TUESDAY, SEPTEMBER 1, 2026

FIRST READ

A West Virginia court win landed at the top of the state’s energy news Sunday night, and it is the kind of ruling that should have Trenton and Albany paying closer attention. State Attorney General J.B. McCuskey announced late Monday that a federal judge in Northern New York struck down that state’s Climate Change Superfund Act — the law that would have hit coal and natural gas producers, including West Virginia companies, with a share of $75 billion in retroactive fines for lawfully producing the energy that heats homes and runs factories across the country. Chief Judge Brenda Sannes found the law “simply beyond the limits of state law,” inconsistent with the federal Clean Air Act and therefore unenforceable. West Virginia was the first state to sue, and McCuskey’s office says Vermont’s copycat law is next on the docket. It is a rare morning when the biggest energy story out of Charleston is actually a legal victory instead of another retirement notice, and today qualifies.

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What comes to mind when you see this scene? How does it make you feel? No need to answer right now, we’ll get back to that a bit later. Right now, let’s get to the point.

Data centers are coming to West Virginia and much of Appalachia whether the public embraces them or not. That reality makes the case for winning public support, not manufacturing public resentment. TJ Meadows’ recent MetroNews commentary, “Data Centers Make Power Bills Go Down!”, does the latter with real enthusiasm, and it is worth examining why that matters beyond the annoyance of reading it.

Meadows opens by describing a nine-year-old at a protest, “screaming at the top of his lungs,” and asks whether the boy even understands what he’s angry about. “I doubt it,” he answers himself. From there he widens the lens to everyone who shares the boy’s concern, describing them as trapped in “a world of data-center myths.” The rhetorical function is plain enough. Discredit the emotional response, then position yourself as the sober adult who has actually done the reading. It is a technique borrowed from talk radio, and it works fine as entertainment. It works terribly as persuasion.

To be sure, I have used ridicule and condescension in fighting for something believed in — it works when targeted at the right people — but it doesn’t work when you’re trying to reach a broad public with legitimate concerns.

The people who need convincing on data centers are not the activists chanting outside a substation. They are the undecided homeowner watching a transmission line survey crew show up on the county road, the retiree on a fixed income who just opened an electric bill that jumped again, the small-business owner who has heard “load growth” and “cost causation” thrown around and isn’t sure who benefits and who pays. That audience does not respond to being told their fear is childish. They respond to being taken seriously. A commentary that opens by mocking a child tells every uncertain adult reader exactly how their own hesitation is going to be received. Most of them will simply stop reading, and the ones who finish will remember the contempt longer than they remember the Indiana Michigan Power rate case buried in paragraph twelve.

That’s the real cost of this kind of writing. It is not that it fails to make an argument. Buried under the condescension, Meadows actually has one, and parts of it hold up. The Indiana example is real. Cost causation is the correct regulatory principle, and utilities that make large loads pay their own freight while contributing to shared system costs can produce exactly the outcome he describes. That case deserves to be made loudly and often in West Virginia, where the PSC and the Legislature are working through exactly these questions right now. But an argument this important gets buried when it’s delivered inside a package built to provoke rather than persuade. Readers remember how a piece made them feel before they remember what it proved.

There is also the matter of who is making the argument. Meadows is a former federal policy director for American Electric Power, a fact MetroNews itself has disclosed in an editor’s note on at least one of his prior columns. That background does not disqualify him from writing about utility economics. It should, however, make him more careful, not less, about how the argument gets delivered. When a former utility policy executive tells the public that concerns about data centers and rate impacts are mostly myth, and does it while mocking the people who hold those concerns, he hands skeptics the easiest possible reason to dismiss the whole piece as having little validity. Fair or not, that perception does real damage to an argument that otherwise has legitimate merit, and it does that damage regardless of what Meadows actually intended.

West Virginia and the broader coal-and-gas-producing regions of Appalachia have a genuine stake in getting data-center development right. Done well, with utilities and regulators enforcing real cost allocation and demanding that large loads bring firm generation or pay full freight for the capacity they draw down, data centers can be an economic asset. They can support baseload generation, including coal and gas, in a market that has spent two decades starving it of demand. Done badly, with costs socialized onto residential ratepayers and speculative load growth outrunning actual infrastructure, they become one more reason for people in these communities to distrust the energy industry and the people who write about it. Which outcome we get depends heavily on public buy-in, on legislators and regulators feeling public pressure to get the rules right rather than public apathy that lets utilities write those rules themselves.

Commentary like this one makes that buy-in harder to get, not easier. Every reader who closes the tab after the opening paragraphs is a reader who never encountered the Indiana Michigan Power case, never heard the phrase “cost causation,” and never had the chance to become a supporter of doing this right. Instead they walk away with one more data point confirming that the people pushing data centers think the public is either too dim or too gullible to be reasoned with. That is not a communications win. It is a forfeited opportunity, and it is the kind of mistake that compounds. The next commentary making the same argument, even one written with real care and real respect for the audience, now has to work through the residue this one left behind.

If the goal is genuinely to build public understanding and support for data-center development in a way that benefits ratepayers, protects the grid, and strengthens the case for reliable baseload power, that goal is served by arguments that respect the reader enough to earn their agreement rather than shame them into it. Meadows had the makings of a useful piece here. He buried it.

MONDAY, AUGUST 31, 2026 | Vol. 1 — Daily Edition

Summary / First Read

Bloomberg reported Thursday, and CNBC and Reuters confirmed the same day, that Anthropic has signed a six-year, $45 billion agreement for roughly 460 megawatts of computing capacity at Nscale’s Monarch Compute Campus in Mason County, taking over a site Microsoft had reserved under a letter of intent before walking away from it. Gov. Patrick Morrisey called it “an extraordinary vote of confidence” in West Virginia. The campus will generate its own power on site with Caterpillar gas generators rather than draw from the regional grid, which is precisely the model this state should be pushing for every large-load project that follows it. The same discipline showed up in Georgia this week, where regulators finished the paperwork on Georgia Power’s contract to serve OpenAI’s 3,200-megawatt data center near Savannah. Buried in that filing is a number worth remembering ahead of West Virginia’s own Sept. 8 transmission-line testimony deadline: $180, the annual bill cut Georgia Power says its existing residential customers will see once the new large-load revenue starts flowing in 2029, because regulators required the hyperscaler to cover the full cost of the infrastructure it demanded.

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A Production of Hedley & Company | Charleston, W.Va.
Vol. 1, No. 2 | Week Ending August 30, 2026)

FAST FACTS

Note on data cadence: unlike a weekly production series, no single federal agency publishes a weekly national data-center absorption or capacity figure. Figures above reflect the most recently published data as of this issue: FERC and RTO docket filings dated as shown; commercial real estate data (CBRE, JLL) reflect Q2 2026, the most recent full-quarter figures available; hyperscaler capex reflects Q2 2026 earnings-call guidance issued in late July and early August 2026. Reporting lag ranges from same-week (FERC dockets, state legislative actions) to one full quarter (commercial real estate). Where this issue cannot obtain a true weekly figure, it says so rather than estimating one.

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By Chris Hamilton
For West Virginia Coal Association

FirstEnergy wants West Virginia ratepayers to underwrite a 1,200-megawatt, $2.47 billion natural gas plant next door to the Fort Martin Power Station in Monongalia County — inside the same generation corridor as the Harrison Power Station. Before regulators sign off, someone needs to ask the obvious question: what happens to the two coal plants already standing on that ground?

Nobody is arguing against new generation. West Virginia needs it. The question in front of the Public Service Commission is narrower and harder: should regulators hand over billions of dollars in cost recovery and special ratepayer protections for a new gas plant before the utility has answered basic questions about it — and before anyone has reckoned with whether approving it as written undermines the very coal fleet state law now directs FirstEnergy to preserve?

House Bill 2014, signed into law in 2025, set capacity-factor and coal-supply standards for West Virginia’s coal-fired power plants. State law requires in-state coal plants to be upgraded and run indefinitely.

That standard is now the law of this state, and it should be the starting point for every regulatory decision that touches this corridor — including this one.

The gas plant proposal comes loaded with unresolved risk, and it’s worth walking through exactly what’s still missing.

Start with the wires. The Fort Martin-Harrison corridor already runs into transmission congestion today, before a single new gas turbine is built. Testifying before the Public Service Commission, WVCA Executive Vice President Jason Bostic warned that reduced operating levels at Fort Martin and Harrison could leave “no place for the electrons from those two coal plants to go” if the projected demand for the new gas facility never shows up.

That demand is speculative, full stop. The utilities lean heavily on a proposed 1,012-megawatt data center and a handful of prospective industrial customers to justify the project. But company witnesses admitted under questioning in PSC proceedings that not one of those customers has signed a binding agreement to buy power from the plant. This is a $2.47 billion bet being built on a stack of maybes — right next to two coal plants that are already generating power today, under contract, with no such uncertainty attached.

The financial case doesn’t hold up on its own, either. FirstEnergy officials testified they couldn’t say whether the gas project pencils out without a guaranteed ratepayer surcharge — the exact kind of backstop that tells you private capital wouldn’t touch this deal without someone else’s money underneath it. That someone else is the ratepayer, the same ratepayer already paying to keep Fort Martin and Harrison running.

The transmission math is just as shaky. Supporters expect much of the power tied to the separate MARL transmission project to originate from Fort Martin, Harrison and neighboring plants. But that line has run into serious public opposition across four counties, and its estimated construction costs have more than doubled — raising real questions about whether the infrastructure this whole plan depends on ever actually gets built.

And here’s the part that should stop everyone cold: FirstEnergy’s own long-range planning documents show the company expects to operate Fort Martin and Harrison only through 2035 — fifteen years short of the 2050 horizon West Virginia law requires. The same company asking ratepayers to backstop a new gas plant next door is, in its own internal planning, already writing off the two coal plants sitting on that same corridor.

Which raises a question FirstEnergy has yet to answer: where is the capital commitment to Fort Martin and Harrison themselves? If these plants are supposed to run through 2050, ratepayers deserve to see a real investment plan for the upgrades that will get them there — not a 2035 retirement date buried in the company’s own planning documents while it asks for billions toward a plant next door. FirstEnergy hasn’t committed a dollar or a timeline to modernizing the coal units it’s legally obligated to keep running. That commitment should come first. Approving new gas generation for a company that hasn’t shown its work on the plants it already owns gets the order of operations backward.

That is the plain math regulators are being asked to ignore. FirstEnergy wants approval and ratepayer protection for the gas plant now, on the strength of demand that doesn’t exist yet, while its own planning documents show Fort Martin and Harrison being phased out fifteen years ahead of what state law requires. Approve the gas plant on FirstEnergy’s terms, and the company gets exactly what it needs to justify retiring the coal fleet early — with ratepayers having already paid for its replacement.

