresses the formation of tritium inside the coolant loop. Natura describes itself as privately owned, with more than $120 million in private funding and a $120 million commitment from the State of Texas, and holds what it says is the first Nuclear Regulatory Commission construction permit issued for a liquid-fueled reactor.
Executive Summary
The headline event is a shipment, not a groundbreaking — but shipments are where advanced nuclear schedules actually slip. Molten salt reactors substitute a liquid salt for the pressurized water used in conventional plants, which is what lets them run hot and near atmospheric pressure. That coolant is not a commodity. Getting it right requires lithium enriched to a specific isotope, lithium-7, at a purity Natura puts at 99.99%.
The reason the purity matters is operational rather than ceremonial. Natural lithium contains a meaningful fraction of lithium-6, which absorbs neutrons and produces tritium — a radioactive hydrogen isotope that migrates readily through hot metal and creates containment, monitoring and worker-protection burdens for the life of the plant. Stripping the lithium-6 out up front converts a permanent operating problem into a one-time procurement problem. That procurement, on Natura’s own account, was resolved by winning a federal allocation rather than placing an order.
For the Texas power market the relevance is indirect but real. Data center load growth in the state has made any firm, siteable generation valuable, and advanced nuclear is one of the options developers keep on the table. The MSR-1 is a demonstration unit intended to generate data for Natura’s commercial reactors; the company disclosed no capacity rating, no in-service date and no customer alongside the salt delivery.
The Scarce Input Is the Coolant, Not the Paperwork
Advanced nuclear coverage tends to track licensing milestones, because licenses are public, dated and easy to compare. Natura has one of the notable ones — it says it holds the first NRC construction permit for a liquid-fueled reactor. But a permit authorizes construction; it does not conjure the materials the design requires. This week’s event is the quieter constraint clearing, and the structure of the transaction tells you how tight it is.
Consider what Natura describes: salt held at a national laboratory, released through a competitive solicitation issued in August 2025, facilitated by a second national laboratory, and delivered more than a year later. That is the procurement pattern of an allocated stockpile, not a supply chain. Enriched lithium-7 at 99.99% is a Cold War-era product of isotope separation programs, and a developer that wins a tranche of it has removed a risk that competitors bidding on the same solicitation did not. Natura’s own framing — that the delivery secures “one of the most specialized inputs required” and reduces supply-chain risk — is an unusually direct admission that the material was a gating item.
The downstream implication is the part that matters for anyone financing or contracting firm power. If the coolant for a first-of-a-kind unit has to come from a federal solicitation, then the question for every molten salt program is what happens at unit two, unit ten, and at commercial scale, when legacy inventory cannot cover the order book and someone has to build enrichment capacity. That is a multi-year industrial problem with its own permitting, capital and workforce constraints, and it sits upstream of every megawatt these designs promise. Developers, utilities and data center buyers evaluating molten salt timelines should be asking about lithium-7 supply with the same seriousness they ask about NRC dockets.
Texas Is Buying Optionality on Firm Power
Natura discloses a $120 million commitment from the State of Texas alongside more than $120 million in private funding. That pairing is the more revealing number in the release. Texas has watched data center interconnection requests pile up against a grid that must serve them on the hottest and coldest days, and firm generation — power that runs regardless of weather — is the scarce commodity. State money in a pre-commercial reactor developer is not an energy purchase; it is a call option on a technology that, if it works, can be sited near industrial load without a transmission build.
What the announcement does not do is connect that option to load. The MSR-1 is a demonstration reactor on a university campus, and Natura says plainly that its purpose is to generate data for commercial reactors. No capacity figure, no offtake agreement and no data center customer appears anywhere in the disclosure. Readers evaluating this as an AI-power story should hold both facts: the material bottleneck is genuinely smaller today, and the distance between a campus demonstration unit and a contracted megawatt on an industrial site remains long.
A 13,000-Hour Precedent Is Heritage, Not Qualification
Natura leans on the Molten Salt Reactor Experiment, which ran at Oak Ridge from 1965 to 1969 and logged more than 13,000 operating hours demonstrating passive safety, high-temperature performance and fuel flexibility. The lineage is real, and receiving MSRE-era salt from the laboratory that ran the experiment makes for a legitimate through-line. It is also a reason the material exists at all.
The analytical caution is that operating hours from the 1960s are evidence the physics works, not evidence that a modern commercial unit will license, build and run on schedule. The MSRE was a research reactor with no requirement to sell power, meet a modern regulatory framework, or hit a cost of capital. Sixty years of institutional memory attrition sits between that program and this one, which is precisely why demonstration units like the MSR-1 exist. The honest read of this week’s news is narrow and still meaningful: one specialized input is secured, one category of schedule risk is retired, and the rest of the program is still ahead of the company.
