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Tag: Power Infrastructure

  • For Anthropic’s 401 MW AI Lease, TeraWulf’s Real Asset Is a Smelter’s Grid Connection

    For Anthropic’s 401 MW AI Lease, TeraWulf’s Real Asset Is a Smelter’s Grid Connection

    TL;DR · 30-second read

    The Short Version

    TeraWulf, a company that used to mine bitcoin, has lined up the artificial intelligence developer Anthropic as the tenant for a giant computer campus on the site of an old aluminum plant in Kentucky.

    The lease runs 20 years and is estimated to be worth about $19 billion. Its computers will use about as much electricity as a small city. Averaged out, the yearly rent would be more than five times what TeraWulf now takes in from sales in a year.

    The takeaway: for artificial intelligence, the scarce ingredient is electricity, and an old factory already wired for enormous power loads was the prize.

    StocksToTrade reported on October 2, 2026 that TeraWulf Inc. (Nasdaq: WULF) has secured Kentucky Public Service Commission approval for a Retail Electric Service Agreement providing up to 482 megawatts (MW) of power to its Justified Data Campus, a repurposed former aluminum smelter, and that the campus is anchored by a 20-year lease with Anthropic covering roughly 401 MW of critical IT load. The lease carries options to extend by up to 10 more years and an estimated $19 billion of contracted revenue, backed by expected investment-grade credit. Initial investment in the project is estimated at $4.0–4.5 billion.

    WULF shares rose 4.15% on the day, closing near $15.49 after a pullback from the $17–18 range in early September. The same period brought a run of analyst initiations: Wells Fargo, UBS, Freedom Capital and Jones started the stock at Buy or Overweight with targets from $19 to $30, while Rothschild & Co Redburn started at Neutral with a $15 target.

    Executive Summary

    TeraWulf, a U.S. company that built its business mining bitcoin, is turning a former Kentucky aluminum smelter into an AI data center campus with Anthropic as its anchor tenant. The two numbers at the center of the deal — 482 MW of approved power and a 401 MW lease — sit close enough together that the lease reads as sized to fit inside the power the state regulator signed off on.

    That is the significance for the wider market. AI developers need enormous, reliable electricity, and power access is widely described as the main bottleneck in building data centers for them. A site that already carries heavy industrial power infrastructure, paired with a regulatory approval, gives a landlord something a tenant will commit to for 20 years before the buildings exist.

    For TeraWulf, the lease implies revenue on a scale far beyond anything its mining business has produced. It also means the story now turns on execution and financing: roughly $4 billion or more must be spent before that revenue arrives.

    The Lease Fits Inside the Power Approval

    Two numbers explain this deal. The Kentucky Public Service Commission, the state’s utility regulator, approved a Retail Electric Service Agreement — in effect a large-customer supply contract with the local utility — for up to 482 MW at the Justified Data Campus. Anthropic’s lease covers roughly 401 MW of critical IT load, meaning the power reserved for the servers themselves, before cooling, power conversion and building systems. The difference is about 81 MW, so the approved supply is roughly 1.2 times the IT load. That ratio is consistent with the overhead a modern, efficient facility needs for cooling and electrical losses, which suggests the tenant commitment was sized to the power envelope rather than the other way round.

    That ordering matters for anyone valuing a converted miner. The expensive part of the campus is still ahead: the $4.0–4.5 billion of initial investment is planned spending, not completed construction. What TeraWulf could offer a 20-year tenant today is a site with heavy power infrastructure already in place and a regulatory path to nearly half a gigawatt of supply. In that sense the grid connection — not the buildings, and not bitcoin mining hardware — is the asset Anthropic is committing to.

    The consequence reaches several groups. Utilities and state regulators become gatekeepers of AI leasing, because their approvals set how much capacity a landlord can sell. Owners of retired heavy-industry sites hold something newly valuable. And tenants sign multi-decade commitments whose value depends on construction that has not yet happened.

    Why an Old Smelter Beat a Greenfield Site

    Aluminum smelting is among the most electricity-hungry industrial processes, so smelter sites are typically built with high-voltage connections and substations sized for very large, continuous loads. Repurposing one is a “brownfield” project — building on previously developed industrial land — as opposed to a “greenfield” build on empty land that must wait for new transmission and utility upgrades. Wells Fargo, launching coverage with an Overweight rating and a $30 target, highlighted exactly this point: existing infrastructure cuts both time and capital spending compared with starting from scratch.

    Notably, the flagship is not a converted bitcoin mine. What TeraWulf’s mining history appears to contribute is experience in finding, contracting and energizing industrial-scale power, rather than the mining sites themselves. That distinction matters for investors who value miners on the megawatts they already run: this deal suggests the premium goes to power that can be delivered at data-center quality and scale, wherever it sits, and to the ability to get it approved.

    It also shows who is signing. Anthropic, an AI developer, is named as the direct tenant of a former miner. One deal does not make an industry trend, but Wells Fargo’s reference to an 839 MW contracted capacity pipeline across three tenants indicates TeraWulf is building a portfolio around this model rather than a one-off project.

    $19 Billion of Revenue, $4 Billion-Plus of Spending First

    Simple division puts the estimated $19 billion of contracted revenue at an average of about $950 million a year over the 20-year base term — a rough figure that ignores rent escalators and the construction ramp. That is more than five times TeraWulf’s trailing revenue of about $168.5 million. Against it sits an estimated $4.0–4.5 billion of initial investment, or roughly $10–11 million per megawatt of IT load.

    The spending comes first. TeraWulf reported free cash flow of about −$992 million in its latest quarter, raised more than $1.1 billion of equity and put over $1.0 billion into property and equipment. Debt is modest relative to equity, at about 0.16, but working capital is negative and the current ratio — short-term assets divided by short-term liabilities — is below 1. In plain terms, the company is spending well ahead of the cash the lease will eventually produce.

    This is where “expected investment-grade credit” carries weight. A long lease backed by investment-grade credit — a rating signaling low default risk — is the kind of contract lenders will finance against. If that support materializes as described, much of the build could be funded with debt rather than further share sales; if it does not, the burden shifts back toward equity and dilution of existing shareholders.

    Where the Bulls and the Skeptics Actually Disagree

    Analysts largely agree on the asset and differ on the backdrop. Wells Fargo ($30, Overweight), UBS ($24, Buy, arguing a fully leased development portfolio could be worth up to $30 a share), Freedom Capital ($19, Buy, with a “floor” near $14) and Jones ($30, Buy) frame TeraWulf as a favored AI infrastructure name, and FactSet data put the consensus at Buy with a mean target in the mid-$30s.

    Rothschild & Co Redburn’s Neutral rating and $15 target — close to where the stock closed — rests on a different question: not whether the Kentucky campus is valuable, but whether tightening credit markets and the balance sheets of hyperscalers, the largest cloud providers, will keep funding AI buildout at the current pace. That is a fair challenge to a business built on long-dated tenant commitments and borrowing against them. Equally, the bull case rests on a named tenant and a regulatory approval, which are concrete rather than speculative.

    Concentration is the risk both camps must weigh. One tenant anchors the flagship, and a 20-year lease is only as strong as that tenant’s ability to pay through cycles in AI spending. Delivering 401 MW of capacity on schedule is the near-term test that will settle which view was closer.

    Background

    TeraWulf Inc. (Nasdaq: WULF) built its business as a U.S. bitcoin miner, running large fleets of specialized computers that draw electricity around the clock. That model depends on securing large amounts of reliable, low-cost power — the same input that AI data centers need. As demand for AI computing has surged, TeraWulf and other public miners have begun converting capacity into data centers that host AI workloads, shifting from mining revenue toward long-term leases.

    Anthropic is an AI developer whose models require very large amounts of computing capacity. In data center leasing, “critical IT load” measures the power available to the servers, and state utility regulators such as the Kentucky Public Service Commission approve the supply agreements that make large new loads possible — which is why power approvals have become central milestones in AI infrastructure projects.

    Sources

    Source: WULF Stock Rallies As Massive Anthropic AI Deal Takes Shape — StocksToTrade on TeraWulf’s Kentucky power approval, Anthropic lease and analyst coverage.

  • A Reported $4B Federal Loan Moves Vistra’s AI-Era Nuclear Credit Risk to Washington

    A Reported $4B Federal Loan Moves Vistra’s AI-Era Nuclear Credit Risk to Washington

    TL;DR · 30-second read

    The Short Version

    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.

    Sources

    Source: Vistra shares bounce off lows on report of $4B nuclear loan (Investing.com), on the market reaction to reported federal loan backing; and Trump Administration to Back $4B Loans for Vistra’s Nuclear Facilities (GuruFocus).

