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  • 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.

  • TVA Creates Data Center Rate Class, Approves 2026 IRP Amid AI Load Growth

    TVA Creates Data Center Rate Class, Approves 2026 IRP Amid AI Load Growth

    The Tennessee Valley Authority’s Board of Directors on August 20, 2026, approved a package of actions aimed at insulating ordinary ratepayers from the cost of surging data center demand: a modified wholesale rate structure that creates a new data center rate, adoption of the 2026 Integrated Resource Plan projecting a need for 11 to 32 gigawatts of additional generation by 2040, and an FY2027 budget that includes more than $13 billion in planned investment through FY2029.

    TVA — the nation’s largest public power supplier, serving roughly 10 million people across seven southeastern states — also confirmed construction of 4,120 megawatts of new TVA-owned capacity, with another 3,000 megawatts under evaluation.

    Executive Summary

    The headline action is structural, not financial: TVA is changing who pays for growth. By carving data centers into their own wholesale rate class, the utility says it will align charges with the actual cost of serving that load and prevent residential and manufacturing customers from subsidizing the infrastructure that hyperscale computing requires. The move follows TVA’s signing of the Ratepayer Protection Pledge, a national initiative built around the same cost-causation principle — the idea that large power users should cover the full cost of the energy and grid capacity their facilities demand.

    The rate change lands alongside two planning decisions that frame its scale. The 2026 Integrated Resource Plan — the long-range study utilities use to map future generation needs — projects the Valley region will need between 11 and 32 gigawatts of additional capacity by 2040, a range wide enough to signal genuine uncertainty about how much AI-driven demand will actually materialize. The FY2027 budget backs the near-term end of that build-out with more than $13 billion planned through FY2029, including over $1 billion annually to maintain the existing fleet and transmission system.

    For the data center industry, the signal is unambiguous: in TVA territory, as in a growing number of utility service areas, large computing loads will be priced as a distinct customer class with distinct cost responsibility — and other regulated utilities will be studying this template closely.

    Ring-Fencing Ratepayers Is Becoming Utility Orthodoxy

    The core mechanism here is a familiar one in utility economics: cost allocation by customer class. Utilities have long charged residential, commercial, and industrial customers differently because they impose different costs on the system. What is new is treating data centers — historically lumped in with large industrial users — as a class of their own. The rationale is that hyperscale facilities demand power at a scale, density, and speed that requires dedicated generation and transmission investment; without a separate rate, those costs spread across everyone’s bills. TVA’s framing, echoed in the Ratepayer Protection Pledge it recently signed, is that data centers should carry the full freight of the infrastructure they trigger.

    The release is explicit about the political economy driving this. Board Chair Mitch Graves invoked ‘hardworking American families and small businesses’ not being ‘left carrying the cost’ of AI’s electricity appetite. That language reflects a real pressure point: public concern that AI load growth is inflating household electricity bills has become one of the most potent consumer-energy narratives in the country. A public power agency with no shareholders — TVA answers to its board and, ultimately, to Congress — has strong incentives to get ahead of it. What the release does not disclose is the actual design of the new rate: no price levels, demand-charge structure, contract terms, or eligibility thresholds are given, which makes it impossible to judge yet how protective — or how burdensome to data center developers — the class will be in practice.

    An 11-to-32 Gigawatt Question Mark

    The 2026 Integrated Resource Plan’s projection that the region needs 11 to 32 gigawatts of additional capacity by 2040 deserves attention for its width as much as its size. The high end is nearly triple the low end — a spread that honestly reflects how speculative long-range AI demand forecasting remains. Data center interconnection queues across the country are known to contain duplicate and speculative requests, and utilities that build to the high case risk stranded assets if projects evaporate, while building to the low case risks reliability shortfalls if they don’t. TVA’s approach — approving a plan that ‘identifies a host of diverse generation mixes’ rather than committing to one — preserves optionality, which is prudent, though it also defers the hard resource choices.

    The concrete commitments are nearer-term: 4,120 megawatts of new TVA-owned capacity under construction, 3,000 megawatts under evaluation, and more than $13 billion planned through FY2029. Against even the low-end 11-gigawatt need, that construction pipeline covers roughly a third — meaning substantially more investment decisions lie ahead. The new data center rate class is arguably what makes that math workable: if large loads pay their full cost of service, incremental capacity can be financed against contracted demand rather than socialized risk.

    A Template Other Utilities Will Study — With Caveats

    TVA occupies an unusual position that makes it both a bellwether and an imperfect template. As a self-supporting federal corporate agency, its board sets rates directly rather than litigating them before a state utility commission, so it can move faster than investor-owned utilities, which must take rate-class changes through contested regulatory proceedings. Its starting point is also enviable: the release notes TVA’s residential rates are lower than those paid by 80% of customers of the top 100 U.S. utilities, and its industrial rates lower than 90%. A low-cost incumbent can impose stricter terms on data centers without immediately pricing itself out of site-selection shortlists.

    Still, the direction of travel matters for everyone in the digital infrastructure value chain. For data center developers and their tenants, specialized rate classes generally mean longer-term contracts, minimum-payment obligations, and less ability to externalize infrastructure risk — raising the cost floor but also, potentially, giving utilities the confidence to build capacity faster. For competing regions, TVA’s combination of cheap incumbent power, a massive build-out, and an explicit consumer-protection posture is a competitive statement: the Valley wants AI load, but on terms its board can defend publicly. Buyers evaluating the region should read the new rate’s fine print, once published, before assuming historical TVA pricing applies to them.