Background
Molten salt reactors are an old idea with a short operating record. The Molten Salt Reactor Experiment at Oak Ridge National Laboratory ran from 1965 to 1969 and accumulated more than 13,000 hours, establishing that a reactor could run with its fuel dissolved in circulating salt at high temperature and low pressure. The program ended without commercialization, and the technology sat largely dormant for decades while the industry standardized on pressurized and boiling water designs.
Natura Resources LLC, based in Abilene, Texas, is one of the developers attempting to carry the concept into commercial service. It is privately owned, reports more than $120 million in private funding plus a $120 million commitment from the State of Texas, and says it holds the first NRC construction permit granted for a liquid-fueled reactor. Its first unit, the MSR-1, is under construction at Abilene Christian University and is intended to produce the operating data that commercial designs will be built on. Jordan Robison was named chief executive officer ahead of this phase of the program.
Sources
Source: Natura Receives Historic Molten Salt Reactor Coolant from Department of Energy — Natura Resources’ September 18, 2026 announcement that it received FLiBE salt from the Department of Energy’s Oak Ridge National Laboratory, via Idaho National Laboratory, for its MSR-1 demonstration reactor in Abilene, Texas.
Artificial intelligence computers draw electricity in sudden bursts, which can jolt the power grid the way a heavy factory switching on and off does. At a conference in Shanghai, Huawei showed gear meant to let large AI computing sites soak up those swings with batteries, and even help steady the grid instead of straining it.
It also pushed a different scorecard. Instead of measuring how much power a building wastes, measure how much useful artificial intelligence work each unit of electricity buys. The Chinese firm SenseTime says it has improved that figure by 80 percent.
Huawei used the HUAWEI AIDC Facility Summit, held alongside HUAWEI CONNECT 2026 in Shanghai on September 20, 2026, to launch what it calls a grid-interactive AIDC solution — a package of power and cooling equipment for AI data centers built around what the company labels “3+1” innovations. The announced version 1.0 combines a grid-friendly uninterruptible power supply, intelligent lithium batteries and grid-forming energy storage, alongside an AI-managed liquid cooling system that predicts the condition of its working fluids to schedule maintenance before failures. In the power domain, Huawei also outlined a longer-horizon “MIMO” power supply architecture.
Hou Jinlong, Director of the Board of Huawei and President of Huawei Digital Power, opened the summit with four design arguments: pairing new power architecture with liquid cooling, using multi-layer hybrid storage to absorb local power fluctuations, coupling electricity and compute so data centers stop behaving as rigid loads, and shifting to modular, prefabricated delivery to cut construction lead times. Speakers from VNET Group and SenseTime shared the stage; SenseTime’s Lin Hai said end-to-end optimization had improved SenseCore’s tokens per watt by 80%.
Executive Summary
The substance of the announcement is architectural rather than financial. Huawei is proposing that an AI data center should be designed as a participant in the power system — able to hold its own voltage and frequency behavior steady through grid-forming storage, and to buffer the second-to-second swings that large training and inference clusters impose — rather than as a fixed block of demand that a utility must simply serve.
That framing matters because grid connection, not construction, is increasingly what sets the calendar for AI capacity. A site that arrives at the utility as a controllable, power-quality-friendly asset is a different negotiation from one that arrives as raw megawatts of volatile load. Huawei’s pitch, delivered by Digital Power Vice President Bob He, is that as renewables raise the share of power-electronic sources on the grid, compute and energy infrastructure can no longer be planned independently.
The second half of the pitch is a measurement change. Huawei and SenseTime both argued for scoring AI facilities on tokens per watt — useful model output per unit of electricity — instead of power usage effectiveness, the long-standing ratio of total facility power to IT power. That is a bigger change than it sounds, because it moves the boundary of the efficiency calculation outward to the grid and inward to the model at the same time.
Why a Data Center Would Want to Look Like a Grid Asset
A conventional data center is, from a utility’s point of view, a well-behaved but inflexible customer: it wants a large, constant, highly reliable supply and offers nothing back. AI clusters break the “well-behaved” half. Synchronized training jobs can ramp thousands of accelerators together, producing what the release describes as rapid and severe power fluctuations, and Huawei’s speakers named the consequences utilities worry about — disconnection events and unstable wideband oscillation, meaning sustained electrical ringing across a range of frequencies that neither the site nor the grid damps out.