    Primary sources: Vistra Corp. Form 8-K filed September 24, 2026, covering completion of $1.5 billion in 7.000% Series A and 7.250% Series B Junior Subordinated Notes due 2057.

  • Rexel Buys $1.1B-Revenue GCG, Betting Data Center Cable Is an Engineering Sale

    Rexel Buys $1.1B-Revenue GCG, Betting Data Center Cable Is an Engineering Sale

    TL;DR · 30-second read

    The Short Version

    • Rexel, a giant European seller of electrical supplies, is buying GCG, a Chicago company that supplies specialized wire and cable.
    • GCG expects more than $1.1 billion in sales this year. Its customers include data centers, the warehouse-sized buildings full of computers that run the internet and artificial intelligence, plus power networks and the military.
    • What Rexel is really buying is expertise: GCG’s engineers design and prepare cable to order for demanding building projects.
    • The price has not been made public.

    GCG, a Chicago-based specialty wire and cable distributor, announced on September 25, 2026, in a release distributed by PR Newswire, that Rexel is acquiring it from Audax Private Equity. The transaction is expected to close by year end, subject to regulatory approvals and customary conditions. Financial terms were not disclosed.

    GCG operates in North America and Europe through 16 locations with more than 950 employees and expects to exceed $1.1 billion in revenue in 2026. Rexel, a publicly held distributor of energy-management products, reported €19.4 billion in 2025 sales across 1,876 branches in 17 countries.

    Executive Summary

    Rexel is buying a distributor whose selling point is not inventory but engineering. GCG runs two segments, Custom Engineered Solutions and Connectivity & Power Solutions, and describes its model as engineer-led, value-added distribution of wire, cable and connectivity products. Its customers span data centers, power infrastructure, defense, building systems, water, telecom and industrial markets.

    Rexel’s stated reasons are specific: to extend its presence in high-growth, mission-critical markets, naming data centers and power infrastructure first, and to bring GCG’s engineering-led model and proprietary product portfolio into its larger platform. That framing matters more than GCG’s size. At just over $1.1 billion in revenue against Rexel’s €19.4 billion, GCG is a targeted capability purchase rather than a transformational one.

    The central open question is price. Without a purchase figure, financing details or GCG’s profitability, outsiders cannot judge how much Rexel is paying for data center exposure versus the underlying distribution business.

    What Rexel Is Actually Buying: Engineers at the Cable Reel

    Electrical distribution is often a volume business: stock common products, run many branches, deliver fast. GCG looks different. It serves more than $1.1 billion in expected revenue from just 16 locations, while Rexel runs 1,876 branches. A small number of specialist sites generating that revenue points to a model built around project work, not counter sales. GCG’s own segment name, Custom Engineered Solutions, and its description of ‘engineer-led, value-added’ service say the same thing.

    In cable, value-added distribution typically means work done before the product ships: cutting to specified lengths, assembling or kitting components, and helping customers specify the right cable for a job. On large, mission-critical projects such as data centers and power facilities, cabling is specified to project requirements and delivered on construction schedules, so a distributor that can engineer and prepare it takes on work that would otherwise fall to contractors or manufacturers.

    That is the capability Rexel names in its rationale: GCG’s ‘engineering-led, value-added distribution model and proprietary product portfolio.’ Rexel is not describing a need for more warehouse space or more product lines. It is describing a need for engineering capacity attached to cable, aimed first at data center and power customers. The bet is that in those markets, the sale is won on specification and preparation, and that this capability can be scaled across Rexel’s much larger network.

    A Small Deal by Size, a Pointed One by Market

    GCG’s expected 2026 revenue is well under a tenth of Rexel’s 2025 sales, so this acquisition will not reshape Rexel’s overall results. Its significance lies in direction. When a distributor of Rexel’s scale names data centers and power infrastructure as the markets it wants more of, it signals where it expects demand growth to come from.

    That expectation is consistent with the broader construction cycle in data centers, much of it driven by cloud computing and artificial intelligence, which requires large quantities of power and connectivity cabling. The release, however, does not say how much of GCG’s revenue comes from data centers. GCG lists seven end markets, including defense, water and building systems, so its data center exposure could be substantial or modest. Readers should treat the deal as a bet on data center growth, not evidence of how large GCG’s share of that market already is.

    The Private Equity Roll-Up Behind the Deal

    GCG is the product of a classic buy-and-build strategy. Audax acquired it as a carve-out of Genuine Parts Company’s Electrical Specialties Group, then expanded it through acquisitions including United Wire & Cable, CableMaster, RWL, Paige and Allied Wire & Cable. GCG says it grew to more than $1.1 billion in revenue since 2019 through both organic growth and those add-ons.

    For Rexel, that history cuts two ways. GCG has experience integrating acquired businesses and operates through local brands, which suggests customer relationships that sit with those brands. But the release does not separate organic growth from acquired revenue, so the underlying growth rate of the business Rexel is buying is not visible. A roll-up that grew mainly through purchases carries different risks from one that grew mainly by winning customers.

    Who Gains, and What Could Go Wrong

    Contractors and developers building data centers and power sites could gain a single channel that combines GCG’s engineered cable services with Rexel’s scale, if integration goes as described. Cable manufacturers will see further consolidation among the distributors that sell their products, which can shift purchasing leverage toward larger buyers.

    The main risks are concentration and integration. A business positioned for data center growth is exposed to any slowdown in that construction cycle, and engineering-led operations depend on retaining the specialists who do the work. GCG’s CEO emphasized its people and culture in announcing the sale; keeping that capability intact inside a 26,306-employee group will determine whether Rexel gets what it is paying for.

    Background

    Rexel is a publicly held distributor of electrical and energy-management products serving residential, non-residential and industrial customers for construction, renovation, production and maintenance. It operates 1,876 branches in 17 countries with 26,306 employees and reported €19.4 billion in 2025 sales.

    GCG began as Genuine Parts Company’s Electrical Specialties Group before Audax Private Equity acquired it in a carve-out. Under Audax, it expanded through organic growth and a series of acquisitions into a specialty wire, cable and connectivity distributor with 16 locations in North America and Europe, more than 950 employees and expected 2026 revenue above $1.1 billion.

    Sources

    Source: Rexel to Acquire GCG, a Leading Specialty Wire & Cable Distribution Platform — GCG’s announcement, via PR Newswire, of its sale by Audax Private Equity to Rexel.

  • Oracle’s 2.4 GW Bloom Reaffirmation Shows On-Site AI Power Trades on Delivery Risk

    Oracle’s 2.4 GW Bloom Reaffirmation Shows On-Site AI Power Trades on Delivery Risk

    TL;DR · 30-second read

    The Short Version

    Oracle, one of the giant companies that rents out computing power over the internet, has confirmed it still plans to buy a huge amount of power equipment from a company called Bloom Energy.

    The equipment is fuel cells: machines that turn natural gas into electricity on site without burning it. Together they would produce roughly as much power as two large nuclear reactors, to run artificial intelligence computer centers.

    A formal warning had said deliveries might be disrupted. When Oracle said the deal was still on, Bloom’s stock jumped about 8 percent. The deal didn’t get bigger. Investors were simply relieved it would happen.

    Bloom Energy shares climbed after Oracle reaffirmed its commitment to a 2.4 gigawatt (GW) fuel cell contract that had been put in question by a force majeure notice. A force majeure notice is a formal warning that events outside a party’s control may delay or prevent it from meeting its obligations. Yahoo Finance put Bloom’s gain at 8.7%, and 24/7 Wall St. reported a jump of about 8%.

    The contract covers on-site fuel cell generation intended to power AI data center capacity. Oracle’s reaffirmation left the headline size of the commitment unchanged at 2.4 GW.

    Executive Summary

    Oracle has publicly stood by a 2.4 GW fuel cell agreement with Bloom Energy after a force majeure notice raised the possibility that deliveries under the contract could be disrupted. Investors responded by bidding Bloom’s shares up roughly 8% to 8.7%.

    The notable part is what did not change. The contract was 2.4 GW before the notice and 2.4 GW after it. The share move therefore reflects restored confidence that the equipment will actually be delivered and used, not any new demand. That is a useful read on how the market values on-site power for AI. The megawatts on paper matter less than whether the delivery chain behind them holds.

    The episode also highlights concentration. A single customer’s statement about a single contract moved Bloom’s valuation this much, which suggests investors see this relationship as central to the company’s outlook. Bloom has not publicly quantified that dependence.