    Background

    Created by Congress in 1933, the Tennessee Valley Authority has grown into the largest public power supplier in the United States, serving roughly 10 million people through local power companies across seven southeastern states while funding itself entirely from electricity sales. Its service territory has become one of the country’s most active data center growth corridors, and TVA has been positioning for that demand: the utility recently reported $6.6 billion in operating revenues on nearly 82 billion kilowatt-hours of sales for the first six months of fiscal 2026, and was selected for a $400 million U.S. Department of Energy grant to accelerate next-generation nuclear power.

    The August 2026 board actions arrive amid a national debate over who should pay for AI-driven load growth. Utilities across the country face record interconnection requests from hyperscale computing projects, and regulators, consumer advocates, and industry groups have increasingly converged on special rate classes and cost-causation pricing as the mechanism to keep that growth from flowing into household bills.

    Source: TVA Board Protects Consumers, Strengthens Reliability Amid Rising Power Demand — Tennessee Valley Authority press release via PR Newswire, August 20, 2026, announcing a new data center rate class, 2026 IRP approval, and the FY2027 budget.

  • DOE Emergency Order for PJM Ahead of Heatwave Signals a Grid Under Strain

    DOE Emergency Order for PJM Ahead of Heatwave Signals a Grid Under Strain

    The US government has issued an emergency order covering PJM Interconnection — the largest electric grid operator in the United States — ahead of a heatwave expected to drive electricity demand toward the edge of available supply, Reuters reported on June 30, 2026. Emergency orders of this kind allow the Department of Energy to temporarily relax normal operating constraints so that generators can run at maximum output to keep the lights on.

    Executive Summary

    According to the Reuters report, federal authorities acted preemptively: the order was issued as the heatwave loomed, not after the grid had already buckled. That timing matters. Emergency authority — typically exercised under Section 202(c) of the Federal Power Act, which lets the Energy Secretary direct generators to operate notwithstanding permits or other limits — was historically reserved for rare, acute crises such as hurricanes or sudden plant failures.

    That such an intervention now precedes a forecastable summer weather event suggests the buffer between peak demand and available generation in PJM’s territory has grown uncomfortably thin. PJM coordinates power for roughly 65 million people across 13 states and the District of Columbia — including Northern Virginia, the densest data-center market on Earth — so an emergency footing on this grid is a material signal for the entire digital-infrastructure industry.

    When Emergency Powers Become Routine Tools

    An emergency order is, by design, an extraordinary instrument. It can authorize power plants to exceed environmental or operational limits, keep units scheduled for retirement running, and compel generation that market signals alone would not produce. Using it in anticipation of hot weather — one of the most predictable stresses a grid faces — indicates that ordinary market and reliability mechanisms are no longer producing enough headroom on their own. Similar orders were issued for PJM and other regions during heat events in prior summers, so the June 2026 action fits an emerging pattern rather than standing as a one-off.

    The pattern is the story. Each individual order is defensible as prudent risk management; a sequence of them amounts to the federal government repeatedly bridging a structural gap between demand growth and supply additions. That gap has causes on both sides of the ledger: large thermal plants retiring faster than replacement capacity comes online, interconnection queues that delay new generation for years, and demand rising after two decades of near-flat load.

    AI Load Growth Meets a Tightening Grid

    PJM sits at the center of the demand-growth debate because its footprint includes Northern Virginia’s ‘Data Center Alley,’ along with fast-growing campuses in Ohio, Pennsylvania, and Maryland. Grid planners across the country have sharply raised load forecasts, driven in large part by AI-oriented data centers, electrification, and new manufacturing. PJM’s own capacity auctions — the market that pays generators to be available during peaks — have cleared at record-high prices in recent cycles, a direct financial symptom of scarcity.

    A heatwave is where these abstractions become physical. Air-conditioning load peaks at exactly the moment thermal plants lose efficiency in the heat, and data-center cooling demand rises in parallel. When the margin for error narrows, operators lean on emergency tools. For the industry we cover, the lesson is blunt: electricity availability, not land or fiber, is now the binding constraint on digital-infrastructure growth in America’s largest power market.

    What It Means for Data-Center Operators and Their Customers

    For operators, recurring grid emergencies raise both operational and reputational stakes. Operationally, facilities in PJM territory should expect more frequent conservation appeals, demand-response calls, and scrutiny of backup-generation readiness during peak season. Reputationally, data centers are increasingly cast as the face of load growth; every emergency order sharpens public and regulatory questions about who pays for grid stress and whether large loads should be required to be curtailable or bring their own generation.

    The likely winners in this environment are firms that treat power as a first-class engineering problem: those with flexible-load capability, on-site or contracted generation, long-dated capacity positions, and sites in regions with genuine surplus. The exposed parties are speculative projects counting on grid interconnection timelines and power prices that no longer reflect reality. Utilities and generators in PJM, meanwhile, gain leverage — scarcity is lucrative for whoever owns dispatchable megawatts.

    Background

    PJM Interconnection, founded as a utility power pool in 1927, evolved into the largest competitive wholesale electricity market in the United States, coordinating generation and transmission across the Mid-Atlantic and parts of the Midwest. Its footprint includes Northern Virginia’s data-center corridor, which has made PJM the frontline grid for AI-era load growth. Section 202(c) of the Federal Power Act gives the Department of Energy authority to order emergency generation during grid crises — a power used sparingly for decades but invoked more frequently in recent years as plant retirements, slow interconnection of new resources, and surging demand forecasts have narrowed the system’s reserve margins.

    Source: US issues emergency order for PJM Interconnection as heatwave looms — Reuters report, June 30, 2026, on federal emergency action to shore up the largest US grid ahead of extreme heat.