The engineering answer Huawei describes is layered storage sitting between the workload and the grid. Batteries and grid-forming inverters absorb the swing locally, so the fluctuation never reaches the interconnection point; grid-forming units go further by actively setting voltage and frequency rather than following the grid, which is what allows a site to support a network with a high share of inverter-based renewable generation instead of leaning on it. VNET Group Founder and Chairman Josh Chen extended the idea to campus scale, describing direct green power connections, active microgrids and direct-current distribution inside buildings as the way to serve gigawatt-class AI campuses.
The commercial logic follows from scarcity. When interconnection capacity is the binding constraint on AI buildout, the cheapest new megawatt is often the one a developer does not have to request. Equipment that lets a site ride through disturbances, shave its own peaks and behave predictably at the meter is, in effect, a substitute for grid capacity that has not been built yet — and a bargaining chip in queue discussions. Huawei has not published evidence on how much connection time or capacity this saves in practice, which is the number that would turn the argument into a business case.
Tokens Per Watt Redraws the Boundary of the Efficiency Question
Power usage effectiveness has governed data center efficiency for two decades. It is a facility-boundary ratio: total power into the building divided by power reaching the IT equipment. It says nothing about whether the servers do anything useful. Once a site is spending most of its energy on inference, that blind spot becomes the main event — a facility can post an excellent PUE while running inefficient hardware on badly scheduled work.
Tokens per watt closes that gap by measuring output rather than overhead, and this is where the 80% figure does its work. SenseTime’s Lin Hai described SenseCore’s improvement as end-to-end, spanning power plants and grids, rack services in the data center, compute cloud services and model services. That is the whole chain, not the mechanical plant. A number of that size is therefore not evidence that any single piece of equipment got 80% better; it is evidence that when you draw the measurement boundary that wide, most of the available gain sits in layers the facility team has never been scored on — and, at the far end, in the grid supplying the site. Huawei’s Hou Jinlong put the same point commercially: maximizing tokens per watt and minimizing cost per token will be the core competitiveness of what he called compute factories.
Who this affects is concrete. Colocation operators sell space, power and a PUE commitment; they do not control the model, the scheduler or the chip, so they cannot be held to a tokens-per-watt number without a very different contract. Chip vendors and inference-software teams gain, because their contribution finally appears in the facility scorecard. Utilities gain a vocabulary for load that varies in usefulness as well as size. The catch is standardization: tokens differ by tokenizer, model and precision, so an 80% improvement is a credible internal engineering result and not yet a figure that can be compared across operators. No published methodology accompanied the claim.
The Delivery Clock and the Question of Who Can Buy It
Hou’s fourth argument — modular, prefabricated, product-based delivery to shorten lead time — is the least glamorous and arguably the most operationally consequential. In a market where the constraint is time to first megawatt, converting site-built electrical and cooling systems into factory-built blocks shifts the schedule risk from a construction crew to a production line. It also suits Huawei’s structural position: the company is selling the power chain and the cooling chain and the compute stack, and Bob He explicitly named end-to-end energy plus full-stack AI as the differentiator.
That integration is genuinely hard for point-product vendors to match, and it is also the strongest argument against buying it. A grid-interactive architecture in which the uninterruptible power supply, the batteries, the grid-forming storage, the liquid cooling controller and the workload scheduler are co-designed is, by construction, difficult to unbundle later. Buyers evaluating it should ask what the interfaces are and whether any layer can be swapped — questions the launch materials do not address.
Market context also shapes who this is for. The named practitioners on stage — VNET and SenseTime — are China-based, and the summit sat inside a conference where Huawei also presented an upgraded Stellar AI Network solution and released its Intelligent World 2035 report series setting out ten key directions. The ideas here travel further than the product does: measuring output per watt, buffering workload volatility on site and offering grid services are design responses any operator facing a long interconnection queue will recognize, whatever equipment ends up in the building.
Background
Huawei Digital Power is the Huawei division that sells power conversion, energy storage, solar inverter and data center power and cooling systems — a business adjacent to, but distinct from, the company’s networking and computing lines. Its data center pitch has increasingly merged with Huawei’s AI compute strategy, on the argument that the electricity system and the compute system are now a single engineering problem. HUAWEI CONNECT is the company’s annual flagship conference; the 2026 edition in Shanghai also produced an upgraded Stellar AI Network solution and a set of Intelligent World 2035 research reports laying out ten key directions.
The wider context is a buildout constrained by electricity rather than silicon supply alone. Racks designed for AI accelerators draw many times what general-purpose servers did, pushing operators to liquid cooling and to far larger grid connections, while utilities in many markets face multi-year queues to study and approve new large loads. That has pushed the industry toward on-site generation, storage and demand flexibility, and toward efficiency metrics that account for useful work rather than facility overhead. VNET Group is a Chinese carrier-neutral data center operator; SenseTime is a Chinese AI company whose SenseCore platform runs its own intelligent computing centers.