Before consumers are asked to underwrite this project, FirstEnergy should have to show its work: how the gas plant complies with state law, how it protects the long-term viability of Fort Martin and Harrison specifically — including a firm capital commitment to keep them running through 2050 — and how it serves the public interest, not just the optimistic forecasts sitting in a slide deck that may never become reality.

West Virginia already decided that Fort Martin and Harrison run through 2050. FirstEnergy’s own gas plant application is the first real test of whether the company — and our regulators — intend to honor that.

And before anyone jumps to the conclusion that this is just another stone cast in the proverbial “coal versus gas” debate, the West Virginia Coal Association has not as much as raised a finger in opposition to the 5-6 other gas plants proposed to be developed in the state.

The distinction here is the protection for the First Energy proposed facility being paid for by consumers, many of whom are West Virginia miners, and the potential it may eventually cost them their jobs.

Chris Hamilton is the president of the West Virginia Coal Association

Saturday, August 29, 2026

FIRST READ

Pennsylvania, Ohio, West Virginia, Michigan and South Carolina all made news in the same 24-hour window: an AI data center in Westmoreland County, Pennsylvania went live running on gas turbines fed by its own Marcellus wells; DTE Energy told Michigan regulators it wants two new gas plants totaling 2,100 megawatts; and West Virginia led the Marcellus/Utica region in new drilling permits last week.

Layer that under the national stories — a China-backed hack targeting the Department of Energy, Ohio ratepayers pressing FERC on data-center transmission costs, record uranium production data, Washington state’s new data-center rate rules, and California’s lawsuit over a canceled wind lease — and the picture holds together: the gas basin underneath West Virginia is quietly becoming the AI industry’s backup generator, one gas turbine and one regulatory filing at a time.

And our publisher takes on the issue of radicals and activist judges trying to bypass the President and Congress in setting national energy policy from the bench at the very time our nation’s grid is literally under attack by China.

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FRIDAY, AUGUST 28, 2026

SUMMARY / FIRST READ

The Army picked its vendors this morning. Five microreactor developers — Antares, BWXT, General Atomics, Radiant, and Westinghouse — are getting up to $2.2 billion combined to put working nuclear reactors on five domestic bases by the end of the decade, the kind of concrete federal commitment to baseload power …

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VOL. 1 | NO. 1 • AUGUST 28, 2026 • FRIDAY EDITION

PUBLISHER’S NOTE

Energy & Money follows the dollars through the energy economy. This is a conservative, market-oriented, pro-baseload publication, and we don’t apologize for it. Reliability has economic value. Capital has a cost. Subsidies aren’t free, and ratepayer money is real money — not chips for politicians and developers to gamble with. We favor domestic, dependable generation, and we judge every project the same way: cost, risk, return, and who ultimately writes the check.

THE MARKET IS REPRICING RELIABLE POWER

Existing dispatchable assets, long-term nuclear contracts and brownfield grid connections are drawing fresh capital while electricity bills keep rising.

INSIDE THIS ISSUE — A DIVERSIFIED FIRST EDITION

THE MONEY STORY Lead Analysis

CAPITAL — The market is putting a scarcity premium on dependable megawatts

The most revealing energy-finance story this week was a string of operating power plants changing hands for real money. Equinor agreed to pay $940 million for a majority stake in Pennsylvania’s 1,483-MW Lackawanna Energy Center, a natural gas-fired combined-cycle plant. Constellation agreed to sell the 606-MW Brazos Valley Energy Center, also gas-fired combined-cycle, in Texas to LS Power for $860 million — roughly $1,420 per kilowatt. Smaller but just as telling: Harbert Management Corporation bought the 317-MW Mid-Georgia Cogen plant, a natural gas-fired, dual-fuel cogeneration facility dating to 1998, backed by a fresh 20-year power-purchase agreement with Georgia Power starting in 2028.

Capital doesn’t behave that way toward assets it expects to become worthless. A 20-year revenue tail behind an aging plant, or nine figures for a combined-cycle facility that already has its permits and its grid slot, gives a buyer every reason to keep spending on operation and maintenance instead of walking away.

Nuclear is telling the same story from a different angle. Constellation booked 920 MW of additional long-term power-purchase agreements this month, with 15-to-20-year terms starting between 2029 and 2032. Different fuel, same buyer logic: customers and investors will pay a premium for power that’s firm, useful right where it sits, and contractable for years at a stretch.

Private infrastructure money is making the identical bet on the grid connection itself. Partners Group’s Middle River Power and PowerTransitions platforms — mostly gas-fired peaking and combined-cycle plants, with some legacy coal in the wider Middle River book — have more than doubled operating capacity since 2025, leaning hard on legacy generation sites where an existing interconnection beats waiting years in a new queue.

None of this makes every aging unit worth saving — heat rate, maintenance burden, environmental obligations and fuel access still decide plenty of retirements, and a big price tag doesn’t make a technology sound everywhere it gets built. What it does mean is that anyone still treating an existing megawatt as though its only value shows up in energy-market revenue is leaving money on the table.

The balance sheet is recognizing what a lot of policy debates still won’t admit: a connected site, a working machine, a long-lived contract and a trained crew all carry scarcity value. When replacement power is expensive and interconnection queues stretch for years, the plant you already own is worth more than it used to be.

That’s the theme of our first issue. Reliability isn’t a talking point. It’s an asset attribute, and the market has started pricing it accordingly.

• SOURCE Harbert Management Corporation — Mid-Georgia Cogen acquisition (Aug. 25, 2026)

• SOURCE Equinor — U.S. power-market acquisition

• SOURCE Constellation — Q2 2026 results and Brazos Valley divestiture

• SOURCE Partners Group — Middle River Power / PowerTransitions update (Aug. 25, 2026)

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THE CAPITAL FLOW Where Money Is Moving

THE DEAL BOOK Transactions That Put a Price on Power

ACQUISITION — Equinor’s $940 million Lackawanna deal says U.S. dispatchable power is strategic

Equinor’s agreement to acquire a majority interest in the 1,483-MW Lackawanna Energy Center in Pennsylvania — a natural gas-fired combined-cycle plant near Jessup — carries a reported transaction value of $940 million. For Equinor, it’s one piece of a broader push to build a real power business in select U.S. markets.

For Energy & Money, the corporate strategy is the least interesting part. A global energy company just committed nine figures to a large, existing combined-cycle plant in a power market that’s already tight. The asset delivers scale, dispatchability and an established grid position on day one — attributes a greenfield project could spend years trying to reproduce.

• SOURCE Equinor — recent U.S. acquisitions

• SOURCE Hogan Lovells Cadwalader — transaction value reference

VALUATION — Brazos Valley clears at roughly $1,420 per kilowatt

Constellation agreed in August to sell the 606-MW Brazos Valley Energy Center — a gas-fired combined-cycle plant in Fort Bend County — in ERCOT to LS Power for $860 million before closing adjustments — about $1,420 per kilowatt of existing capacity.

A transaction price isn’t the same thing as an overnight construction estimate. Buyers are also paying for land, permits, equipment, interconnection, operating history and market position, and the plant may carry financing terms that don’t show up in a simple $/kW figure. Even so, that price is a real benchmark, and it should give boards pause before penciling in retirement as the cheap option.

• SOURCE Constellation — Brazos Valley Energy Center divestiture

PLATFORM VALUE — Partners Group reports 4.8 GW and more than 60% EBITDA growth

Partners Group’s Middle River Power and PowerTransitions platforms tell a different piece of the same story. The fleet is overwhelmingly gas-fired — peaking plants and combined-cycle units concentrated in California, plus PowerTransitions’ 226-MW seed portfolio of gas assets bought from Talen Energy — with some legacy coal capacity in the broader Middle River book. Since the platforms were acquired in 2025, Partners Group says combined operating capacity has more than doubled to 4.8 GW and combined EBITDA has climbed more than 60%.

The thesis uses legacy power sites and their interconnections as a launchpad for additional capacity. Whatever you think of each technology stacked onto these sites, the investment logic is hard to argue with: an old power plant site isn’t dead real estate. The interconnection sitting on that property can be worth more than the turbine that came with it.

• SOURCE Partners Group

ACQUISITION — Harbert buys 317 MW of 1998-vintage generation — with a 20-year contract attached

Not every deal this week ran nine figures. Harbert Management Corporation’s purchase of Mid-Georgia Cogen, a 317-MW natural gas-fired, dual-fuel cogeneration plant, is a smaller transaction that makes the same point in miniature: it’s an operating asset with a utility counterparty and a fresh 20-year PPA starting in 2028, not a speculative development site.

The undisclosed price limits how far the valuation math can go, but the contract length says plenty on its own. Twenty years of locked-in revenue justifies real reinvestment in mature equipment and turns a plant that used to carry short-horizon merchant risk into something closer to an infrastructure bond with a smokestack.

THE MONEY LINE / A plant commissioned in 1998 can still pull in institutional capital when the grid connection, the operating record and the contract are worth something.

• SOURCE Harbert Management Corporation

POWER & UTILITY FINANCE Capital Discipline Meets Affordability

RATES — Indiana Michigan Power proposes $59 million in 2027 base-rate reductions

Indiana Michigan Power, an American Electric Power subsidiary, announced a proposal to cut Indiana base rates by about $59 million in 2027. The utility estimates a residential customer using 1,000 kWh a month would save roughly $100 a year, and it is proposing to freeze every rate on the monthly bill for three straight years.

A rate cut doesn’t mean every cost pressure has vanished, and the plan still has to clear the state regulatory process. It matters because it’s landing in the middle of a national affordability squeeze, with utilities being told to spend more on generation and the grid at the exact moment households are already paying noticeably more for power.

The conservative standard here is simple: build what’s necessary, and put the burden of proof on whoever is asking customers to pay for it. Efficient procurement, squeezing more value out of existing assets, and disciplined capital planning matter more every time another billion dollars works its way into rates or required returns.

• SOURCE AEP / Indiana Michigan Power — rate-reduction proposal (Aug. 26, 2026)

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THE RATEPAYER LEDGER What Customers Are Actually Paying

EIA’s new Electric Power Monthly, released Aug. 26 with June data, is why affordability belongs in a finance publication instead of getting waved off as a political talking point. U.S. electricity sales rose just 1.5% from June 2025, but revenue collected from customers jumped 6.0%. The all-sector average price rose 4.5%.

Year to date, residential electricity averaged 18.16 cents per kilowatt-hour, 7.4% above the first half of 2025. Every capital plan should get measured against that number. A project can check every engineering box and still be a financial mistake if customers can’t absorb the rate base it requires.