    A Reaffirmation, Not a New Order, Moved the Stock

    Bloom’s rally did not come from new business. The contracted capacity stayed at 2.4 GW, and no expanded scope was announced. What changed was the perceived probability that the contract would be performed as planned. A move of roughly 8% to 8.7% on that alone is effectively a market price on delivery risk. Before the reaffirmation, investors were discounting the chance that the notice would lead to delays, renegotiation or a smaller commitment. Oracle’s statement removed much of that discount.

    The mechanism runs through the force majeure clause. That clause lets a party suspend or delay its obligations when an event beyond its control intervenes. For on-site generation, performance depends on a long chain: fuel cell modules have to be manufactured, shipped, installed, connected to a gas supply, permitted and commissioned. A notice under that clause signals that at least one link is under strain. For the buyer, the stakes are high, because on-site fuel cells are the power plant for the data center. If the modules arrive late, the computing capacity switches on late.

    Three groups feel that directly. Bloom’s shareholders are exposed because revenue timing depends on delivery. Oracle’s capacity plans assume the power arrives on schedule. Contractors and lenders have built plans around the same timeline. For on-site AI power, the variable that moves value is delivery certainty, and this episode puts a number on how much.

    Why AI Builders Are Taking Power Into Their Own Hands

    Large AI data centers need enormous, steady amounts of electricity. Connecting that much new demand to the utility grid often means joining an interconnection queue, the line of projects waiting for grid operators to study and approve new connections, and that wait can stretch for years. On-site generation offers a way around it. Fuel cells can be installed next to the data center and added in modules as capacity grows.

    That speed comes with a trade-off. An operator that generates its own power exchanges dependence on a regulated utility for dependence on a vendor contract. That means exposure to the manufacturer’s factory output, to natural gas pipeline availability and to local air permits. Fuel cells avoid combustion, but they still emit carbon dioxide when running on natural gas, so permitting and emissions questions do not disappear.

    Scale sharpens the risk. A gigawatt is 1,000 megawatts, and 2.4 GW is roughly the output of two to three large nuclear reactors. At that size, on-site generation is no longer backup power. It is the primary supply for the campus, so any disruption to it matters.

    One Buyer, Outsized Weight

    The size of the market’s reaction suggests investors treat the Oracle contract as central to Bloom’s outlook. Bloom has not said what share of its backlog or expected revenue the contract represents. Concentration of this kind cuts both ways. An anchor customer from the hyperscale tier (the handful of companies running cloud platforms at global scale) validates the technology at a scale few buyers could offer, and it can justify factory expansion. The same concentration means one counterparty’s decisions on site priorities, schedules or procurement flow directly into Bloom’s revenue timing.

    In fairness to both companies, Oracle’s reaffirmation is a meaningful signal. A buyer looking to exit or reprice a deal could have used a force majeure notice as leverage, and Oracle chose to stand by the commitment publicly. Still, a public reaffirmation is not the same as disclosed terms. It is not known whether delivery schedules, pricing or remedies were adjusted along the way.

    What Buyers and Financiers Should Take From It

    For data center developers, the practical lesson is in the contract drafting. That includes how force majeure is defined, what remedies apply if delivery slips, whether deliveries are staged against milestones, and what backup supply exists if a vendor cannot perform. These terms carry weight well beyond boilerplate when on-site generation is the campus’s main power source.

    Lenders and equity investors underwriting AI campuses powered on site will likely want more visibility into the vendor’s manufacturing throughput and the fuel supply behind each project. This episode shows the market is already pricing that risk. Better disclosure is how the discount narrows.

    Background

    Bloom Energy builds solid oxide fuel cells, modular systems that convert natural gas or other fuels into electricity through an electrochemical reaction rather than combustion. The company has positioned its systems as a fast way for data center operators to secure large blocks of power without waiting for grid upgrades, a pitch that has gained traction as AI workloads push electricity demand well beyond what many local grids can supply quickly.

    Oracle runs Oracle Cloud Infrastructure and has become one of the most aggressive builders of AI computing capacity. Its proxy statement filed with the SEC on September 25 lists Clayton M. Magouyrk and Michael D. Sicilia, alongside Safra A. Catz, as principal executive officers for the fiscal year ended May 31, 2026. That is the leadership team now responsible for Oracle’s large power commitments, including the 2.4 GW Bloom contract.

    Sources

    Source: Bloom Energy (BE) Is Up 8.7% After Oracle Reaffirms 2.4 GW AI Fuel Cell Deal Commitment – Has The Bull Case Changed? (Yahoo Finance) and Bloom Energy Jumps 8% as Oracle Reaffirms 2.4 GW Fuel Cell Contract After Force Majeure Notice (24/7 Wall St.): coverage of Bloom Energy’s share gain after Oracle reaffirmed its 2.4 GW fuel cell contract.

    Primary sources: Oracle Corporation, Schedule 14A definitive proxy statement (DEF 14A), filed with the SEC on September 25, 2026.

  • SoftBank’s $21B AI Debt Puts a Repayment Calendar on Compute That Isn’t Built Yet

    SoftBank’s $21B AI Debt Puts a Repayment Calendar on Compute That Isn’t Built Yet

    TL;DR · 30-second read

    The Short Version

    SoftBank, the Japanese investment group that owns chip designer Arm and is a major backer of OpenAI, has raised about 21 billion dollars by borrowing rather than by selling shares in itself.

    The money is aimed at artificial intelligence: the chips, buildings and electricity needed to train and run AI systems.

    Why it matters: borrowed money has to be paid back on a set date, whether or not the plan works. The computers it buys may take years to earn anything. If the payoff runs late, the bill still arrives on time.

    ET Enterprise AI reported that SoftBank Group has added $21 billion through new debt deals, expanding the pool of capital behind its artificial intelligence ambitions. The figure represents fresh borrowing rather than new equity issued to shareholders.

    SoftBank is the Tokyo-listed investment group led by Masayoshi Son. It controls chip architecture company Arm, runs the Vision Fund investment vehicles, and has positioned itself as one of the largest single financiers of the current AI buildout, spanning silicon, model developers and large-scale data center ventures.

    Executive Summary

    A $21 billion debt raise is a financing event, not a construction announcement — but for an industry that spent the last three years funding itself with equity, venture capital and corporate free cash flow, the instrument choice is the story. Equity is patient capital: it has no maturity date and no coupon. Debt is dated capital, and it begins charging for time the moment it is drawn.

    SoftBank is an asset-rich holding company, and borrowing against holdings is a long-standing part of how it operates. What makes this raise notable is the destination. AI infrastructure — chips, sites, power, cooling, interconnection — has a long lag between the first dollar spent and the first dollar earned. Land, permits, grid connections and construction consume years before a single graphics processor is billable.

    The consequence runs downstream to everyone who builds, powers and supplies these facilities. When the marginal dollar behind AI capacity is borrowed rather than raised as equity, lenders’ underwriting standards start setting the shape of projects: what gets built, how much of it must be pre-leased to a creditworthy tenant, and how fast the schedule has to move.

    Debt Has a Calendar. Compute Has a Ramp.

    This is the mechanism the headline points at, and it is arithmetic rather than opinion. A $21 billion borrowing creates two obligations that are fixed in advance: periodic interest, and repayment of principal at maturity. Neither is contingent on how AI demand develops. Equity capital, by contrast, imposes no schedule at all — shareholders can wait a decade, and many holding-company investors have.

    Set that fixed calendar against the physical timeline of AI capacity. A large data center campus moves through site selection, land control, permitting, an interconnection queue with the local grid operator, substation and transformer procurement, construction, commissioning, and finally customer ramp. Each of those stages is measured in quarters or years, and several are not controllable by the developer — grid connection dates are set by utilities and regional operators, and long-lead electrical equipment is ordered well before concrete is poured. Interest accrues through all of it.

    Who carries that mismatch matters. For SoftBank, debt service comes from cash the group can generate today — dividends, asset monetizations, the market value of listed holdings — not from AI revenue that has yet to be earned. For counterparties, the effect is second-order but real: chip suppliers, engineering and construction firms, electrical equipment vendors and power developers now have an order book whose funding depends partly on credit markets staying open at tolerable rates. Equity funding can absorb a bad year; a refinancing window cannot.

    Why Equity Stopped Being the Whole Answer

    AI infrastructure has crossed a threshold of scale where equity alone is an awkward tool. Issuing shares to fund capital spending dilutes existing holders, and doing it repeatedly at the size AI campuses now require is expensive in ownership terms. Debt does not dilute. For a holding company sitting on valuable listed stakes, borrowing against those assets is the cheaper way to convert paper wealth into deployable cash without selling the position outright.