Chattanooga’s city-owned electric company, EPB, has switched on a quantum computer, an experimental machine that works very differently from a laptop, built by a company called IonQ.
Its first job is to help the power company run its own electric grid more cheaply and reliably, paid for by a $4 million federal science grant.
Local universities will start using it in early October.
It is unusual for a power company to host a computer like this, and the bigger promises about jobs and economic growth are still forecasts.
EPB, the municipally owned electric and fiber provider in Chattanooga, Tennessee, said on Sept. 18, 2026 that it has launched an IonQ Forte Enterprise quantum computer at its EPB Quantum Center, in a release distributed via PR Newswire. The utility describes the site as America’s first commercial hub offering both quantum computing and quantum networking under one roof.
The first users are eight EPB Quantum Computing Fellows, graduate researchers funded by a $4 million National Institute of Standards and Technology (NIST) grant, who are developing algorithms to optimize EPB’s power grid. EPB says its quantum computing service opens for business in early October, with the University of Tennessee at Chattanooga (UTC) as its first customer and Vanderbilt University lining up a first project.
Executive Summary
EPB is adding a quantum computer to a quantum network it launched in 2023, turning an electric utility into a host for specialized computing. The machine comes from IonQ, which separately is investing $15 million in a Tennessee Quantum Communications Research Center in Chattanooga with plans for about two dozen jobs. EPB, IonQ, Oak Ridge National Laboratory and NVIDIA have also installed a classical supercomputer inside the same facility for a hybrid project that combines the two kinds of computing to optimize parts of EPB’s automated grid.
What matters most is the order of use. Before any outside business pays for time, the machine’s first workload is the utility’s own grid, followed by two universities. That gives the system a guaranteed, research-grade user base on day one, but it also means commercial demand from companies outside academia and EPB itself is not yet demonstrated in the announcement.
The release also cites larger projections, including up to $1.1 billion in local economic gains over a decade and $2.7 trillion in potential economic value from quantum computing, which are forecasts rather than commitments.
The Anchor Tenant Is the Grid Itself
Any operator hosting expensive, scarce compute faces the same early problem: keeping the machine busy with work that justifies it. EPB’s answer is to be its own first customer. According to the utility, the EPB Quantum Computing Fellows, eight graduate researchers funded by a $4 million NIST grant, will be the first to run workloads, specifically algorithms aimed at optimizing local power grid circuits to reduce costs and improve resilience. The hybrid project with Oak Ridge National Laboratory, NVIDIA and IonQ points at the same target: portions of EPB’s automated electric grid.
This is the mechanism behind the headline. A utility running a highly automated grid has a built-in optimization problem, such as how power flows through circuits and how to reconfigure them, that it can hand to a new computing platform without first finding a buyer. External demand comes next, and it is academic: UTC begins in early October with research it is already prepared to run, and Vanderbilt is still lining up its first project. For vendors like IonQ, a host that brings its own workload lowers the risk of an idle installation. For other utilities, the takeaway is narrower but real: owning the problem can be as important as owning the power or the fiber.
The flip side is that the announcement names no paying commercial customer outside universities. The model is anchored in research, and its commercial proof point is still ahead.
Why a Utility Can Host Compute at All
Most compute hosts are data-center operators or cloud providers. EPB’s case rests on assets a typical utility does not have. It built a 100% fiber-to-the-home network starting in 2010, now offering service up to 25 gigabits per second, and launched the EPB Quantum Network in 2023. Quantum networking, which moves fragile quantum information over fiber, depends on exactly the kind of dark and lit fiber a telecom-savvy utility controls.
The Board chair’s comparison to the 2010 gig-speed rollout is the strategic tell: EPB is repeating a playbook of building infrastructure ahead of demand and marketing the city around it. That worked for broadband. Whether it works for a technology still largely in the research phase is a different question, and the release is candid that the near-term users are researchers.
Hybrid, Not Quantum Alone
One of the more substantive details is easy to miss: a classical supercomputer now sits inside the EPB Quantum Center. Quantum processors today generally work alongside conventional computers rather than replacing them, with the classical machine handling most of the calculation and the quantum system tackling specific sub-problems. Co-locating both, with a national laboratory and NVIDIA as collaborators, is a practical design choice that reflects how quantum workloads are actually run.
For facility operators, that means a quantum site is not just a single exotic box. It carries the power, cooling and networking requirements of conventional high-performance computing too, which is one more reason a utility with its own grid and fiber is a plausible host.
Commitments Versus Projections
The release mixes firm commitments with forecasts, and they deserve different weight. Concrete items include the $4 million NIST grant, eight fellows, IonQ’s $15 million research center with about two dozen planned jobs, the October service start, and an academy expected to serve roughly 400 high school students a year from 2028.