THE MONEY LINE / Affordability isn’t reliability’s enemy. It’s the financing constraint that forces utilities to chase reliability efficiently instead of expensively.

• SOURCE U.S. EIA — Electric Power Monthly, June 2026

• SOURCE U.S. EIA — year-to-date summary

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VOL. 1 | NO. 1 • AUGUST 31, 2026 .

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CHARLESTON, W.Va. — Thursday, August 27, 2026
Vol. 1, No. 8 | Covering the Previous 24 Hours in American Energy

First Read

Oil fell for a third straight day this morning — Brent down 3% to near $86, WTI off 2.8% to $80 — after Iran and Oman announced a framework for temporarily reopening safer passage through the Strait of Hormuz. It’s the clearest de-escalation signal since the conflict began, though implementation questions remain. On the ground in Iran, two petrochemical plants suspended production amid heatwave-driven power shortages, a reminder that the pressure campaign is compounding strain that already existed.

Treasury Secretary Scott Bessent, meanwhile, downplayed Monday’s sanctions rollout as a “warning shot” and told reporters to expect a bigger move against a specific, unnamed financial institution by the end of the week. A CNN Business analysis added useful context to all of it: China remains the overwhelming buyer of what Iranian oil still moves, importing an estimated $3.9 to $4.2 billion worth last September alone, which means any sanctions serious enough to actually bite Iran’s revenue run straight into US-China friction that only recently cooled.

Nuclear had a genuinely historic day. The IAEA and the Department of Energy formally launched ATLAS — Atomic Technologies Licensed for Applications at Sea — at a Washington ministerial Wednesday, with IAEA Director General Rafael Grossi and Energy Secretary Chris Wright opening the forum. It’s a small, wonky story by cable-news standards. It’s also the clearest signal yet that nuclear propulsion is moving from a military and icebreaker niche toward serious commercial consideration.

Coal and gas infrastructure both had quieter but real news. Thermal coal slipped to $131.25 a ton, extending a recent pullback even as Chinese stimulus signals and a Japanese heat wave offer potential support ahead. And FERC held a public scoping session on the CP2 LNG Expansion Project, part of the routine but consequential environmental review process that determines how fast new Gulf Coast export capacity actually gets built.

Critical minerals rounded out a strong week with two more data points: Brazilian mining giant Vale is studying whether it can recover rare earths and gold from its own historical mining waste, and Critical Metals Corp’s stock jumped 21% as investors piled into the broader rare-earth rally on the back of federal supply-chain support.

Closer to home, a fight over a $1.16 billion transmission line is coming to a head. West Virginia’s Public Service Commission staff, its Consumer Advocate Division, and the state’s largest industrial energy users have all now told the Commission the same thing about NextEra’s Mid-Atlantic Resiliency Link: pause the case or dismiss it outright. Today’s commentary digs into why the Commission should listen — and what’s at stake for West Virginia ratepayers either way.

Domestic Energy News

1. Oil Falls Third Straight Day as Iran-Oman Discuss Hormuz Framework; Iranian Petrochemical Plants Halt Production

CNN — Aug. 26, 2026

Brent crude fell 3% to near $86 a barrel and WTI dropped 2.8% to $80 as Iran and Oman announced a framework for temporary safe passage through the Strait of Hormuz — the clearest de-escalation signal since the conflict began. Iran’s Arvand and Ghadir petrochemical plants separately suspended production amid heatwave-driven power shortages.

Read more: https://www.cnn.com/2026/08/26/world/live-news/iran-war-trump

2. Bessent Calls Monday’s Iran Sanctions a “Warning Shot,” Signals Bigger Move on a Specific Bank This Week

CNN — Aug. 24, 2026

Treasury Secretary Scott Bessent defended holding off on the most crippling sanctions for now, calling Monday’s “Operation Economic Outcast” rollout a “warning shot” rather than the full campaign. He said the public should expect a major sanctions announcement targeting an unspecified financial institution by the end of the week.

Read more: https://www.cnn.com/2026/08/24/world/live-news/iran-war-trump

3. Who’s Buying Iran’s Oil? China Still Dominates, Complicating the New Sanctions Push

CNN Business — Aug. 25, 2026

China remains the overwhelming buyer of Iranian crude, importing an estimated $3.9 to $4.2 billion worth last September alone, according to a CNN Business analysis. Analysts said a full halt would have limited impact on China’s own energy security given already-reduced Iranian volumes, but new sanctions targeting that trade risk reopening US-China friction that only recently cooled.

Read more: https://www.cnn.com/2026/08/25/business/us-sanctions-iran-oil-china

4. IAEA, DOE Formally Launch ATLAS Maritime Nuclear Initiative in Washington

IAEA / U.S. Department of Energy — Aug. 26, 2026

IAEA Director General Rafael Grossi and U.S. Energy Secretary Chris Wright formally opened the ATLAS (Atomic Technologies Licensed for Applications at Sea) initiative at a Washington ministerial Wednesday, establishing a framework to advance small modular reactor deployment for commercial shipping and offshore power.

Read more: https://www.iaea.org/newscenter/pressreleases/iaea-to-launch-atlas-pioneering-nuclear-solutions-for-shipping-and-offshore-energy-washington-august-26-27-2026

5. Thermal Coal Prices Slip to $131.25 a Ton, Extending Pullback Even as Asian Demand Firms

Trading Economics — Aug. 26, 2026

Thermal coal fell to $131.25 per ton on August 26, down 0.30% from the previous day, even as China’s latest stimulus signals and a Japanese heat wave lifting power prices to their highest level since 2023 offer potential support for coal demand ahead.

Read more: https://tradingeconomics.com/commodity/coal

6. FERC Holds Public Scoping Session for CP2 LNG Expansion Project

Federal Energy Regulatory Commission — Aug. 26, 2026

FERC convened a public scoping meeting on the CP2 LNG Expansion Project, Docket Nos. CP26-530-000 and related filings, part of the Commission’s environmental review process for the proposed expansion of Gulf Coast LNG export capacity.

Read more:

https://www.ferc.gov/

7. Vale Studies Recovering Rare Earths, Gold From Its Own Mining Waste

Reuters via NetNewsLedger — Aug. 27, 2026

Brazilian mining giant Vale is studying whether rare earth elements, gold, and other valuable minerals can be recovered from its existing mining waste, Reuters reported Thursday, part of a broader industry shift toward extracting additional value from tailings rather than opening new pits.

Read more: https://www.netnewsledger.com/2026/08/27/mining-news-for-august-27-2026-copper-critical-minerals-and-northwestern-ontario-drilling-in-focus/

8. Critical Metals Corp Stock Jumps 21% Amid Broader Rare-Earth Rally on Government Supply-Chain Support

Yahoo Finance — Aug. 25, 2026

Critical Metals Corp shares gained 21% on August 25 following a broader rally in rare-earth stocks tied to expanded federal support for domestic supply chains. The company’s Tanbreez project in Greenland remains on track for production within three years, per the company.

Read more: https://finance.yahoo.com/quote/CRML/

The Day Ahead

• Bessent’s Bigger Sanctions Announcement: Treasury has signaled a major move targeting a specific, unnamed financial institution by the end of this week — expect this to be the dominant energy-market story through Friday.

• ATLAS Project Groups: with the ministerial launch complete, watch for the initial ATLAS project-group structure and regulatory recommendations to emerge from today’s Port of Baltimore sessions.

• WV PSC Case No. 26-0633-E-GI: the HB 2014 rulemaking implementing Proposed Rule 150 CSR 41 remains pending before the Commission following the reply comment period; a scheduling order or further Commission action could issue at any time.

• EIA Weekly Natural Gas Storage Report: next release Thursday morning — watch for confirmation of NGI’s 23 Bcf injection projection against continued Appalachian pricing weakness.

Commentary

A Stale Justification, an Incomplete Filing, and a Bill for West Virginia: Why the PSC Should Kill MARL

The West Virginia Public Service Commission is on the verge of doing something state regulators rarely do to a multi-billion-dollar transmission project already deep into the approval process: kill it, or at least stop it cold. And they’d be right to.

The Mid-Atlantic Resiliency Link is a proposed 107.5-mile, 500-kilovolt power line that would cut through Monongalia, Preston, Mineral, Hampshire, and Jefferson counties on its way from Pennsylvania to a substation in Gore, Virginia. NextEra Energy Transmission filed for a certificate in January. Since then the case has collected 7,397 formal protests against it and 152 in favor — a lopsidedness that should tell you almost everything you need to know about how this project is landing with the people actually living along its route. Now the PSC’s own professional staff, its Consumer Advocate Division, and the West Virginia Energy Users Group representing the state’s largest industrial ratepayers have all told the Commission the same thing in the last two weeks: pause this case for at least 60 days, or throw it out entirely.

Start with why staff moved first. NextEra filed five last-minute route changes in July, adding roughly a million dollars to the project cost and dragging three new landowners into a case they never got a chance to weigh in on during the public hearings back in June. One of the company’s own engineering witnesses reportedly isn’t even licensed to practice in West Virginia. That’s the profile of a project still being built on the fly, not a developer with a clean, ready-to-approve application, while the clock runs out before an evidentiary hearing already on the calendar.

Then the Consumer Advocate Division landed the real blow. MARL was justified to regional grid planners on the assumption that two major Maryland power plants would retire in 2025, opening a reliability gap this line was supposed to fill. Those plants have since been granted extensions to keep running through at least 2031. The hole in the grid that MARL was built to patch may simply not exist anymore, at least not on the timeline anyone used to justify it. When the premise a billion-dollar infrastructure project rests on quietly disappears, regulators owe ratepayers a plain question before waving the project through on momentum: should West Virginia families still be on the hook for a line the grid may no longer need the way it once did?

And they would be on the hook. PSC staff’s own filing raises a sharper concern than most people following this case realize: PJM’s cost-allocation tariff, the formula that decides who pays for a transmission line like this, may not adequately protect West Virginia ratepayers from covering costs that primarily benefit customers somewhere else on the grid. Appalachian Power and Wheeling Power customers were quietly added to the project’s rate impacts partway through the case, in a change NextEra itself has to admit wasn’t in the original filing. A 107.5-mile line built mostly to move power toward Virginia data centers, paid for in part by West Virginia electric bills, is exactly the cost-shifting dynamic this publication has flagged in PJM’s broader governance mess for months. MARL just puts a specific price tag and a specific set of counties on the abstraction.