    That logic is sound as far as it goes, and it is worth stating plainly rather than treating leverage as a warning sign in itself. Infrastructure has always been a debt-financed asset class: toll roads, fiber networks, power plants and stabilized data centers are financed with borrowings precisely because their cash flows are long-dated and predictable. The open question for AI is whether the cash flows are yet predictable enough to deserve that treatment. Stabilized data centers leased to investment-grade tenants on fifteen-year terms are one risk profile. Speculative capacity built ahead of demand, or equity stakes in model developers still spending far more than they earn, are a different one.

    A single $21 billion raise does not settle that question, and it would be a stretch to read it as evidence of industry-wide strain. What it does show is that the funding mix behind AI is broadening beyond the equity and internal cash flow that characterized the first phase — and that the lenders now entering the trade will price, covenant and structure it on infrastructure terms.

    What Leverage Changes for the People Who Build the Sites

    Credit underwriting reshapes projects in predictable ways, and developers who have raised project debt know the pattern. Lenders want contracted revenue before, not after, construction: a signed lease with a named, creditworthy counterparty covering a defined block of capacity for a defined term. They want the power secured — an executed interconnection agreement or an energy supply contract, not a queue position. They want schedule certainty, because every month of delay is a month of interest on an asset earning nothing.

    The practical result is a sorting effect. Developers holding anchor leases with large technology tenants can finance at scale; those holding land and optimism find capital scarcer and dearer. Power availability becomes the gating item in credit committee rather than merely in engineering, which strengthens the hand of operators sitting on existing grid connections, retiring industrial sites or behind-the-meter generation. Equipment vendors with long lead times — transformers, switchgear, chillers, generators — become part of the financing conversation, because an unfillable equipment order is a schedule risk a lender will price.

    There is a risk case worth naming without overstating it. Leveraged AI capacity is more sensitive to interest rates and refinancing conditions than equity-funded capacity, and it concentrates the consequences of a demand slowdown into specific dated moments rather than spreading them across a valuation. That does not make the strategy wrong; ample profitable infrastructure has been built on debt. It does mean the relevant metric for observers shifts from how much capital SoftBank has assembled to how, and from what cash flows, the group intends to service it.

    Background

    SoftBank Group began as a Japanese software distributor and grew through telecommunications into one of the world’s most active technology investors under founder Masayoshi Son. It acquired British chip architecture company Arm, whose designs underpin most of the world’s smartphones and an increasing share of data center processors, and launched the Vision Fund vehicles to take large positions in private technology companies. The group’s balance sheet has long been characterized by concentrated stakes in listed and private assets, financed in part by borrowing against those holdings.

    Since the generative AI boom began, SoftBank has repositioned around the technology at multiple layers at once: chip design through Arm, model development through its backing of OpenAI, and physical capacity through large-scale data center ventures. That breadth is unusual — most participants occupy a single layer of the stack — and it means the group’s capital needs span semiconductor investment, venture-style equity stakes and heavy, slow-building physical infrastructure with very different payback periods.

    Sources

    Source: SoftBank adds $21 billion to AI firepower in new debt deals — ET Enterprise AI reports that SoftBank Group has raised $21 billion in new debt to fund its artificial intelligence ambitions.

  • Equinix’s 170 MW Cape Town Data Center Approval Faces Appeal

    Equinix’s 170 MW Cape Town Data Center Approval Faces Appeal

    TL;DR · 30-second read

    The Short Version

    Two campaign groups are trying to overturn Cape Town’s approval of two very large Equinix data centers near the city’s airport. Data centers are warehouse-sized buildings full of computers that run cloud storage, websites and artificial intelligence.

    The site could draw about 170 megawatts of electricity, comparable to the round-the-clock demand of a sizeable town. Critics say the approval came without clear figures on water and power use, in a city that nearly ran out of water in 2018.

    Equinix says it owns the land but has not yet filed detailed building plans.

    Housing Assembly and the UK-based organization Foxglove have appealed a municipal approval for two large Equinix data centers planned for the King Air Industria industrial area near Cape Town International Airport, Benin Web TV reported, citing the Financial Times. The project is estimated at roughly 170 megawatts (MW) of capacity on a site of about 122,500 square meters. Cape Town’s municipal planning tribunal approved it in July despite objections.

    The appellants say the approval rested on insufficient detail about water consumption, electricity demand, backup diesel generators, emissions and noise, and they want a new assessment before the project proceeds. Equinix confirmed it has acquired the land. It said no detailed development plan has been submitted yet and that it will continue talking with stakeholders if the project moves forward.

    Executive Summary

    The appeal puts one of the largest publicly discussed data center proposals in Africa’s most developed data center market under formal review. The objection does not claim the campus is inherently unacceptable. It argues that the city approved the project before anyone had quantified the resources it would consume. If the appeal succeeds, developers may have to submit a new application or provide more information before development continues.

    The case matters beyond one site. South Africa holds about 70% of Africa’s data center capacity, according to Financial Times estimates, and that growth is driven by cloud services and artificial intelligence workloads. The South African Human Rights Commission told the Associated Press it has received more than 250 submissions in a consultation on how data centers affect water, electricity, land and communities. For operators, the Cape Town appeal is an early test of how much resource disclosure regulators and communities will expect, and at what stage of a project they will expect it.

    An Approval Granted Before the Blueprint

    The dispute contains a timing tension. The planning tribunal approved two data centers in July, but Equinix says no detailed development plan has been submitted. Large developments often move through stages: land-use or zoning consent first, then detailed site and building plans. At those later stages, designs for cooling, power connections and backup generation become concrete. An early-stage approval can be legitimate while still leaving the resource questions unanswered.

    That is the gap the appellants are targeting. Their argument is essentially about sequencing: the water, electricity, diesel and noise numbers should be on the table before the city commits, not after. Equinix’s position points the other way. It says it is not yet at the detailed-plan stage and would continue engaging stakeholders if the project advances. The appeal will likely turn on which standard the municipal process requires at the approval stage.

    Water, Power and Diesel in a City That Remembers Day Zero

    Each resource concern maps to a real engineering choice. Data centers shed heat. Evaporative cooling uses less electricity but consumes water, while closed-loop and air-based systems use little water but more power. In Cape Town, where the 2018 “Day Zero” scare brought the city close to turning off municipal taps, the water side of that trade-off is politically sensitive. The electricity side is sensitive too, in a country whose national grid has long struggled with supply.

    Backup diesel generators are the less-discussed issue. Operators install them so servers keep running during grid outages. Where the grid is unreliable, generators may run more often than in markets where they are rarely used, which raises the emissions and noise questions the appellants cite. The site sits in an industrial area near an airport, which may shape how noise is assessed. Emissions and fuel storage still need their own analysis.

    Scrutiny Is Becoming a Market-Wide Cost

    The Human Rights Commission’s consultation shows that the debate in South Africa is broadening from individual permits to how the whole sector is regulated. For developers, that raises the likely cost of permitting: more studies, more disclosure, longer timelines and more exposure to appeal. Operators that can document low-water cooling, credible power sourcing and limited generator use may find approvals easier to defend. Those that cannot may face delays.

    Customers have a stake too. Cloud providers, enterprises and network operators that rely on South Africa as the continent’s main data center hub need capacity to arrive on schedule. A longer, more contested approval path in Cape Town could shift demand toward sites with clearer permits or delay the capacity growth the market expects.

    Fair Questions for Both Sides

    The appellants’ core request, quantified resource data before final commitment, is a reasonable planning principle. Their case would be stronger with specifics: which thresholds or disclosures would satisfy them, and whether full data can realistically exist before detailed designs do. Calling for a new assessment is different from showing that the project’s impacts would be unacceptable, and the reported objections so far focus on missing information rather than demonstrated harm.

    Equinix’s statement is also limited. Saying no detailed plan has been filed explains the absence of numbers but does not provide any. The 170 MW estimate has not been confirmed as the company’s own figure, and it has not described cooling technology, power sourcing or backup arrangements for the site. Early voluntary disclosure of design intentions would give the tribunal, the appellants and the public a factual basis for the debate.

    Background

    Equinix is a US-based, publicly traded digital infrastructure company that operates data centers and interconnection hubs worldwide, where networks, cloud providers and enterprises connect directly to each other. It entered African markets through its 2022 acquisition of West African operator MainOne and has since expanded its presence on the continent, including in South Africa.

    South Africa is Africa’s largest data center market. Cape Town and Johannesburg host most of the continent’s capacity, alongside major cloud regions. The country’s growth has come with resource concerns: Cape Town’s near-miss with running out of municipal water in 2018 and the national grid’s long-running supply problems have made water and electricity central to public debate over large new energy users.