Softer items include UTC’s plan to add 135 to 240 faculty, staff and students, Vanderbilt’s roughly 250-person institute, the Mayor’s figure of up to $1.1 billion in local economic gains over a decade, and a projected $2.7 trillion in near-term economic value from quantum computing. The release does not give the methodology behind the latter two figures. The “first” claims are also carefully qualified: first to offer commercially available quantum computing and quantum networking in one facility, not the first quantum computer available commercially in the country.
Background
EPB is a Chattanooga utility that provides both electricity and communications. In 2010 it began building a 100% fiber-to-the-home network that it describes as the world’s first community-wide gig-speed internet service, now offering up to 25 gigabits per second, alongside a highly automated electric grid. In 2023 it launched the EPB Quantum Network, and UTC became what the release calls the first American university connected to a commercial quantum network.
IonQ is a quantum computing company whose Forte Enterprise system is now installed at the EPB Quantum Center. Quantum computers use the physics of very small particles to approach certain problems, such as optimization and simulation, differently from conventional machines, though most practical work today pairs them with classical computers.
A giant battery site in Moss Landing, California, caught fire again on Friday. The owner is Vistra, a large power company. The site uses batteries to store electricity for the grid, and it already burned badly in January 2025.
This time about 1,500 battery packs caught fire. They had been unplugged from the grid after the last fire, but they still held a charge. About 106 nearby residents were told to stay indoors.
This matters because power companies and huge computing centers are counting on big batteries to keep the lights on. A battery that has been switched off can still catch fire.
A fire broke out shortly after 6:15 a.m. on Friday, September 18, 2026, at Vistra’s battery storage facility in Moss Landing, California, the Salinas Californian reported. It started in the Moss 300 building, the same structure heavily damaged in the January 2025 fire. North Monterey County Fire District Chief Jess Cortez said the fire involved the roughly 1,500 battery modules left on the building’s north side. By a noon briefing there was no active flame. The site was “hot and smoldering” and expected to burn out within 24 hours, with drones checking battery temperatures.
A shelter-in-place order covered about 106 residents within a third of a mile of the plant, and Dolan Road stayed closed near the site. Vistra temporarily shut down the natural gas plant on the same property as a precaution. No injuries were reported. Air monitors detected some fine particulate matter (PM 2.5), but none above screening levels, and no hydrogen fluoride.
Executive Summary
This is the second fire in about 20 months at one of the world’s best-known grid-scale battery sites. The detail that matters most is where it happened. Vistra plant manager Ron George said the modules that burned were idle and disconnected from the grid, but still energized, inside a unit Vistra has already retired and is remediating with the U.S. Environmental Protection Agency.
For utilities and data-center developers who plan to use large batteries as “firming” capacity, meaning storage that fills gaps when solar, wind or other supply falls short, the lesson is about the full life of the asset. A battery that has left service can still hold energy and still ignite. The cleanup phase therefore carries its own safety, siting and insurance risk. Vistra also shut down the neighboring gas plant as a precaution, which shows how a battery incident can reach other generation on the same site.
Both Vistra’s investigation into the cause of the January 2025 fire and a California Public Utilities Commission investigation are still open. A second fire has now occurred before either has reported a root cause.
Retired Is Not the Same as Safe
The headline fact is simple. The 1,500 modules that burned on September 18 were not delivering power to anyone. George said they were idle and disconnected from the grid but still energized. The Moss 300 unit was retired after the 2025 fire, and Vistra is working with the EPA on remediation. The modules that burned were sitting in a damaged building while that cleanup was under way.
This is how lithium-ion storage behaves in general. Unplugging a battery from the grid stops it from trading power, but it does not remove the chemical energy stored in its cells. Until modules are discharged, removed or otherwise made safe, a damaged battery building remains a hazard. Operators usually model safety risk during commercial operation. Moss Landing shows that the period after an asset stops earning revenue can carry comparable risk, and the local community still bears it.
That changes the math for anyone buying storage-backed power. A data-center operator or utility signing a long-term capacity contract is exposed to more than the chance that a battery fails during its service life. It is also exposed to how long a failed asset takes to wind down, and to what happens to neighboring assets while it does.
One Fire, Two Assets Offline
Vistra shut down the onsite natural gas plant “out of an abundance of caution.” Co-locating batteries with existing generation is attractive because it reuses grid connections, land and permits that took years to secure. Moss Landing shows the other side of that choice. An incident at the battery portion of a site can take down generation that has nothing to do with the batteries, at least temporarily.