The precedent here matters as much as the dollars. If the Commission grants the pause or the dismissal, it sends a message to every transmission developer eyeing West Virginia as a pass-through state for someone else’s power needs: come with a complete application, a route that doesn’t shift mid-case, and a cost allocation that doesn’t quietly stick West Virginians with someone else’s bill, or don’t come at all. If the Commission waves MARL through anyway, on a stale justification and an incomplete filing, it tells the next developer the opposite — that momentum and sunk cost will eventually carry a project past whatever objections state regulators, ratepayer advocates, and thousands of West Virginia landowners raise along the way.

That next developer already has a name: Valley Link. The Dominion, AEP, and FirstEnergy consortium behind that project is proposing an even bigger line — 260 miles at 765 kilovolts, running from the John Amos plant in Putnam County to Frederick County, Maryland, still in the open-house and draft-route stage rather than a filed certificate application. Valley Link runs a separate docket from MARL, so the Commission’s ruling here won’t bind it directly — but it was justified by the identical PJM reliability assessment MARL leaned on, built around the same assumption about Maryland generation retirements that the Consumer Advocate Division just told the PSC no longer holds. If that assumption is too stale to support MARL, it’s too stale to support Valley Link on the same logic, and past estimates have put West Virginia ratepayers’ share of Valley Link’s cost north of $220 million — more than MARL’s own exposure. PSC Staff’s warning about PJM’s cost-allocation tariff failing to protect West Virginia customers from footing someone else’s bill applies with at least as much force to a 765-kilovolt line as it does to MARL’s 500-kilovolt one. Valley Link’s developers are watching this docket closely, and they should be: whatever bar the Commission sets for NextEra here is the bar they’ll be filing against next.

West Virginia doesn’t need to reflexively oppose every transmission line that crosses its borders. Plenty of genuinely needed infrastructure runs through this state and serves it well. But a project built on an outdated premise, an incomplete application, and a cost formula that may quietly bill West Virginia families for Virginia’s growth doesn’t deserve the benefit of the doubt just because it’s already been in the pipeline for seven months. The Commission has every reason on the record to hit pause, and the state’s ratepayers deserve nothing less than that scrutiny before this line gets built through their backyards on someone else’s justification.

By T.L. Headley, MBA, President
The Hedley Company

AI DISCLOSURE: AI assistance used in research/drafting under author’s direction; all judgments author’s own.

THE BASELOAD | Published by The Hedley Company | 169 Raceview Drive, Ona, WV 25545 | tlheadley@hedleycompany.com | Ph. 681.356.1776

VOL. 1, NO. 31 │ WEEK ENDING AUGUST 23, 2026

DATA POINT OF THE WEEK

FAST FACTS

EXECUTIVE SUMMARY

The week ending August 23, 2026 handed the domestic rare earth buildout its clearest good-news story in months, and it came from two directions at once. Energy Fuels announced that the terbium oxide coming out of its White Mesa Mill in Utah has cleared full commercial qualification with one of Japan’s largest rare earth magnet manufacturers outside China — the company’s own words, no further validation required before that material can go into a commercial magnet. That is not a pilot claim or a laboratory purity number. It is a Japanese buyer, operating under some of the toughest acceptance standards in the industry, putting American-mined and American-processed terbium into its supply chain. Pair that with the renewed national coverage of West Virginia University’s acid-mine-drainage rare earth work this week, and Appalachia’s coal legacy looks less like a liability and more like the raw-material half of the same story Utah just proved on the qualification side.

Read more

Demand | Generation Mix | Market Prices | Reliability |
VOL. 1, NO. 32 | WEEK ENDING AUGUST 23, 2026

Table of Contents

Key Signals

Read more

CHARLESTON, W.Va. — Wednesday, August 26, 2026
Vol. 1, No. 7 | Covering American Energy

First Read

Oil kept sliding this morning — its third straight losing session — after Iran and Oman said they’d discussed a framework to temporarily reopen safer shipping through the Strait of Hormuz. American crude inventories didn’t help the bulls either: the API reported a 4.2 million-barrel build, more than double what analysts expected. Treasury Secretary Scott Bessent, meanwhile, downplayed Monday’s sanctions rollout as a “warning shot,” and told reporters to expect a bigger move against a specific, unnamed financial institution by the end of the week. Today’s commentary steps back from the day-to-day Iran headlines to look at a different number making the rounds this week: new EIA data showing wind and solar reached 20% of U.S. generation in the first half of 2026. That statistic gets repeated constantly. It’s also close to meaningless for judging grid reliability, and today’s piece explains why.

Appalachian gas producers have their own headache brewing. Natural Gas Intelligence reports regional prices have sunk low enough that supply curtailments in the Marcellus Shale are now a real possibility heading into fall, even as record heat lifts prices everywhere else in the country. Nationally, gas prices actually touched a one-week low on softer demand forecasts and reduced LNG flows, and Cheniere confirmed its Corpus Christi LNG plant is undergoing scheduled maintenance — a reminder that U.S. LNG exports are facing what Reuters called an “endurance test” from elevated domestic gas prices.

Nuclear had an unusually newsy morning outside the reactor fleet itself. The Financial Times reports the U.S. is weighing a nuclear-powered merchant marine fleet to challenge China’s dominance in commercial shipbuilding, and DOE and the IAEA are launching a new initiative this week — dubbed ATLAS — aimed at licensing nuclear technology for use at sea.

And the broader fuel-mix data itself, reported by E&E News from EIA figures, tells a story with more nuance than the renewable-share headline suggests: gas held flat as the country’s largest single power source, nuclear output grew, and coal generation fell 10% — the only major source to decline in both absolute terms and market share.

Top 10 — Domestic Energy News

Ranked by importance, not chronology. Every headline links to the live source.

1. Oil Slides Third Straight Day as Iran, Oman Discuss Framework to Reopen Hormuz; U.S. Crude Stocks Surge

CNN / American Petroleum Institute — Aug. 26, 2026

Global oil prices fell for a third consecutive day after Iran and Oman said they had discussed a framework to establish temporary safe passage through the Strait of Hormuz. The API separately estimated U.S. crude inventories rose 4.2 million barrels for the week ending August 21 — more than double the 1.9 million-barrel build analysts expected — adding further downward pressure on prices already retreating from Monday’s sanctions-driven spike.

Read more: https://edition.cnn.com/2026/08/26/world/live-news/iran-war-trump

2. Bessent Calls Monday’s Iran Sanctions a “Warning Shot,” Signals Bigger Move on a Specific Bank This Week

CNN — Aug. 24-25, 2026

Treasury Secretary Scott Bessent defended the decision to hold off on the most crippling sanctions for now, calling Monday’s “Operation Economic Outcast” rollout a “warning shot” rather than the full campaign. He said the public should expect a major sanctions announcement targeting an unspecified financial institution by the end of this week, while declining to say whether the U.S. is willing to target Chinese banks directly.

Read more: https://www.cnn.com/2026/08/24/world/live-news/iran-war-trump

3. First-Half 2026 Grid Data: Coal Fell 10%, Nuclear Rose 2%, Natural Gas Remains the Dominant Fuel Source

E&E News (EIA data) — Aug. 25, 2026

EIA data reported by E&E News shows natural gas generated 767 terawatt-hours in the first half of 2026, essentially flat and still the largest single source of U.S. power by a wide margin. Nuclear generation rose 2% to 390 terawatt-hours. Coal generation fell 10% to 323 terawatt-hours, the only major source to decline in both absolute output and market share, while wind and solar combined reached 20% of total generation — a generation-share statistic that says nothing about how much of that capacity can be counted on when demand actually peaks.

Read more: https://natlawreview.com/article/grids-first-half-2026-fuel-mix

4. Appalachian Natural Gas Prices Sink Toward Levels That Could Trigger Marcellus Supply Curtailments This Fall

Natural Gas Intelligence — Aug. 24, 2026

Physical natural gas prices were mixed Monday as record heat across the southern tier lifted Gulf Coast and Western hub prices, while Appalachian pricing sank low enough that producers could face Marcellus Shale supply curtailments this fall. NGI is projecting the EIA’s weekly storage report for the week ended August 21 will show a 23 Bcf injection, 7 Bcf higher than the prior week.

Read more:

https://www.naturalgasintel.com/

5. Cheniere Confirms Corpus Christi LNG Maintenance as U.S. Exports Face “Endurance Test” From High Gas Prices

Reuters — Aug. 25, 2026

Cheniere Energy confirmed its Corpus Christi LNG export terminal is undergoing scheduled maintenance, even as Reuters reported U.S. LNG exports broadly are facing an “endurance test” as elevated domestic natural gas prices squeeze the economics of shipping gas overseas. U.S. natural gas prices separately touched a one-week low on softer demand forecasts and reduced LNG flows.

Read more: https://www.lngglobal.com/august-25-2026-headlines/

6. U.S. Weighs Nuclear-Powered Merchant Fleet to Challenge China’s Shipbuilding Dominance

Financial Times — Aug. 25, 2026

The Financial Times reports the U.S. government is evaluating development of a nuclear-powered merchant marine fleet as part of a broader strategy to challenge China’s dominance in commercial shipbuilding, an initiative that would extend nuclear propulsion well beyond its traditional naval applications.

Read more: https://www.lngglobal.com/august-25-2026-headlines/

7. DOE, IAEA to Launch ATLAS Initiative for Nuclear Power at Sea This Week in Washington

U.S. Department of Energy / IAEA — Aug. 26-27, 2026

The United States will host the ministerial launch of the International Atomic Energy Agency’s new initiative, Atomic Technologies Licensed for Applications at Sea (ATLAS), in Washington on August 26 and 27. The initiative aims to establish a licensing and regulatory framework for nuclear reactors used in maritime applications.

Read more: https://www.energy.gov/listings/energy-news

8. Hanwha Establishes New U.S. LNG Business Subsidiary “Hanwha Horizon USA”

Press release via LNG Global — Aug. 25, 2026

South Korea’s Hanwha Group established a new subsidiary, Hanwha Horizon USA, to manage its growing U.S. liquefied natural gas business interests, adding to a wave of foreign capital moving into American LNG infrastructure as export capacity continues to expand.

Read more: https://www.lngglobal.com/august-25-2026-headlines/

9. DOE Publishes June 2026 Natural Gas Imports and Exports Monthly Report

U.S. Department of Energy — Aug. 25, 2026

DOE published its monthly report on U.S. natural gas imports and exports for June 2026, providing the federal government’s official accounting of cross-border gas flows as LNG export capacity continues its multi-year buildout along the Gulf Coast.

Read more: https://www.lngglobal.com/august-25-2026-headlines/

10. Turkey Braces for Potential Gas Squeeze as U.S. Targets Iran Trade

Bloomberg — Aug. 25, 2026

Bloomberg reports Turkey is preparing for a possible natural gas supply squeeze as expanded U.S. sanctions increasingly target countries and entities maintaining energy trade relationships with Iran, illustrating how Washington’s sanctions campaign is beginning to ripple into third-country energy security calculations.