    Sources

    Source: South Africa: Equinix’s 170 MW data centers challenged on appeal (Benin Web TV), on the appeal against Cape Town’s approval of two Equinix data centers near the airport.

  • Fermi Founder Seeks Independent Strategic Review Before October 30 Vote

    Fermi Founder Seeks Independent Strategic Review Before October 30 Vote

    TL;DR · 30-second read

    The Short Version

    Fermi is a young company trying to build a huge private power and computing campus to run artificial intelligence systems. Its founder, Toby Neugebauer, was removed as chief executive in April but still owns about a fifth of the company.

    He has now formally asked the board to hire an outside bank to test whether selling the company, or bringing in a big partner, would be worth more than going it alone. Shareholders meet October 30.

    The stock has dropped about a fifth since April, a sign investors doubt the giant project will get built on schedule.

    Toby Neugebauer, co-founder and largest shareholder of Fermi Inc. (Nasdaq: FRMI), stepped up pressure on the company’s board ahead of its October 30 annual meeting. Neugebauer’s group, the Fermi Founder Parties, holds approximately 22% of shares outstanding. In a statement issued September 11 via PR Newswire, the group said it sent the board a letter on September 9 and a presentation on September 10. On September 10 it also submitted a shareholder proposal under SEC Rule 14a-8. The proposal asks the board to retain an independent, nationally recognized investment bank to evaluate extraordinary transactions, including a full-value sale or a majority recapitalization with a strategic partner, and to report the results to shareholders.

    Neugebauer also asked the board to voluntarily put two non-binding questions to shareholders. One would restore pre-IPO voting standards in place of a 70% supermajority adopted since April. The other would raise the company’s 2.5% ownership limit to 9.8%. The statement said Fermi shares hit an intraday low of $5.26 on September 10, down roughly 20% since Neugebauer was removed as CEO on April 17.

    Executive Summary

    The founder of an AI power-campus developer is using the formal shareholder-proposal process to force a question onto the agenda: is Fermi worth more as a standalone company or in a transaction? Neugebauer is careful to say he has never asked the board to sell. His proposal explicitly leaves the existing standalone plan in place and asks only that alternatives be tested against it by an independent banker. He also stated that his group is not soliciting proxies.

    The fight matters beyond one company. Fermi went public in October 2025 pitching Project Matador as a private utility, with its own power, transmission and water on a single scalable campus for AI compute. Neugebauer’s critique rests on specific gaps. The one disclosed tenant lease, 222 megawatts with TensorWave, is under 5% of Fermi’s stated 4.8 gigawatts of near-term power opportunity. As of September 10, he says, supporting guarantees and project financing for that lease had not been confirmed. And the company still has no permanent outside CEO.

    For investors in gigawatt-scale energy and data center developments, the episode illustrates how quickly confidence can erode. When projects are mostly still potential, the market reacts to leadership turmoil, unconfirmed financing and governance rules that limit shareholder influence.

    A Modest Ask With Pointed Timing

    Rule 14a-8 is the SEC mechanism that lets eligible shareholders place a proposal in a company’s proxy materials, the documents shareholders receive before voting. Such proposals are typically advisory. Even if one passes, the board is not legally required to act, though ignoring a strong vote carries reputational cost. The proposal is also narrowly drawn: hire an independent bank, test a sale or majority recapitalization against the standalone plan, and report back. A recapitalization means bringing in new capital that would change who controls the company. It is hard to argue against gathering that information in principle, which is likely the point.

    The timing is deliberate. Neugebauer paused an earlier proxy contest, meaning a campaign to win shareholder votes for his own positions or nominees. He now says he expected the board to finalize counterparty agreements his team had negotiated, on the terms agreed, and that execution has stagnated instead. Rather than restart a full contest, he is using lower-cost tools: a proposal, a public letter, and a request that the board voluntarily add advisory questions. That keeps pressure on without the expense and escalation of a formal vote-solicitation campaign, while positioning him to argue later that the board refused reasonable requests.

    The board’s side of the story does not appear in Neugebauer’s statement. The company has previously said it completed all five objectives of its 90-day plan, as of August 13. Shareholders will need its response to weigh the founder’s characterization of those milestones.

    222 Megawatts Against a 4.8-Gigawatt Story

    The core economic tension is scale. A megawatt is a unit of power capacity. A gigawatt is 1,000 megawatts, roughly the output of a large power plant. Fermi’s stated near-term power opportunity is 4.8 gigawatts, and its disclosed TensorWave lease is 222 megawatts, about 4.6% of that figure. For a company valued on the promise of a multi-gigawatt campus, the gap between contracted demand and stated potential is what investors are pricing.

    Financing is the second pressure point. Neugebauer says that as of the morning of September 10, Fermi had not confirmed the guaranteed agreement it previously said would support the TensorWave lease. He also says it had not confirmed that project financing was secured. In data center development, a signed lease is only as valuable as the tenant’s credit, or the guarantee standing behind it. That credit support is often what unlocks construction loans. Until those pieces are confirmed, the lease reads as a milestone rather than de-risked revenue.

    The stock-price figures in the statement also deserve a careful reading. Shares are down roughly 20% since April 17, 35% since July 2, and 20% since August 13. Taken together, those numbers imply shares traded higher in early July than on the day Neugebauer was removed. They also imply shares were near April levels by mid-August. The decline has not been a straight line from the leadership change, which complicates attributing it to any single board decision.

    Governance Rules as a Valuation Lever

    Two of Neugebauer’s requests concern who can own and influence Fermi. The first targets voting standards adopted since April. Amending bylaws now requires a 70% supermajority, and electing directors requires a majority of all outstanding shares. He wants to restore the standards discussed before the IPO: a majority of shares outstanding for bylaw changes, and a plurality of votes cast for directors. A plurality vote means the candidates with the most votes win, even without an outright majority. Higher thresholds make shareholder-initiated change harder to achieve, particularly when turnout is incomplete. Boards commonly defend such provisions as protection against a single large holder gaining effective control without paying other shareholders a premium. With a 22% holder in a dispute with the board, that argument is plausible here. Fermi’s own stated rationale is not included in the release.

    The second request concerns Fermi’s real estate investment trust (REIT) ownership limit. REITs are tax-advantaged property companies, and they must avoid concentrated ownership under federal tax rules. For that reason their charters typically cap how much any one holder can own. Neugebauer notes that peers such as Digital Realty, Equinix and Prologis use 9.8%, while Fermi’s general limit is 2.5%. A lower cap restricts how large a position any single institution can build. That can thin out the pool of large, long-term buyers, and some investors view that as a drag on valuation. Raising it would widen the potential shareholder base. Whether that would change the stock’s trajectory more than delivering contracts and financing would is an open question.

    Leadership Uncertainty and Counterparty Confidence

    Neugebauer argues that counterparties considering committing billions to Project Matador want to know who is running the company. After a four-month search, Fermi named board member Lee McIntire as CEO. Neugebauer contends that the choice showed no outside candidate would take the role, and says the company itself described McIntire as a temporary solution. The first point is his inference rather than an established fact; searches end with internal appointments for many reasons. The underlying concern is still reasonable. Large tenants, lenders and equipment suppliers weigh management continuity when signing long-dated commitments.

    Neugebauer’s own claims warrant scrutiny too. The contention that Fermi is a one-of-a-kind asset, and significantly undervalued, is an argument, not a demonstrated valuation. He says counterparties had agreed to terms while he led the company, but those terms have not been made public. His request that the board release all written communications with him since the IPO could clarify the record for both sides. His stake also gives him an obvious interest in a higher share price. That interest aligns with other shareholders on value, though not necessarily on control.

    Background

    Fermi Inc., doing business as Fermi America, went public on Nasdaq under the ticker FRMI on October 1, 2025. It was capitalized around Project Matador, which the company describes as a private utility campus. The campus would supply its own power, transmission and water for AI computing at scale, with the stated aim of avoiding added burden on public infrastructure and local ratepayers. The company is organized with a real estate investment trust ownership structure. It reports a near-term power opportunity of 4.8 gigawatts and a disclosed 222-megawatt lease with TensorWave.

    Co-founder Toby Neugebauer was removed as CEO on April 17, 2026. Since then, according to Neugebauer, the board adopted a 70% supermajority to amend bylaws and a majority-of-outstanding-shares standard to elect directors. On July 2 it removed the option of a dual-path strategic process, and on August 13 it announced completion of its 90-day plan. Neugebauer launched and later paused a proxy contest. He has also publicly criticized a $375 million convertible note offering, which he tied to former CFO Miles Everson’s resignation from the board. Board member Lee McIntire has since been named CEO.