This correlation is directly relevant to AI infrastructure planning. Large computing campuses increasingly look for power from sites that pair several resources: gas, storage and solar. The goal is reliability through diversity. If one resource’s safety incident forces a precautionary shutdown of another, the reliability benefit of pairing them is smaller than it appears on paper. Buyers need to know how often that can happen and how long it lasts.
Safeguards Worked, but Answers Are Still Pending
Parts of the response went well. After the 2025 fire, the Monterey Bay Air Resources District oversaw installation of six additional air sensors. Four sit at the facility fence line, one at Elkhorn Elementary School and one at a nearby boatyard. Officials reported fine particulate readings within health standards and no hydrogen fluoride, a toxic gas that burning lithium-ion cells can release. Schools outside the shelter zone lifted their own orders the same day. No one was hurt.
The monitoring also has limits. The air district’s Richard Stedman said the sensors are not testing for heavy metals, “although we would expect that to be in the smoke.” And the core question from 2025, why the original fire started, remains open in both Vistra’s investigation and the CPUC’s. Without a published root cause, other operators, insurers and permitting authorities cannot yet say which design, spacing or suppression changes would prevent a repeat. The industry is still waiting for that input to its siting and insurance decisions.
Background
Vistra Corp. is a large U.S. power producer. At Moss Landing on California’s Monterey Bay, it built one of the world’s largest battery energy storage installations next to an existing natural gas power plant, reusing the site’s grid connections. The batteries charge when power is abundant and discharge when California’s grid needs extra supply, often in the evening as solar output fades.
In January 2025 a major fire damaged the facility’s Moss 300 building, which Vistra has since retired. After that fire, the Monterey Bay Air Resources District oversaw installation of six additional air monitoring sensors around the site and the community. Vistra and the California Public Utilities Commission are each still investigating the 2025 fire’s cause.
Pennsylvania’s environmental regulator has approved how the Three Mile Island nuclear plant may use river water if it restarts. The plant’s power has been promised to Microsoft to help run its computer centers.
On its busiest days the plant could draw up to 73 million gallons from the Susquehanna River, enough to fill more than 100 Olympic swimming pools. About 21 million gallons a day would turn to steam and not return.
The takeaway: reviving old nuclear plants for artificial intelligence depends on rivers and fish, not just reactor safety.
The Pennsylvania Department of Environmental Protection (DEP) has issued a Section 401 Water Quality Certification for restarting Constellation Energy’s Three Mile Island nuclear plant in Londonderry Township, Dauphin County, PA Environment Digest reported on September 18, 2026. Notice of the decision appears in the September 19 edition of the Pennsylvania Bulletin, the state’s official register.
The certification covers water withdrawals from the Susquehanna River of up to 73.2 million gallons per day on a peak day, consumptive use of up to 21 million gallons per day, and heated-water discharges back to the river at a maximum of 110°F. Anyone aggrieved by the decision has 30 days from the notice to appeal to Pennsylvania’s Environmental Hearing Board.
Executive Summary
A Section 401 certification is the state’s formal finding that a federally licensed project will meet state water quality standards. For a nuclear plant, the federal license comes from the Nuclear Regulatory Commission (NRC), and under the federal Clean Water Act that license cannot take effect for an activity discharging into U.S. waters unless the state certifies it or waives its right to do so. DEP’s action therefore removes a state-level condition on the path to restarting Unit 1, the reactor Constellation has agreed to run for Microsoft under a 20-year power purchase agreement announced in 2024.
The certification also puts hard numbers on the restart’s physical footprint. The plant expects to withdraw up to 73.2 million gallons a day at peak and consume up to 21 million gallons, water lost to evaporation in cooling towers rather than returned to the river. DEP concluded that closed-cycle cooling will minimize harm to fish drawn into or trapped against the intake.
The decision is not yet final in a practical sense: the 30-day appeal window is open, and the certification is one of several approvals a restart needs. But it shows that the fastest route to firm, carbon-free power for AI, reviving a plant that already exists, still runs through water regulators.
Why a Water Permit Gates a Reactor Restart
Most coverage of nuclear power for AI focuses on the NRC, which judges whether a reactor is safe to operate. The Three Mile Island certification highlights a second, parallel track. A steam-cycle power plant is, in large part, a machine for moving heat into water: it pulls water from a river, uses it to condense steam, and either evaporates it through cooling towers or sends it back warmer. Every one of those steps touches state water quality law.
DEP’s notice identifies three impacts it had to weigh: withdrawal from the Susquehanna, consumptive use, and thermal discharge into a river designated for warm water fishes and migratory fishes. The figures are specific. Peak withdrawal of up to 73.2 million gallons a day, consumptive use of up to 21 million gallons a day, and a discharge temperature ceiling of 110°F. Those numbers define what the restarted plant is permitted to do, and they are set by the state, not by the NRC or the power buyer.