Read more: https://www.lngglobal.com/august-25-2026-headlines/

The Day Ahead

• EIA Weekly Natural Gas Storage Report: released Thursday morning — NGI projects a 23 Bcf injection for the week ended Aug. 21; watch for confirmation given the Appalachian pricing weakness flagged above.

• Bessent’s Bigger Sanctions Announcement: Treasury has signaled a major move targeting a specific, unnamed financial institution by the end of this week — expect this to be the dominant energy-market story through Friday.

• WV PSC Case No. 26-0633-E-GI: the HB 2014 rulemaking implementing Proposed Rule 150 CSR 41 remains pending before the Commission following the reply comment period; a scheduling order or further Commission action could issue at any time.

• ATLAS Ministerial Launch: the DOE/IAEA nuclear-at-sea initiative concludes its Washington launch Thursday — watch for participating nations and initial regulatory framework details.

Commentary

The 20% Statistic That Doesn’t Mean What You Think: Generation Share Versus Grid Reliability

New EIA data on the first half of 2026 is making the rounds this week, and the headline number renewables advocates keep repeating is that wind and solar combined reached 20% of U.S. electricity generation, up from 18.6% a year earlier. That number is accurate. It is also close to useless for answering the only question that actually matters to a family that wants their lights on during a January cold snap or a July heat dome: how much of the grid’s capacity can be counted on to show up when demand peaks?

Generation share and reliable capacity are two entirely different measurements, and conflating them is the single most persistent trick in the energy-transition conversation. A gigawatt of coal, gas, or nuclear capacity is available essentially whenever the grid operator calls on it, subject to routine maintenance and the occasional forced outage. A gigawatt of wind or solar capacity produces electricity only when the wind blows or the sun shines, which means the actual “effective load-carrying capability” utilities can bank on from a solar fleet often runs somewhere between 20% and 50% of its nameplate rating, and for a wind fleet the number is frequently lower still, depending on the region and season. PJM’s own capacity market recognizes this explicitly, assigning solar and wind far smaller capacity credits per installed megawatt than it assigns thermal and nuclear plants. The 20% generation-share statistic says nothing about any of that.

Here’s what the first-half data actually shows once you separate generation share from reliability. Natural gas generated 767 terawatt-hours, essentially flat year over year, and remains by a wide margin the largest single source of power in the country. Nuclear output rose 2% to 390 terawatt-hours — modest growth, but growth in exactly the resource category that runs at a 90%-plus capacity factor around the clock. Coal fell 10% to 323 terawatt-hours, continuing its decline. Wind and solar grew fast enough to reach that 20% generation share, but growing your share of a pie by adding capacity that can’t be dispatched on demand is a different achievement than growing the pie’s reliability.

This distinction is exactly why grid operators from PJM to MISO to ERCOT keep issuing reliability warnings even as renewable capacity additions accelerate year after year. You can build enormous quantities of solar and wind, watch their generation-share percentage climb steadily, and still end up with a resource-adequacy problem, because the metric that determines whether the lights stay on during a genuine system stress event is dispatchable capacity margin, not annual generation share. PJM’s reserve margin has been shrinking even as renewable capacity additions have been the fastest-growing category in its interconnection queue. Those two facts are the direct, predictable consequence of adding capacity that helps the annual generation statistics while doing comparatively little for the hour when the grid actually needs the electrons — not a contradiction at all.

Wind and solar remain a legitimate part of an all-of-the-above energy mix, and cheap incremental generation has genuine value when the resource is actually producing. The real argument here is for honesty about what category of resource they belong in when utilities, regulators, and reporters talk about keeping the lights on. Baseload means coal, nuclear, natural gas, and hydro — the resources that show up on command, day and night, regardless of weather. Wind and solar are supplemental generation that reduces fuel burn on the baseload fleet when conditions cooperate. Calling them anything more than that in a resource-adequacy conversation is a category error dressed up as optimism, and category errors in grid planning eventually show up as blackouts.

West Virginia’s own generation mix — 87% coal, per the state’s most recent EIA data — looks like an outlier next to the national 20% renewable-share number, and it should be read as exactly the opposite of a liability. It’s the reason this state’s grid doesn’t face the same capacity-credit math problem PJM’s other members increasingly do. The policy conversation in Charleston should keep that distinction in view: the real goal is maintaining the dispatchable capacity margin that keeps the lights on when it actually matters, not chasing a generation-share percentage that looks good in a press release.

By T.L. Headley, MBA,
President
The Hedley Company

AI DISCLOSURE: AI assistance used in research/drafting under author’s direction; all judgments author’s own.

THE BASELOAD | Published by The Hedley Company | 169 Raceview Drive, Ona, WV 25545 | tlheadley@hedleycompany.com | Ph. 681.356.1776

FAST FACTS

Note on data cadence: unlike EIA’s weekly coal production series, no single federal agency publishes a weekly national data-center production or absorption report. Figures above are drawn from the most recently published data as of this issue: FERC docket filings dated as shown; corporate and market data (CBRE, JLL, Avison Young) reflect Q2 2026, the most recent full-quarter market data available; hyperscaler capex reflects Q2 2026 earnings-call guidance. Reporting lag ranges from same-week (FERC) to one full quarter (commercial real estate data). Where this issue cannot obtain a true weekly figure, it says so rather than estimating one.

EXECUTIVE SUMMARY

The interconnection reckoning FERC set in motion in June came due this week. Under Section 206 show-cause orders issued to all six FERC-jurisdictional grid operators — PJM, MISO, SPP, CAISO, ISO-NE and NYISO — August 17 was the deadline for each to either defend its current large-load tariff as just and reasonable or propose reforms. PJM, which carries the heaviest data-center load growth of the six and projects 32 gigawatts of peak demand growth by 2030, is the filing every other region will be measured against. A related governance docket, AD26-7, set August 21 as the deadline for post-technical-conference comments, with FERC’s Alternative Dispute Resolution forum opening September 1. Separately, PJM’s proposed $20 billion capacity backstop procurement (Docket ER26-3380) remains pending with no ruling yet, following a second consecutive Base Residual Auction clearing at the $325/MW-day price cap and a 6,831-megawatt reliability shortfall.

On the ground, the story split two ways this period. Developers kept announcing multi-gigawatt, multibillion-dollar campuses at a pace that shows no sign of slowing — OpenAI’s $20 billion Project Camellia in Effingham County, Georgia and Meta’s sixfold capex increase on its El Paso campus to $10 billion both illustrate how fast individual projects are scaling past anything the grid was designed for. At the same time, local governments from Texas to New Jersey kept passing moratoriums and bans that are now generating real litigation exposure: Hill County, Texas rescinded the state’s first county-level moratorium after a developer sued for more than $100 million, and similar suits are now active in Michigan, Tennessee and New Jersey. More than 30 North Carolina jurisdictions alone have adopted or floated some version of a pause.

A Bloomberg analysis published August 18 quantified something the industry had downplayed for two years: 99 tracked data-center-dedicated gas plants could add roughly 318 million metric tons of CO2 annually — about 20 percent of current U.S. power-sector emissions — if run at typical utilization rates. And underneath all of it, the real ceiling on this industry’s growth is neither chips nor capital. Demand for generator step-up transformers grew 274 percent between 2019 and 2025, lead times on large high-voltage units now run past three years, and industry analysts estimate 30 to 50 percent of the roughly 16 gigawatts of U.S. data center capacity announced for 2026 is at real risk of delay or cancellation — driven by equipment shortages, not financing or GPU supply.

Five things to know this week: FERC’s national interconnection clock ran out on August 17; the local moratorium wave has become a litigation wave with real financial exposure on both sides; hyperscaler capex is tracking toward $630 billion for 2026 even as Wall Street questions the underlying GPU depreciation math; a Georgia mega-campus and a West Texas gas-plant permit both illustrate how fast individual projects are scaling past anything the grid was designed for; and the transformer and switchgear shortage — not GPU supply — is now the hard ceiling on how much of this actually gets energized on schedule.

SECTION 1 | NATIONAL DATA CENTER DEVELOPMENT PIPELINE

Source: Data Center Knowledge, Data Center Daily Notes (Strisker), Blackridge Research, Barchart, DediRock, DOE, TCEQ. Compiled from project disclosures dated within the past 30 days as of Aug. 23, 2026. N/D = not disclosed by developer or reporting source at time of publication.

Pipeline Analysis

Every project in the table above disclosed its megawatts and its capital commitment before it disclosed permanent headcount, and three of the eight did not disclose permanent headcount at all as of this issue. That pattern is not necessarily deceptive — permanent staffing on a hyperscale campus is genuinely small relative to its physical and capital footprint, typically 50 to 200 people regardless of size (see Section 5) — but it means the jobs figure most often cited in a county commission press conference is the construction-phase number, which is real payroll for two to four years, not a permanent economic base. Communities and reporters covering individual project announcements should request both figures separately and in writing before treating either as the headline number.

The clearest structural signal in this period’s pipeline is the widening gap between projects funding their own generation and transmission (SB Energy/AEP Ohio, Meta’s El Paso pledge) versus those relying on private, off-grid generation entirely (GW Ranch). The former model, however imperfect, at least creates the possibility of new capacity benefiting the broader grid; the latter removes the project from public interconnection queues but also removes any obligation to share the resulting generation. Regulators and communities negotiating with developers should treat this distinction as a primary term of any agreement, not an afterthought.

SECTION 2 | POWER PROCUREMENT & GENERATION ECONOMICS

Source: American Action Forum; U.S. DOE; PJM Interconnection; company disclosures. Dates as shown per deal.

Power Market Commentary

Gas remains the default answer to the industry’s power problem, and the West Texas GW Ranch permit — at up to 7.7 gigawatts, the largest approved gas-fired power project in U.S. history — was built explicitly to serve a private grid rather than the public system. NextEra’s separate 10 gigawatts of combined new gas capacity in Texas and Pennsylvania connects to the public regional transmission grids instead, a meaningfully different cost-and-benefit structure that policy discussions frequently blur together under the single heading of “new gas capacity.” The distinction matters directly for ratepayers: capacity that interconnects to the public grid is at least theoretically available to non-data-center customers; behind-the-meter capacity is not.

PJM’s capacity market result is the dominant power-price signal of the period. A second consecutive Base Residual Auction clearing at the $325-per-megawatt-day price cap, with the entire RTO falling 6,831 megawatts short of its reliability requirement, is not a one-time event — it is the clearest available evidence that PJM’s capacity base has not kept pace with load growth driven overwhelmingly by data centers. PJM’s pending $20 billion backstop procurement (ER26-3380) proposes a one-time reliability auction at a $555-per-megawatt-day cap to cover the shortfall; whoever pays for that backstop, developer or ratepayer, is the single largest open cost-allocation question in the entire national data-center policy debate right now.