    Sources

    Source: Fermi Founder Parties File Formal Proposal for Independent Strategic Review of Extraordinary Transactions, Press Board on Restoring Texas-Style Governance Ahead of October 30 Annual Meeting, a statement from Toby Neugebauer and affiliated entities on their shareholder proposal and governance requests to Fermi’s board.

    Primary sources: Fermi Founder Parties File Formal Proposal for Independent Strategic Review of Extraordinary Transactions, Press Board on Restoring Texas-Style Governance Ahead of October 30 Annual Meeting (PR Newswire, September 11, 2026).

  • Applied Digital’s Harwood, ND AI Data Center (Polaris Forge 2): Site, Power, Cost

    Applied Digital’s Harwood, ND AI Data Center (Polaris Forge 2): Site, Power, Cost

    TL;DR · 30-second read

    The Short Version

    Two buildings north of Fargo, North Dakota are nearly finished, and together they are bigger than the largest building in the state, an Amazon warehouse two miles away. About 1,800 workers are on site.

    The buildings will hold computers that run artificial intelligence, and they will draw about as much electricity as a small city. The local council approved the project in September 2025, and part of it is supposed to be running by the end of this year.

    The company building it, Applied Digital, has not said which businesses will rent the space.

    InForum reported that Applied Digital’s Polaris Forge 2 campus in Harwood, North Dakota is nearing completion, with roughly 1,800 workers finishing two buildings of 907,000 square feet each. The Harwood City Council approved the $3 billion project on September 10, 2025. Part of the campus is on pace to become operational by the end of 2026, with the remainder opening in early 2027, according to Nick Phillips, Applied Digital’s executive vice president of public affairs and real estate acquisition.

    The site is a 280-megawatt facility drawing power from Cass County Electric, and Applied Digital is paying $112 million for the substation and transmission upgrades that serve it. The company has not disclosed which companies will occupy the buildings. It expects 200 to 250 permanent employees once the campus opens, on 400 acres of which about 300 have been graded.

    Executive Summary

    Harwood is Applied Digital’s third North Dakota project, after Jamestown and the Polaris Forge 1 campus at Ellendale, with a fourth under construction near Center. Ellendale, announced in late 2024, is partially operational. The pattern across all four is the same wager: build large blocks of power-dense capacity in a cold, cheap-power state and race to energize them while demand for artificial intelligence compute outruns supply.

    What makes Harwood worth studying is the calendar. From a municipal approval on September 10, 2025 to first operational capacity at the end of 2026 is roughly fifteen months for a 280-megawatt campus. In a market where developers routinely quote three to five years between site control and delivered power, that interval is the entire product. “Time to power” is the industry’s shorthand for how long a tenant waits between signing and switching on machines, and it has become the variable that decides which sites win contracts.

    The unresolved half of the story is commercial rather than physical. Steel, generators, cooling loops and a substation are visible and verifiable. Leases are not. Applied Digital has not named a tenant for Harwood, has not disclosed how much of the 280 megawatts is contracted, and has not detailed how the $3 billion build is financed. Those omissions do not undermine the construction progress, but they determine whether the speed converts into revenue.

    Fifteen Months From Vote to Volts

    The construction detail in the account is mostly a lesson in sequencing. Eight generator rooms in each building hold twelve units apiece, which is 96 generators per building and 192 across the campus, a level of on-site backup that signals a design intended for tenants who will not tolerate interruption. Roughly 86,000 electrical connections and several miles of copper cable have to be terminated and tested before any of it carries load. Workers wear helmets with augmented reality systems that check whether components are installed in the right place and whether crews are tracking to schedule, which is less a gadget than an admission that verification, not fabrication, is the thing most likely to slip.

    Phillips describes the split inside each building as about 25% data halls and 75% supporting systems. That ratio is the clearest single indicator of how the economics have shifted. In a conventional enterprise facility, the computer room dominates the floor plan. In a building designed for dense artificial intelligence racks, the electrical rooms, switchgear, uninterruptible power supply gear and cooling plant swallow three-quarters of the envelope. Applied Digital is not really building a warehouse for servers. It is building a power conversion and heat rejection plant that happens to have servers in the middle of it.

    The arithmetic underlines the point. If 280 megawatts is measured at the computers, spread across roughly 453,000 square feet of data hall, that is on the order of 600 watts per square foot, an order of magnitude above the densities most existing commercial data centers were designed for. Applied Digital has not specified whether the 280-megawatt figure is the load delivered to equipment or the total drawn from the utility, and the distinction changes that number materially. Either way, the campus is firmly in the density range that only recently became buildable at scale.

    The $112 Million Sentence

    The most consequential figure in the account is not the $3 billion headline but the $112 million Applied Digital says it will pay for the substation and transmission upgrades. That is roughly $400,000 per megawatt of connection, and it is the developer, not the utility’s other customers, footing the bill. Grid connection cost allocation is the live political question in nearly every jurisdiction now absorbing large computing loads, because the alternative structure, in which network upgrades are socialized across the rate base, is what makes residents worry about their bills. Harwood drew protesters on exactly that concern.

    Applied Digital’s counter-claim is that its facilities do not raise electricity bills, and Phillips cited more than $46 million in savings for customers across North Dakota and South Dakota since the Ellendale project began. The underlying mechanism is plausible in principle: a very large, very steady customer spreads a utility’s fixed costs across more kilowatt-hours, which can lower the per-unit cost everyone pays. But the claim as stated is not yet verifiable by a reader. It does not identify which utility’s customers, over which period, measured against which counterfactual, or whether the figure is an avoided increase rather than a reduction. Those are answerable questions, and regulated utilities generally have to answer them in rate proceedings.

    It is worth being precise about what each side is arguing, because they are not arguing about the same thing. The savings claim is retrospective and concerns Ellendale. The objection at Harwood is prospective and concerns what happens when a second large load lands on a different distribution system. A past result under one set of contracts does not settle the future question, and neither does a protest settle whether the mechanism works. The $112 million commitment is the strongest evidence Applied Digital has offered that it intends to carry its own interconnection costs, which is the part of the dispute that can actually be documented.

    Air, Not Water, and Why North Dakota Rewards That Choice

    Cooling is where siting logic becomes visible. Branden Cummins, the company’s civil structure architecture superintendent, described a closed loop that circulates fluid through six data halls in each building, carries it to the roof, and uses large fans to shed the heat before recirculating it. Because the loop is sealed, Applied Digital says water consumption will be comparable to a household. That is a meaningful claim in an industry now facing real scrutiny over evaporative cooling, which chills equipment by boiling away water and can consume millions of gallons a year at this scale.

    The trade is not free. Rejecting heat to air rather than to evaporating water costs electricity for fans, and the penalty grows with ambient temperature. In a Texas or Arizona summer, that penalty is severe enough that many operators accept the water consumption instead. In eastern North Dakota, where cold hours dominate the year, the fan energy penalty is small and the water savings are close to pure gain. The closed loop is not primarily an environmental gesture; it is the design that the climate makes cheapest, and the environmental benefit follows from the geography.

    Noise and setback receive the same treatment. Silencing equipment and sound barriers on the generator plant, with the nearest home about half a mile away and the town of Harwood more than a mile off, reflect a siting choice made before mitigation was needed. Developers increasingly buy distance rather than engineer around its absence, because generator testing and rooftop fan arrays are the two complaints most likely to follow a facility through its operating life.

    A Builder Without a Named Tenant

    Applied Digital is a merchant developer, meaning it builds capacity and then leases it, as opposed to a hyperscaler building for its own use. That model turns on a single question: how much of the capacity is committed before it is energized. The company has not disclosed which companies will occupy Harwood. Until it does, an observer cannot distinguish between a campus built against signed leases and one built on conviction about demand.

    The local economics are more legible. Roughly 1,800 construction workers will give way to 200 to 250 permanent employees, a ratio close to eight to one that is typical of the sector and worth stating plainly: data centers are enormous construction projects and modest employers. The durable local benefit is tax base rather than payroll. Polaris Forge 1 at Ellendale paid about $4.3 million in property tax for 2026, Harwood is receiving no tax incentives or abatements according to the company, and Phillips estimated Applied Digital would become the largest single taxpayer in the state by 2029, while acknowledging that Harwood’s own assessment is not yet estimated because the building is not finished.

    The absence of abatements is the notable item. Large data centers are frequently recruited with property tax exemptions that hollow out the fiscal case communities were sold, and a project that forgoes them changes the arithmetic for the county. It also suggests the developer’s binding constraint was schedule rather than subsidy. When capacity delivered in 2026 is worth materially more than the same capacity delivered in 2029, a year of negotiation over abatements costs more than the abatements are worth.