This is the mechanism behind the headline. A restart deal with a technology customer creates the demand; a reactor license makes operation legally possible; but without the water certification, the federal license cannot rest on a finding that state water standards will be met. For the developers, utilities and hyperscalers (the largest cloud operators) counting on restarts to bridge the AI power gap, water approvals belong on the critical path alongside nuclear safety reviews.
The Consumptive-Use Number Is the One to Watch
The 73.2-million-gallon withdrawal figure is the larger number, but the 21-million-gallon consumptive-use figure is arguably the more consequential. Consumptive use is water that does not return to the river, mostly because it evaporates from cooling towers. In a closed-cycle system, the plant recirculates water through towers instead of passing river water through once and discharging it, which sharply cuts withdrawals and the number of fish pulled into the intake (entrainment) or pinned against screens (impingement). The trade-off is that evaporation is built into the design.
That matters most in dry, hot periods, when river flows drop and every user of the basin competes for the same water. The release does not describe any low-flow conditions attached to the certification, which is why the full certification document, available from DEP’s Southcentral Regional Office, will be of interest to other water users downstream and to anyone modeling the plant’s summer availability.
Pennsylvania’s Grid Stress Raises the Stakes
The certification arrives in a week that illustrates why firm generation is valuable in Pennsylvania. PJM Interconnection, the grid operator for Pennsylvania and 12 other states plus Washington, D.C., issued maximum generation and load management alerts for September 17 amid hot weather and 35,000 megawatts of maintenance outages, and a Pennsylvania Public Utility Commission study warned that rapid data center growth could cause PJM to fail a reliability standard in 2027 absent further action. The same week, DEP opened comment on a water quality permit for an Amazon Data Services campus in Luzerne County and on stormwater permits for PPL Electric transmission projects intended to serve large loads.
Against that backdrop, a restart that returns an existing nuclear unit to service is one of the few supply additions that can arrive on a data-center timeline. But the pattern across these permits is consistent: whether the project is a reactor, a data center or a transmission line, state environmental permits for water and land disturbance are a gating step. Buyers of AI capacity who treat power as purely a contracting or interconnection question are likely to underestimate schedule risk.
Background
Three Mile Island, on the Susquehanna River south of Harrisburg, is best known for the 1979 partial meltdown at Unit 2, the most serious accident in U.S. commercial nuclear history. Unit 2 never reopened, but Unit 1 continued operating until 2019, when it closed for economic reasons. In 2024 Constellation Energy, the largest U.S. operator of nuclear plants, announced a 20-year power purchase agreement with Microsoft tied to restarting Unit 1, renamed the Crane Clean Energy Center.
The deal became a reference point for a broader trend: technology companies seeking around-the-clock, carbon-free electricity for AI data centers are turning to existing nuclear assets because new reactors take many years to build. Pennsylvania sits inside PJM, the largest U.S. grid region, where data center demand growth has become a central reliability and cost concern for regulators.
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.
Power companies across America are racing to keep up with the giant computer warehouses that run artificial intelligence, which use enormous amounts of electricity.
A new survey of 134 innovation chiefs at American power companies found that most now use artificial intelligence themselves to manage that demand. The catch: 84% say turning a small trial into something used across the whole company takes more than a year, and that delay is getting longer.
Why it matters to you: 83% of those leaders say the cost of serving these warehouses is showing up in household electricity bills.
National Grid Partners, the venture capital and innovation arm of UK and US energy company National Grid, released its third annual Utility Innovation Survey on September 18, 2026, at the NextGrid Alliance Summit in Boston. The survey of 134 innovation leaders at U.S. utilities, collected between May 20 and July 7, 2026, found that 78% are deploying or operationalizing at least one AI application to manage interconnection demand, while 74% say AI-driven data center load growth is affecting grid reliability.
The survey also found that 84% of organizations take more than a year to move projects from pilot to full rollout, up from 66% in 2024, and that grid reliability has overtaken net zero as a top-three priority. National Grid Partners also announced investments in two startups, Terragrit and LineVision, and noted that National Grid has joined the newly formed AI Energy Management Alliance as a founding member.
Executive Summary
The headline number is adoption: nearly four in five U.S. utility innovation leaders say they are putting AI to work on the flood of requests to connect new load, much of it from AI data centers. That is the industry using the technology driving its demand problem as part of the answer to it.
The more consequential numbers sit underneath. Innovation budgets rose at 72% of respondents, yet the share needing more than a year to scale a pilot has climbed for three consecutive surveys, from 66% to 78% to 84%. Most spending (59%) goes to incremental improvements, only 16% to transformational projects, and 87% say regulatory and rate-case frameworks written before the AI demand boom limit returns on innovation.