SECTION 3 | GRID RELIABILITY, FERC DOCKETS & LARGE-LOAD INTERCONNECTION

Source: FERC docket filings (RM26-4-000; EL26-67 through EL26-72 series; AD26-7-000; ER26-3380); PJM Interconnection public filings.

Grid Analysis

FERC’s June 18 show-cause orders directed all six FERC-jurisdictional RTOs and ISOs to either justify their existing large-load interconnection tariffs as just and reasonable or propose reforms addressing five common categories the Commission identified. The orders followed a Department of Energy directive last October under Section 403 of the DOE Organization Act, calling for standardized rules on how loads above 20 megawatts — including co-located generation arrangements — connect to the transmission system. August 17 marked the 60-day deadline for each RTO and its transmission owners to file. PJM’s response is the one every other state commission and developer nationally will be measuring their own region against, given PJM’s outsized share of national data-center load growth and its two consecutive capacity-auction shortfalls.

The core policy question FERC is resolving is cost causation: whether the load that triggers a network upgrade pays for it directly, or whether that cost gets socialized across every ratepayer in the footprint. Whatever gets filed in response to the show-cause orders will set that answer region by region. This publication will carry a full docket-by-docket breakdown of the PJM and MISO filings once they are available in the public record.

SECTION 4 | REAL ESTATE MARKET: LEASING, VACANCY & ABSORPTION

Source: CBRE Global Data Center Trends 2026; Avison Young Q2 2026 U.S. Data Center Market Overview; JLL North America Data Center Report, Midyear 2026.

Real Estate Analysis

National data center vacancy fell below 1 percent in the second quarter of 2026 — the lowest ever recorded — even as U.S. inventory grew nearly 80 percent year-over-year. That combination should be structurally impossible in a normal commercial real estate market; it is possible here because almost nothing coming online is speculative. Roughly 80 percent of capacity currently under construction nationally is already pre-leased, and JLL reports most tenants signing today are locking in space for 2028 delivery. Northern Virginia, still the largest single market in the country, posted 0.3 percent vacancy. Atlanta posted the steepest vacancy compression of any major market, falling from 3.6 percent to 1.0 percent.

Financing structures are shifting to match. Data-center-backed securitizations — asset-backed and commercial mortgage-backed structures collateralized by leases and equipment — reached $17 billion in the first half of 2026, up 29 percent from a year earlier. That is institutional capital underwriting the assumption that current demand is durable rather than speculative, a useful counterpoint for any argument that this is a bubble on the verge of correcting.

SECTION 5 | EMPLOYMENT & ECONOMIC FOOTPRINT

Source: Associated General Contractors of America; Brookings Institution; NetChoice/Commonwealth Economics Partners (Kentucky); Northern Virginia Technology Council; U.S. Census Bureau construction spending data.

Employment Analysis

The honest read on data-center employment cuts against both sides of the public debate simultaneously. Critics are correct that permanent operating employment at a hyperscale campus is genuinely modest — typically 50 to 200 people regardless of the facility’s capital scale — and that press materials citing large “jobs created” figures are almost always blending in the temporary construction-phase workforce. But proponents are also correct that the construction-phase impact is real, not manufactured: national data center construction spending hit $59.3 billion on a seasonally adjusted annual basis in May 2026, up 23 percent year-over-year, and now accounts for roughly 8.0 percent of all private nonresidential construction spending nationally. Construction wages in this sector are rising faster than the private-sector average and already run about 20 percent above it.

Tax revenue is frequently the more durable and better-documented local benefit than either jobs figure. Loudoun County, Virginia’s data center corridor generates more than $600 million a year in local tax revenue on a cumulative, multi-decade basis. A single Ohio project has been modeled to produce roughly $84 million in annual peak state and local tax collections. A typical 400-megawatt Kentucky project is projected to generate $290 million to $435 million in local tax revenue over a 12-year window. Communities negotiating incentive packages should treat enforceable, clawback-backed tax and job commitments as the more reliable metric than either headline jobs number.

Modeled National Construction Labor Footprint — Methodology Note

Using AGC’s cited Ohio case study as a per-worker output benchmark ($2.4 billion total project economic output supported by approximately 9,700 peak construction jobs, or roughly $247,400 in output per construction worker), and applying that ratio to the $59.3 billion national annualized data-center construction spending run rate reported for May 2026, yields a modeled national estimate of approximately 240,000 FTE-equivalent construction workers supported industry-wide at the current build pace. This is an extrapolation from a single named project’s output-per-worker ratio applied nationally, not a direct headcount measurement, and it should be read as a directional order-of-magnitude estimate rather than a precise employment count. A materially different capital-to-labor mix in other states’ projects would change this estimate meaningfully; readers using this figure for planning purposes should treat it as illustrative rather than authoritative and verify against state-specific labor data where available.

SECTION 6 | SUPPLY CHAIN: THE TRANSFORMER AND SWITCHGEAR BOTTLENECK

Source: Wood Mackenzie transformer survey data as cited in Inflect and The Geopolitical Economist; Sightline Climate/Bloomberg pipeline-delay estimates; company capacity disclosures (Cummins).

Supply Chain Analysis

Every generation deal and every hyperscaler capex commitment in this issue is contingent on physical equipment that does not yet exist in sufficient quantity. Demand for generator step-up transformers grew 274 percent between 2019 and 2025, and demand for substation transformers rose 116 percent over the same period — both figures far outpacing domestic manufacturing capacity. Lead times that ran 24 to 30 months before 2020 now stretch past three years for large high-voltage units, with some reporting sources citing ranges as wide as 80 to 210 weeks depending on unit size and manufacturer backlog. Cummins is reportedly sold out of high-horsepower gensets through 2028.

The consequence is quantifiable at the pipeline level: of roughly 16 gigawatts of U.S. data center capacity announced for 2026, only about 5 gigawatts was actually under construction as of mid-2026, and analysts at Sightline Climate estimate 30 to 50 percent of the broader announced pipeline is at real risk of delay or cancellation — driven by transformer and switchgear shortages rather than financing or chip availability. A $2 billion campus can sit dark waiting on a $40 million transformer order. This is the single most important fact in this entire report for anyone modeling how much of the announced pipeline actually gets energized on the timeline developers are promising.

SECTION 7 | DOMESTIC DATA CENTER INDUSTRY NEWS

FERC’s National Show-Cause Deadline Passes for All Six RTOs/ISOs

Federal Energy Regulatory Commission, Docket Nos. EL26-67 through EL26-72 | Aug. 17, 2026

WHY IT MATTERS: This is the largest single regulatory event of the period. Whatever PJM, MISO and the other four grid operators filed in response determines, region by region, whether data center developers or the broader ratepayer base pays for new transmission and generation triggered by large-load interconnection. THE DIGITAL LOAD is pulling the actual filings now and will carry a full breakdown once available in the public docket.

Bloomberg: Data-Center Gas Plants Could Boost U.S. Power Emissions 20%

Bloomberg News, citing BloombergNEF data | Aug. 18, 2026

WHY IT MATTERS: This converts a two-year-old activist estimate into a quantified, citable industry number — 99 tracked plants, roughly 318 million metric tons of CO2 annually at typical utilization. Expect this figure cited in every state air-permitting fight and hyperscaler sustainability-report footnote from this point forward.

Texas: Hill County’s $100 Million Moratorium Lesson

MultiState Insider | Aug. 19, 2026

WHY IT MATTERS: Hill County rescinded the state’s first county-level data center moratorium after a developer sued for more than $100 million in damages, prompting neighboring Tom Green County to abandon a similar plan. This is now the cautionary case every municipal attorney nationally cites when a client proposes a fast, reactive moratorium.

Texas: Gov. Abbott Orders Statewide Grid-Connection Audit

MultiState Insider | Aug. 2026

WHY IT MATTERS: The audit of every data center connecting to the Texas grid creates a de facto statewide pause pending review — a significant development for the nation’s fastest-growing data-center interconnection market and a wildcard for every pending ERCOT-territory project.

Michigan: Gibraltar and Wixom Sued Over Targeted Moratoriums

Govtech; Click On Detroit | Aug. 19, 2026

WHY IT MATTERS: Developers argue both moratoriums were written specifically to stop already-pending applications. Courts have a long history of striking down ordinances targeted at a single named applicant while upholding generally applicable rules adopted in advance — the distinction is the whole case for both suits.

Tennessee: DC BLOX Sues Nashville Over Moratorium and Buffer Ordinance

Brushwood Media Network / The Center Square | Aug. 12, 2026

WHY IT MATTERS: The federal suit tests whether a proximity ordinance passed after a specific application was filed can survive constitutional scrutiny. The dispute drew bipartisan local opposition to the specific site, including public criticism from Republican gubernatorial nominee Sen. Marsha Blackburn.

Louisiana PSC Votes to Keep Meta’s Richland Parish Facility Details Confidential

Data Center Moratoriums Weekly Tracker | Aug. 13, 2026

WHY IT MATTERS: A 3-1 vote shielded project details despite an administrative law judge’s own subpoena — a live transparency fight over how much ratepayers funding nearby infrastructure ever get to see about the project driving the bill.

SECTION 8 | INTERNATIONAL DATA CENTER INTELLIGENCE

Global Vacancy Diverges Sharply by Region

CBRE Global Data Center Trends 2026; JLL EMEA Data Centre Mid-Year 2026 Report

WHY IT MATTERS: European colocation vacancy across FLAP-D markets held at 6.4% in Q2 2026, roughly six times the U.S. national rate, while APAC vacancy varies enormously by market — Hong Kong at 18% (down from 28% a year earlier) against Singapore at 2%. U.S. developers and capital increasingly view the domestic power-constrained market as tighter, not looser, than most international alternatives.

Meta’s First Canadian Campus Signals Siting Diversification

Data Center Knowledge, New Data Center Developments: August 2026

WHY IT MATTERS: The $9 billion-plus Sturgeon County, Alberta project is Meta’s first Canadian data center. Hyperscalers actively diversifying siting outside the U.S. interconnection queue is a pressure valve worth watching as domestic permitting and transformer delays stretch on.

AWS Commits $48 Billion to India Through 2030

Data Center Knowledge, New Data Center Developments: August 2026

WHY IT MATTERS: The commitment includes $21 billion allocated specifically to cloud and AI infrastructure from 2026-2030, alongside workforce development programs — a signal that hyperscaler capital deployment is not solely a U.S. grid-constraint story but a global capacity race.