    Background

    Applied Digital is a Texas-based developer that builds and leases data center capacity rather than operating computing services itself, a model the industry calls merchant development. Its North Dakota expansion began with a facility in Jamestown, followed by the Polaris Forge 1 campus at Ellendale announced in late 2024 and now partially operational, the Harwood project approved in September 2025, and a fourth site under construction near Center, about 40 miles northwest of Bismarck.

    The expansion tracks a broader shift in where computing gets built. Training and running large artificial intelligence models requires racks that consume several times the power of conventional servers, which has turned electrical capacity, rather than fiber or floor space, into the binding constraint on the industry. Developers have responded by moving to regions with available generation, cold climates that reduce cooling costs, and utilities able to energize large loads quickly. That has brought industrial-scale construction to rural communities with no prior exposure to it, along with recurring local debates over electricity rates, noise, water and tax base that Harwood has seen in full.

    Sources

    Source: An inside look at the Harwood data center as it nears completion — InForum’s report from Applied Digital’s Polaris Forge 2 construction site in Harwood, North Dakota, with detail on schedule, power, cooling, staffing and taxes from company executives.

  • Hydro One Files $1.3B North Shore Link With Ontario Regulator

    Hydro One Files $1.3B North Shore Link With Ontario Regulator

    TL;DR · 30-second read

    The Short Version

    Ontario’s largest electricity company wants to string a new high-voltage power line across the province’s north, from a station near Wharncliffe to the city of Sault Ste. Marie. It would cost $1.3 billion and switch on in 2029. The provincial regulator has to approve it first.

    Nine First Nations have been offered the chance to own half of the line itself, not merely to be consulted about it.

    Why an ordinary person should care: factories, mines and computing sites cannot open where there is no spare electricity. This line is being planned before those customers show up.

    Hydro One Networks Inc. and Hydro One Sault Ste. Marie LP filed a joint leave-to-construct application with the Ontario Energy Board on September 11, seeking approval to build the North Shore Link, according to the company’s announcement. The project is a new 230-kilovolt transmission line running from Mississagi Transformer Station near Wharncliffe to the Third Line Transformer Station in Sault Ste. Marie, which Hydro One Sault Ste. Marie LP owns.

    Hydro One put the investment at $1.3 billion and said the line is expected to be in service in 2029. The work also includes upgrades at Mississagi and an expansion of nearby Algoma Transformer Station, with the Sault Ste. Marie partnership handling upgrades at Third Line. Nine potential First Nation partners have been offered the opportunity to take a 50 per cent equity stake in the transmission line component through Hydro One’s First Nation Equity Partnership Model.

    Executive Summary

    A leave-to-construct application under Section 92 of the Ontario Energy Board Act is the gate every transmission project in the province has to pass through. It obliges the applicant to lay out route, design, timing and cost, and it puts the need for the line in front of a regulator, intervenors and ratepayer advocates. Hydro One has now placed a $1.3 billion northern reinforcement into that process.

    The stated rationale is broad rather than specific. Ryan Docherty, Hydro One’s executive vice president for capital portfolio delivery, framed the project around rising provincial demand, aging infrastructure and more frequent severe weather, and described the line as strengthening the link between Ontario’s northeast and northwest. No customer, industrial project or contracted load appears in the announcement.

    That is the interesting part. Transmission takes the better part of a decade from concept to energization, while a large industrial or computing load can commit to a site in months. A regulator that waits for signed commitments before approving wires guarantees the wires arrive late. A regulator that approves ahead of them puts capital at risk of sitting underused. The North Shore Link asks the Ontario Energy Board to make that call on a $1.3 billion scale.

    Building Wires Before the Load Signs

    The economics of transmission run backwards from the economics of the customers it serves. A 230-kilovolt line, meaning a circuit that moves power at 230,000 volts so it can carry bulk energy over long distances with modest losses, is a multi-year construction project with a multi-decade asset life. Hydro One’s own timeline puts the North Shore Link in service in 2029, roughly three years after filing, and that clock only starts once the regulator says yes. Large electricity consumers do not work on that horizon. They pick a site, want power within a couple of years, and go elsewhere when the answer is a queue position.

    This is why the need case in a filing like this one tends to rest on system arguments rather than customer arguments. Hydro One’s announcement cites demand growth, asset age and storm resilience, and says the line strengthens the northeast-to-northwest connection. Those are real engineering rationales and they stand on their own. They are also, notably, rationales that do not require anyone to have signed a connection agreement.

    The honest framing is that the filing is a bet on capacity being wanted rather than proof that it is already claimed. That bet can be entirely sound. Ontario has publicly signalled load growth across electrification, industry and computing, and pre-building headroom is cheaper than retrofitting a constrained corridor later. But it is a bet, and the Section 92 proceeding is precisely where the strength of the underlying forecast gets tested by parties whose job is to protect ratepayers.

    Fifty Per Cent, Nine Nations

    The equity structure is the most concrete commitment in the announcement. Nine potential First Nation partners have been offered the chance to invest in a 50 per cent stake in the transmission line component of the project, through a model Hydro One has applied to other northern lines. This is ownership, with the returns that regulated transmission assets generate, rather than a consultation process or a community benefits fund.

    For a project developer, the practical value is schedule. Linear infrastructure across northern Ontario crosses traditional territories, and objections surfacing late in permitting are among the most reliable ways to lose a year. Aligning economic interest at the planning stage does not eliminate that risk, but it changes the negotiating posture from opposition to partnership on projects where the model takes hold.

    Two things are worth noting evenly. The word Hydro One uses is potential, and the offer covers the transmission line component rather than the station work. Whether all nine participate, on what financing terms, and how the equity is funded are not addressed in the announcement. Those are ordinary details for a structure at this stage, and they are also the details that determine whether the 50 per cent figure translates into real returns for the communities involved.

    What This Means for Anyone Shopping for Power in Algoma

    For site selectors, whether in steel, mining, manufacturing or compute, the useful signal is not the dollar figure. It is the direction of capacity in the Sault Ste. Marie area and the date. A reinforced 230-kilovolt path into Third Line Transformer Station, plus expanded capability at Algoma Transformer Station, changes what a region can physically absorb. Until the line energizes, the constraint is whatever exists today.

    That produces an awkward window. Anyone evaluating a northern Ontario site now is evaluating against a grid that gets materially better in 2029 if the regulator approves and construction holds, and does not if either slips. Buyers negotiating connection today should be asking how their service depends on this project and what happens to their in-service date if the proceeding runs long or the build encounters the transformer and equipment lead times that have stretched across the industry.

    For investors, the read is simpler. Hydro One reported $39.7 billion in assets and $9 billion of revenue for 2025, and invested $3.4 billion in its networks that year. The North Shore Link sits alongside filings the company made earlier in 2026 for projects in central, eastern and Ottawa-area Ontario. This is a regulated utility adding to a rate base through a steady cadence of approvals, and the pace of that cadence matters more to the equity story than any single line does.

    Background

    Hydro One Limited, listed on the Toronto Stock Exchange under the ticker H, is Ontario’s largest electricity transmission and distribution provider, serving 1.5 million customers through its subsidiaries. Its transmission business owns the high-voltage backbone that moves power across a province stretching more than a thousand kilometres from the Manitoba border to the St. Lawrence, including the long, sparsely populated northern corridors that connect the northwest to the load centres of the south. Hydro One Sault Ste. Marie LP is the Hydro One entity that owns Third Line Transformer Station, the northern end point of the proposed line.

    Every transmission expansion in Ontario runs through the Ontario Energy Board under Section 92 of the Ontario Energy Board Act, 1998. The proceeding is adversarial by design: the applicant files route, design, timing and cost, and intervenors including consumer groups and industrial customers can challenge whether the investment is needed and whether the cost is prudent. Sault Ste. Marie sits in the Algoma district, a northern industrial region where heavy industry, mining and, increasingly, electrification of everything from transport to industrial heat all compete for the same finite grid capacity.

    Sources

    Source: Hydro One seeks approval from the Ontario Energy Board to build the North Shore Link — Hydro One’s September 11, 2026 announcement of a joint leave-to-construct application for a $1.3 billion, 230-kilovolt line into Sault Ste. Marie, targeted for service in 2029.

  • Court Rejects Coal Plant Order, Narrowing DOE Emergency Power

    Court Rejects Coal Plant Order, Narrowing DOE Emergency Power

    TL;DR · 30-second read

    The Short Version

    A 64-year-old coal plant in western Michigan was supposed to shut down in May 2025. The federal government ordered it to keep burning coal anyway, saying the power was needed to stop blackouts.