Taken together, the survey describes an industry that has accepted AI as a grid-planning tool but cannot yet deploy it at the pace data-center load is arriving. For data-center developers, utilities, regulators and ratepayers, the practical constraint is increasingly how fast utilities can change the way they plan, not only how much they build.
The Constraint Is Speed, Not Willingness
The survey rules out the easy explanation that utilities are reluctant to adopt AI. Seventy-eight percent say they are deploying or operationalizing at least one AI application to manage interconnection demand, meaning the queue of customers waiting for permission and capacity to plug into the grid. Seventy-two percent report bigger innovation budgets this year, and only 1% say they have no plans to work with early-stage technology companies.
What has not improved is the time it takes to turn an experiment into standard practice. Eighty-four percent of organizations now need more than a year to move a project from pilot to full rollout, up from 78% in 2025 and 66% in 2024. The trend has worsened for three straight surveys even as money has flowed in, which points to a structural bottleneck rather than a funding one. Respondents cite a shortage of workers skilled in AI and the industry’s traditionally cautious culture, and spending patterns reinforce the picture: 59% of innovation dollars go to incremental improvements against 16% for transformational initiatives.
That matters downstream because 74% of the same leaders say AI data center load is already affecting grid reliability. The pressure is present now; the tools meant to relieve it face a year-plus path to scale at most utilities. Data-center developers waiting in interconnection queues, utility planners fielding large-load requests, and the software vendors selling into utilities all operate on that clock. A tool that could, for example, help a utility study or approve a connection faster only helps once it is embedded in how the utility actually works.
Reliability Moves Ahead of Net Zero
The sharpest year-over-year shift in the survey concerns priorities. Asked to rank organizational priorities, 73% of utility leaders placed reliability in their top three, up from 43% in 2025. Net-zero goals fell from 54% to 16% over the same period.
This is a forced ranking of top-three priorities, so it measures relative emphasis rather than abandonment of climate commitments. Still, a swing of that size in one year is a clear signal about what is occupying planning attention. When a single data-center campus can represent a large new load on a regional system, keeping the lights on becomes the dominant planning question, and decarbonization targets compete for a smaller share of management focus.
Rate Cases Written for a Slower Era
Utilities in the U.S. generally recover investment through rate cases, the regulatory proceedings in which state commissions decide what a utility can charge customers and what return it may earn. Eighty-seven percent of respondents say those frameworks, developed before the current demand boom, are limiting returns on innovation investment. If a software tool that frees up grid capacity earns a utility less than building new poles, wires and substations, the incentive structure itself slows adoption, which is consistent with the lengthening pilot timelines.
The cost question cuts the other way for households. Eighty-three percent of respondents say the cost of building infrastructure to serve AI data centers is being passed on to residential customers through higher bills. That is the view of the utility leaders surveyed rather than a measured cost allocation, and the survey does not quantify it, but it is a notable admission coming from inside the industry, and it frames why regulators are likely to scrutinise who pays for data-center grid upgrades.
Flexible Data Centers as a Grid Resource
National Grid’s answer, alongside its investment activity, is flexibility. The company has become a founding member of the AI Energy Management Alliance, whose announced members include Google, NVIDIA, Anthropic, Emerald AI, RWE, Constellation and NRG. The group says it will push for policies encouraging flexible data centers that automatically reduce power use during peak demand, buffering nearby communities from price spikes.
The supporting evidence cited is a UK pilot last December involving Emerald AI, a National Grid Partners portfolio company, together with National Grid and NVIDIA, which found AI software could cut data center energy use by more than a third in under a minute during simulated grid strain while protecting critical workloads. That is a meaningful proof of concept, though it was a single pilot under simulated conditions. Whether flexibility becomes a dependable planning resource depends on data-center operators contractually committing to curtail, and on utilities trusting those commitments enough to connect load sooner, which brings the question back to how fast planning practices and rules can change.
Background
National Grid supplies electricity and natural gas to more than 80 million people in the UK, New York and Massachusetts, and is running major transmission programmes including the Great Grid Upgrade in the UK and the Upstate Upgrade in New York. Its venture arm, National Grid Partners, launched in 2018, is based in Silicon Valley with offices in Boston, London and New York, and describes itself as the utility industry’s only Silicon Valley-based corporate venture capital group.
National Grid also founded the NextGrid Alliance, which says it includes more than 1,000 senior decision-makers from over 170 utilities in 25 countries and has facilitated more than 500 introductions between utilities and startups. The survey arrives as U.S. utilities face surging requests to connect large AI data centers, a demand shift that is pressing on grid planning, reliability and how infrastructure costs are allocated among customers.