SECTION 9 | LEGISLATIVE & REGULATORY DEVELOPMENTS

Industry Action key: MONITOR = track for developments; COMMENT = formal comment period open; FILE = filing deadline applies directly.

SECTION 10 | SWOT ANALYSIS & STRATEGIC OUTLOOK

Strategic Outlook

This period’s data draws a sharper line than usual between the data-center industry’s two live fault lines, and developers, communities and policymakers should read them separately rather than blending them into a single national narrative. On the regulatory-cost side, the question FERC is resolving through its six show-cause dockets is fundamentally about who pays: whether the load that triggers a network upgrade bears that cost directly, or whether it gets socialized across every ratepayer in the footprint. PJM’s back-to-back capacity-auction shortfalls and its pending $20 billion backstop procurement make this the single most consequential open question in the entire sector heading into the fourth quarter.

On the local-political side, the moratorium-to-lawsuit pipeline is accelerating faster than most industry participants have priced in. More than 30 North Carolina jurisdictions alone have adopted or floated some version of a pause, and the financial exposure on the government side is no longer theoretical — Hill County’s nine-figure damages exposure is a fact pattern now being cited nationally by municipal attorneys advising clients against fast, reactive ordinances. States writing enforceable, litigation-resistant tariff structures (Ohio, Kentucky, Colorado, Minnesota) are proving to be a more durable policy tool than outright bans, which continue to lose in court when adopted in a panic rather than through orderly process.

The single most important physical-world constraint in this issue is not a market or legal signal at all — it is a piece of hardware. The transformer and switchgear shortage detailed in Section 6 is the hard ceiling on how much of the current pipeline actually gets energized on schedule, and it will remain the binding constraint on this industry regardless of how favorably the FERC dockets or state legislatures resolve. Developers, utilities and communities negotiating project timelines should treat announced in-service dates with real skepticism until equipment procurement status is confirmed directly.

Week’s Bottom Line

The data-center buildout remains structurally under-supplied by almost every real estate measure — sub-1% national vacancy, 80% pre-leasing, and record capex — even as its two biggest headwinds intensified this period: a national regulatory reckoning over who pays for the grid upgrades this growth requires, and a fast-metastasizing local moratorium-and-lawsuit pattern that is proving expensive for governments that move in haste. The transformer and switchgear shortage detailed in Section 6, not GPU supply or capital availability, is now the most reliable predictor of which announced gigawatts actually get built on schedule and which stay speculative interconnection requests.

DATES & DEADLINES

• Aug. 21, 2026 — FERC Docket AD26-7 post-technical-conference comments due (PJM governance)

• Sept. 1, 2026 — FERC Alternative Dispute Resolution forum opens (PJM governance track)

• September 2026 — PJM target window for FERC-approved special capacity backstop procurement (ER26-3380)

• Ongoing — Ohio Supreme Court docket activity on the AEP Ohio data-center tariff appeal (no argument date set)

• Ongoing — Texas statewide data-center grid-connection audit; no stated completion date

• 2027 legislative sessions — Oregon and New Mexico statewide data-center moratorium bills

• Quarterly — CBRE, JLL, and Avison Young data center market reports (next: Q3 2026, expected mid-October)

PRIMARY SOURCES

• Federal Energy Regulatory Commission, Docket Nos. RM26-4-000, EL26-67 through EL26-72, AD26-7-000, ER26-3380 — large-load interconnection show-cause orders, PJM governance docket, and capacity backstop filing.

• PJM Interconnection, “PJM Capacity Auction Procures 138,318 MW of Generation Resources,” July 14, 2026 — 2028/2029 Base Residual Auction results.

• Day Pitney, McGuireWoods, Orrick — client alerts on FERC’s June 18, 2026 show-cause orders and large-load interconnection reform categories.

• CBRE, “Global Data Center Trends 2026,” Q1/Q2 2026 data. https://www.cbre.com/insights/reports/global-data-center-trends-2026

• Avison Young, “Q2 2026 US Data Center Market Overview.” https://www.avisonyoung.us/us-data-center-market-overview

• JLL, “North America Data Center Report, Midyear 2026.” https://www.jll.com/en-us/insights/market-dynamics/north-america-data-centers

• Associated General Contractors of America, “Data Centers - Economic Impact.” https://www.agc.org/understanding-economic-impact-data-center-development

• Brookings Institution, “New Evidence on Data Center Employment Effects,” Aug. 2026. https://www.brookings.edu/articles/new-evidence-on-data-center-employment-effects/

• Data Center Knowledge, “New Data Center Developments: August 2026.” https://www.datacenterknowledge.com/data-center-construction/new-data-center-developments-august-2026

• Bloomberg News, “Data Center Gas Plants to Boost US Power Emissions by 20%,” Aug. 18, 2026. https://www.bloomberg.com/news/articles/2026-08-18/data-center-gas-plants-to-boost-us-power-emissions-by-20

• MultiState Insider, “The Local Fight Over Data Centers: A Texas Case Study,” Aug. 19, 2026. https://www.multistate.us/insider/2026/8/19/the-local-fight-over-data-centers-a-texas-case-study

• Data Center Moratoriums Weekly Tracker. https://www.datacenterbans.com/

• The Geopolitical Economist, “AI Infrastructure Bottleneck: The Transformer Shortage Slowing Data Centers,” Jun. 2026. https://medium.com/the-geopolitical-economist/everyone-is-watching-the-ai-boom-nobody-is-watching-the-transformer-that-cant-be-built-in-time-341c523e8e81

• Inflect, “Data Center Power Shortage 2026: Why Grid Capacity Is Now the Bigger Constraint Than GPUs.” https://inflect.com/blog/data-center-power-shortage-2026-why-grid-capacity-is-now-the-bigger-constraint-than-gpus

• American Action Forum, “AI Data Center Power Surge: Shifting Trends Toward Natural Gas.” https://www.americanactionforum.org/insight/ai-data-center-power-surge-shifting-trends-toward-natural-gas/

• U.S. Department of Energy, “Fact Sheet: Ensuring Affordable Energy Access in Ohio While Powering the Future of AI,” Mar. 2026. https://www.energy.gov/articles/fact-sheet-department-energy-ensuring-affordable-energy-access-ohio-while-powering-future

• Futurum Group, “AI Capex 2026: The $690B Infrastructure Sprint,” Feb. 2026. https://futurumgroup.com/insights/ai-capex-2026-the-690b-infrastructure-sprint/

PUBLISHER’S VIEW

The Fleet We Already Built

Every conversation about closing PJM’s capacity gap starts in the wrong place. It starts with a new gas turbine that needs a transformer nobody can get for three years, or a small modular reactor that won’t produce a kilowatt-hour until the next decade, or an interconnection queue that treats a shovel-ready project like it just showed up yesterday. Nobody starts where the fastest, cheapest, already-permitted capacity actually sits: idling.

PJM’s coal fleet, as of the most recent full accounting on December 31, 2025, carries 38,366 megawatts of installed nameplate capacity. That is not a rounding error next to PJM’s own reliability shortfall. It is more than five and a half times the 6,831-megawatt gap the RTO’s 2028/2029 Base Residual Auction just failed to fill for the second consecutive cycle. The plants are permitted, interconnected, staffed, and — this is the part the “coal is dying” narrative keeps skipping — largely still standing. What they are not doing is running anywhere close to what they are capable of.

The most recent EIA figure on PJM coal utilization, drawn from 2023 generator data, put the fleet’s capacity factor at 34 percent, down from 56 percent as recently as 2013. Run the arithmetic on what that gap means in megawatt-hours, and the number should stop every FERC commissioner and every state utility regulator cold. At 38,366 megawatts of nameplate capacity running 8,760 hours a year, the fleet’s full theoretical output is about 336 million megawatt-hours annually. At a 34 percent capacity factor, actual dispatched output comes to roughly 114 million megawatt-hours. A well-maintained coal steam unit can sustain a capacity factor in the 80-to-85 percent range without heroics — the range baseload coal ran at for decades before gas got cheap. Call 85 percent a realistic, sustained ceiling, and the fleet’s achievable output is closer to 286 million megawatt-hours a year. That leaves roughly 171 million megawatt-hours sitting on the table annually — call it 3.3 million megawatt-hours a week, or an average of 19,600 megawatts of continuous generating capacity that exists, is paid for, and simply is not being asked to work.

Nineteen point six gigawatts. That number alone is larger than the entire announced data-center capacity currently under construction nationwide. It would not require a single new interconnection agreement, a single new transformer order, a single new mile of transmission right-of-way. It requires PJM’s own dispatch stack to call on plants that are already sitting there, fueled and staffed, waiting for a phone to ring.

Here is why the phone mostly does not ring, and it is worth explaining plainly because most of the public debate over this gets it backwards. PJM runs two separate markets. The capacity market pays a generator for being available — for existing, passing its performance tests, and standing ready to answer a dispatch call during the delivery year. That is what cleared at the $325-per-megawatt-day price cap in the most recent Base Residual Auction. The energy market is a different transaction entirely: it pays a generator only when it is actually dispatched, and dispatch order runs on marginal cost, cheapest megawatt-hour first. Most days of the year, a gas combined-cycle unit beats a coal steam unit on marginal cost, so gas gets called and coal sits. The coal plant still collects its capacity payment for being the insurance policy. It just does not get asked to actually do the job the insurance policy exists for, except on the handful of days a year — a January cold snap, a July heat dome — when gas prices spike or gas supply tightens and coal suddenly becomes the cheaper choice again.

That is a rational market design for an ordinary year. It stops being rational the moment the grid operator itself is telling FERC, in writing, that it is 6,831 megawatts short of its own reliability target for the second straight auction, while data centers alone are projected to help drive 32 gigawatts of new peak demand onto this same system by 2030. Ratepayers are now being asked to fund a $20 billion emergency backstop auction, at a $555-per-megawatt-day cap, to solve a shortfall that a fleet already sitting idle at 34 percent utilization could substantially close if the market simply called on it more often. That is not a hypothetical. It is 171 million megawatt-hours a year of existing, permitted, interconnected capacity that ratepayers are already paying to keep on standby and are barely using.

The honest counterargument deserves a straight answer, not a dodge. Coal’s low capacity factor is not purely regulatory timidity; a real share of it reflects gas simply being cheaper on marginal cost most days, plus real environmental compliance costs, plus the wear-and-tear economics of cycling a baseload steam unit up and down instead of running it flat. Forcing dispatch preferences onto price formation has real costs too, including higher energy prices in the months coal beats gas on merit order and gets called anyway. That is a legitimate point, and any serious policy fix has to price it honestly rather than pretend the fleet can simply be switched to 85 percent utilization for free.