    A federal appeals court has now ruled that order was unlawful, because there was no real emergency. Keeping the plant open has cost about $259 million so far, and Midwest households and businesses may end up paying much of it in their electricity bills.

    The government is still issuing similar orders at other plants, so the fight is not over.

    The U.S. Court of Appeals for the District of Columbia Circuit ruled Friday that the Energy Department exceeded its authority when it forced Michigan’s J.H. Campbell coal-fired power plant to operate past its scheduled May 2025 retirement. The Associated Press reported that a unanimous three-judge panel sided with environmental groups and the states of Michigan, Illinois and Minnesota, finding there was no genuine emergency under the Federal Power Act. Writing for the panel, Judge Cornelia Pillard described the statute’s emergency provision as “essentially a narrow, last-resort backstop” and called the reversal of the plant’s “long and carefully planned retirement” disruptive.

    The 64-year-old plant in West Olive, operated by Consumers Energy, has stayed online under successive orders signed by Energy Secretary Chris Wright, who argued the unit was needed for regional reliability. Keeping it running has cost roughly $259 million so far, according to new financial filings. Consumers Energy said it is reviewing the ruling and will keep the plant operating under a more recent Energy Department directive that extends through mid-November.

    Executive Summary

    The decision is the first appellate ruling to test how far the Energy Department can stretch emergency authority to keep generation online, and it lands squarely against the department. The court did not weigh in on whether the Campbell plant’s output was useful last winter. It held that usefulness is not the legal test: the emergency provision applies only when immediate, last-resort action is required and when the Energy Department in particular must act, rather than the states responsible for making sure enough generation exists to meet demand.

    That distinction matters well beyond one coal unit. Since President Trump’s January 2025 executive order declaring a national energy emergency, which cited demand growth from artificial intelligence and data centers, the administration has used the same authority to hold roughly half a dozen coal plants and one Pennsylvania oil-and-gas plant past their closure dates. The ruling gives challengers in Indiana, Colorado, Florida and Washington a precedent written by the court that most federal energy appeals run through.

    It also sharpens a question the industry has largely deferred. If aging fossil units cannot be conscripted by federal order, then the burden of serving new data center load falls back where the court says it belongs, on state regulators, regional grid operators and the developers themselves. Emergency orders were never a capacity plan. They are now a considerably less reliable one.

    A Backstop, Not a Planning Tool

    The Federal Power Act’s emergency provision, Section 202(c), lets the Energy Department order a power plant to run during a sudden crisis. It was written for hurricanes, fuel shortages and deep freezes, not for structural shortfalls that everyone can see coming years out. The D.C. Circuit read it that way, holding that the authority is “triggered only when there is a need for immediate, essentially last-resort action and the circumstances require action by DOE in particular, as opposed to action by the state or states responsible for resource adequacy.” Resource adequacy is the industry term for having enough generation on hand to meet peak demand, and in the United States it is primarily a state and regional grid operator responsibility.

    The second half of the holding is the part utilities will read twice. Reversing a long-planned retirement, the court said, is itself disruptive. That reflects operational reality. A plant scheduled to close sheds staff, winds down coal supply contracts, defers environmental capital spending and is replaced in the resource plan by something else. Restarting that machinery is not free, and the court treated the disruption as a cost of the order rather than a neutral act of caution.

    It is worth being precise about what the court did not decide. The panel reviewed statutory authority, not engineering. The Energy Department’s specific claims, that Campbell delivered more than 650 megawatts daily from January 21 to February 1 and that coal output in affected regions rose 25 percent at the peak of the winter storms, were not rejected as facts. Its broader claim that the orders “likely saved hundreds of lives” is a causal inference the department has not published supporting analysis for. And if the output genuinely was needed during those storms, that points to a resource adequacy gap which the ruling says states and grid operators, not emergency orders, are supposed to close.

    The $259 Million Question

    The hard number in this story is the cost: roughly $259 million to keep one 64-year-old unit running past its retirement date. Costs from reliability orders of this kind are typically recovered through regional rates, which is why the challengers, and Michigan’s attorney general, framed the case around Midwest ratepayers footing the bill for a plant their own utility had planned to close. Sierra Club attorney Sanjay Narayan called the ruling a victory for families “paying to keep this old, expensive and dirty power plant online.”

    Advocacy framing aside, the underlying economics are not really contested. A unit gets a retirement date because its running costs, maintenance burden and emissions compliance no longer pencil out against alternatives. An emergency order does not change that arithmetic; it transfers the loss to someone else. Neither Consumers Energy nor the Energy Department has published the plant’s operating economics under the orders, so the $259 million figure is the only quantified measure of what the intervention has cost, and the ruling leaves open who ultimately absorbs it.

    For large electricity buyers, this is the cost-allocation fight in miniature. Reliability insurance for a region has to be paid for by somebody. When it is bought through an emergency order rather than a capacity market or a bilateral contract, the payer is chosen administratively and litigated afterward. That is a poor foundation for a ten-year power budget.

    What AI Load Growth Actually Needs

    The January 2025 executive order invoked artificial intelligence and data center growth as justification for a national energy emergency. Set the scale side by side. Campbell’s contribution during the storm period was a bit over 650 megawatts, which the Energy Department described as enough for hundreds of thousands of homes. It is also roughly the appetite of a single large AI training campus of the kind being announced across the Midwest and Mid-Atlantic. Holding a handful of aging units online buys time measured in months and capacity measured against one or two hyperscale projects.

    The practical takeaway for developers is that announced retirement dates just became more credible as planning inputs. Siting a campus on the assumption that a nearby fossil unit will be kept alive by federal order is now a materially riskier bet. The binding constraints remain what they were: interconnection queues, the multi-year backlog of requests to connect new plants and large loads to the grid, plus transformer and turbine lead times. None of those are addressed by an emergency order.

    The court’s federalism framing pushes the pressure toward state commissions and regional grid operators, and through them toward large customers. Expect more of what is already emerging: on-site or behind-the-meter generation, long-term contracts that fund firm capacity directly, and demand flexibility arrangements in which a data center agrees to curtail during system peaks in exchange for faster service. Those are slower and more expensive than a federal directive, but they do not expire when a panel of judges rules.

    The Orders Keep Coming

    The administration’s response was immediate. Hours after the ruling, Secretary Wright issued a new emergency order keeping the TransAlta-operated Centralia plant in Washington online; it had been scheduled to close at the end of 2025. Similar orders cover plants in Indiana, Colorado and Florida, and a Pennsylvania oil-and-gas plant has been directed to keep its turbines running as a hedge against Mid-Atlantic shortages. Consumers Energy, for its part, will keep Campbell running through mid-November under a separate directive while it reviews the decision.

    Each order stands on its own record, so the ruling does not automatically void the others. It does hand challengers a template, and because the D.C. Circuit hears most federal energy appeals, its reasoning carries unusual weight. The Energy Department has not said whether it will seek rehearing or Supreme Court review, which is the near-term question for anyone modeling how long this authority remains usable.

    For plant owners, an emergency order is revenue with a legal tail. Payments made under an order later found unlawful invite disputes over recovery and potential disallowance, and the uncertainty itself imposes planning costs on utilities trying to decide whether to retire, retrofit or resell a marginal unit. The cleanest reading of Friday’s decision is not that coal must close on schedule. It is that the federal government cannot unilaterally decide it should not.

    Background

    The J.H. Campbell plant has operated on Michigan’s west side for 64 years and is run by Consumers Energy, the regulated utility subsidiary of CMS Energy. Like much of the aging coal fleet in the Midwest grid region, it was slated for closure as operating costs, maintenance demands and cleaner alternatives shifted the economics. Its retirement date of May 2025 had been in utility resource plans for years before the Energy Department intervened.

    Section 202(c) of the Federal Power Act, the provision at issue, has historically been used sparingly and briefly, typically during hurricanes, fuel disruptions or extreme cold snaps. That changed after President Trump’s January 2025 executive order declaring a national energy emergency, which cited electricity demand growth from artificial intelligence and data centers. Since then the department has used the authority to hold roughly half a dozen coal plants past their closure dates, plus an oil-and-gas plant in Pennsylvania, producing litigation in several states of which the Michigan case is the first to reach an appellate decision.

    Sources

    Source: Federal court rejects Trump order keeping Michigan coal plant open — Associated Press report on the D.C. Circuit ruling that the Energy Department exceeded its authority in ordering the J.H. Campbell coal plant to operate past its scheduled retirement.