But “some of the gap is legitimate economics” is not the same claim as “all fifty-one points of the gap between 34 and 85 percent capacity factor is legitimate economics,” and nobody arguing for premature retirement schedules has shown their work on that distinction. DOE’s Section 202(c) emergency orders already established the legal and operational precedent that specific coal units can be directed to remain available and dispatch economically when reliability requires it. The next logical step — and the one this publication will keep pressing FERC and PJM to answer directly in the show-cause dockets now working through the system — is whether price formation and capacity accreditation rules should be doing more of that work automatically, rewarding the fleet for the reliability it already provides on paper by actually calling on the megawatt-hours it is capable of delivering. The data centers are coming whether the grid is ready or not. The fastest capacity PJM has access to is not the one still waiting on a transformer. It is the one already sitting on the interconnection, drawing a capacity payment, and waiting to be told to run.

— The Publisher

Methodology note: Capacity-factor headroom calculated as (installed nameplate MW × 8,760 hrs) at a realistic sustained 85% capacity factor, minus actual output at the most recently published EIA capacity factor (34%, 2023 generator data — EIA has not published a more recent PJM-specific coal capacity factor as of this issue). Installed coal capacity of 38,366.4 MW per Monitoring Analytics’ 2025 State of the Market Report for PJM (as of Dec. 31, 2025). The 85% ceiling is an editorial assumption representing sustained baseload operation with normal planned maintenance and forced-outage allowance, not a PJM- or EIA-published target; actual achievable utilization would vary by unit condition, environmental permit limits, and fuel logistics, and should be verified against unit-specific EFORd and GADS data before use in any dispatch-planning or policy context.

AI ASSISTANCE DISCLOSURE: AI assistance was used in research compilation, data formatting, and drafting of this publication. All data sourced from the primary and secondary sources cited throughout; editorial judgments and strategic assessments should be reviewed and confirmed by the author before publication. Readers should verify data directly with cited sources, particularly figures drawn from secondary trade-press summaries of primary filings rather than the underlying dockets themselves.

By T.L. Headley, MBA, / President / The Hedley Company

I get asked constantly, usually by people who assume the answer will embarrass me: do you use AI to write your columns, your regulatory filings, your research papers? The answer is yes. I use it every working day — at least for the past year.

I also think most people using it are doing it badly, and I think the energy industry in particular has been slow to figure out how to use it well. So let me lay out exactly how I work with it, because the method matters more than the confession.

Start with the boundary I hold firm in my shop. AI does not have a byline. It does not get to decide what goes into a research paper, a PJM filing, or a column with my name on it. Those decisions stay mine, full stop.

I built a thirty-year career in Appalachian energy communications before large language models existed, and everything I learned in that career — verify twice (actually more), cite the primary source, never let a talking point substitute for a fact — still governs how the work gets made today. What AI — particularly Anthropic’s Claude suite — has earned, through demonstrated usefulness under tight supervision, is a role as research assistant and drafting tool. A good one, when I run it my way. It works for me, under my direction, inside rules I set and enforce, and it does not get promoted past that role no matter how capable it gets.

Here is what that looks like in practice.

Every substantial piece I produce starts with an outline I build myself, not one the AI generates on its own initiative.

If I am writing on PJM governance reform or a coal regulatory history, I know the argument before I open a chat window. I know the structure, I know the sections, I know roughly where the piece needs to land. The AI’s job is to help me fill that structure in — pulling sourcing, drafting sections against my direction, checking my numbers, stress-testing my logic — not to hand me a structure of its own. Anyone who lets a chatbot decide the shape of their argument has already surrendered the thing that made their work worth reading in the first place.

Take a recent example. When I was building out the cross-administration coal regulatory reference document my shop produced this year, I didn’t ask the model to write me a history of federal coal policy and call it done. I built the framework first — which administrations, which agencies, which rule changes mattered, what timeline the piece needed to track. Then I used the tool to pull the specific regulatory citations, cross-check effective dates, and flag where I had the sequence of events wrong in my own head before I put it on paper. That is the difference between using AI as a shortcut and using it as a second researcher who works fast and needs supervision. The framework was mine before I ever opened a chat window. It stayed mine the whole way through.

Sourcing is where I am most demanding, and where I think most people cut corners. I give explicit direction on what counts as an acceptable source and what does not. Government filings, agency data, court records, peer-reviewed research, primary trade publications — those are usable. Aggregator blogs repeating a press release, advocacy sites dressed up as news, anything I cannot trace back to an original document — those get thrown out, and I throw them out myself. I do not accept a claim because the model states it with confidence. Confidence is not a source. I have caught invented citations, misdated regulatory actions, and numbers that were close enough to right to be dangerous. That is exactly why the discipline exists in the first place. That verification stays my job, every time.

The back-and-forth is the actual work. I do not send one prompt and take what comes back. I question everything — where did this number come from, what is the underlying methodology, does this actually support the sentence you just wrote, is there a more recent filing that supersedes this one. I push back when something reads generic, when it hedges where the evidence supports a firm conclusion, when it drifts into the mushy on-the-one-hand-on-the-other-hand voice that AI defaults to and that I have no use for. My readers get direct, substantive commentary because I insist on it, draft after draft, until the piece sounds like something a person with an actual position wrote — because it is.

Then comes verification. Before anything goes out with my name on it, I re-read the whole thing several times, hunting for exactly the kind of soft, hedging construction AI tends to produce, and I go back through every factual claim against its original source. Regulatory dates, tonnage figures, statutory citations, quotes attributed to specific officials — I check them myself. I have run a shop that broke a corruption story that put county officials in federal prison. I did not get there by taking anyone’s word for anything, and I am not going to start now because the anyone in question is a language model instead of a source with an agenda.

Which brings me to another issue — AI DOES have an agenda. The material that was originally chosen to teach it was chose by people with agendas, with philosophical and political views. They often come with guardrails to prevent using them to counter their “teachers” preferred position. I am constantly on guard for AI attempts to circumvent my guidelines — and it does.

In many ways it is like Wikipedia on steroids — written by liberals to push a liberal agenda at every opportunity. That’s another reason to never let down your guard and be as responsible for your work as you were before the development of AI assistants.

And here is the part that ought to be the whole industry standard: I disclose it. Every time. When AI assisted in research or drafting, I say so. I don’t think there is anything shameful about using a tool to work faster and more accurately, provided a competent, accountable human being is still doing the thinking, setting the direction, checking the work, and standing behind the final product. What is shameful is pretending otherwise — publishing AI-drafted material as if it sprang fully formed from your own research, letting readers assume a rigor that was never applied. Disclosure is the price of using the tool honestly, and I pay it every time without exception.

There is a broader point here about who ought to be using these tools at all, and how.

A researcher with thirty years of primary-source discipline behind them can use AI to move faster without moving recklessly, because they already know what a real citation looks like and what a fabricated one looks like. Someone without that background, using the same tool the same way, will produce confident-sounding garbage and never know the difference until a critic or a regulator catches it for them. The tool widens the gap between rigorous work and lazy work rather than closing it, because it lets rigorous people move faster while it lets careless people generate more volume of the same low-quality material they were already producing. The honest reality is that it rewards discipline that already exists and punishes its absence, faster than the old tools ever did.

I would tell anyone in this business, or any business that trades in facts and argument, to build the same guardrails before they build the workflow. Decide what an acceptable source looks like before you start asking questions, and do not let the model relax that standard for you because it is faster to accept what it hands you. Keep your own outline. Keep your own conclusions. Use the tool to test them, not to generate them from scratch and hope they hold up. Question every output the way you would question a junior researcher who is eager to please and occasionally wrong with total confidence — because that is, more or less, exactly what you are working with. Verify facts against primary documents, not against the model’s own restatement of them. And when it helped, say so.

The energy debate in this country is drowning in bad information already — inflated renewable capacity claims, cherry-picked emissions studies, regulatory filings that get summarized by people who never read past the executive summary. AI can make that problem dramatically worse, at a speed and scale we have not seen before, if the people using it do not hold themselves to a higher standard than the tool holds itself to. Or it can make good, careful, well-sourced work faster to produce, which matters a great deal when you are a small shop competing against organizations with ten times your staff and budget.

I use it because it makes me faster. It does not make me less careful. If anything it has made me more careful, because I now have a second set of eyes — an untrustworthy one, in the sense that it needs constant checking, but a useful one — asking me whether my numbers hold up and whether my argument has a hole in it before a reader finds one first. The tool does not get credit for the work. It gets used, the way any other piece of equipment in this business gets used, and then it gets disclosed, the way any responsible use of it should be.

That is the whole method. Build the outline yourself. Set the sourcing rules yourself and enforce them. Argue with the machine until the work is right. Verify every fact against the original document, not the model’s paraphrase of it. And tell your readers when it helped. Anyone selling you a shortcut past those five things is selling you a way to get caught being wrong, in public, on the record — and in this business, that is the one mistake you do not get to make twice.

Oh, and by the way… ALL AI tools hallucinate, so I will reiterate, ALWAYS check, and double-check its work. If you don’t know enough about the subject to do so, don’t try to fake it. You WILL make mistakes and probably some seriously bad ones. And try as we might — try as I might — sometimes they get through, but then again mistakes happen regardless of the means of writing or researching, that’s why the ultimate responsibility is shared not just by the writer but also the reader.

WHAT’S INSIDE

Fast Facts

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By T.L. Headley, MBA, / President / The Hedley Company

The “Energy and Environment” reporter has become a fixture of American newsrooms, a single byline assigned to cover coal, natural gas, nuclear power, the electric grid, climate policy, endangered species litigation, and the Environmental Protection Agency, all under one job title. Editors treat the pairing as a matter of convenience. It sounds tidy on an org chart. Two subjects, one beat, one salary line. The convenience is an illusion. Underneath the tidy job title sits a structural conflict of interest that no amount of professional discipline can fully overcome, one that has been quietly corroding the credibility of energy journalism for a generation.

Matthew 6:24 puts the underlying problem better than any journalism school ethics course ever has: “No man can serve two masters: for either he will hate the one, and love the other; or else he will hold to the one, and despise the other.” The verse was written about money and God, and newsroom assignments never crossed the mind of the man who wrote it. The mechanism it describes is universal all the same, and it applies with brutal precision to anyone whose job requires covering both the production of energy and the movement dedicated to restricting it.

Energy coverage, done honestly, requires an editorial disposition toward reliability, affordability, and the physical realities of keeping the lights on. It requires taking seriously the people who work the mines, run the pipelines, staff the power plants, and pay the electric bills. It requires treating baseload generation, grid stability, and industrial employment as legitimate public interests worth defending in print, on equal footing with any renewable-future ambition an editor happens to favor.

Environmental coverage, as it is practiced today in most American newsrooms, requires something close to the opposite disposition. It requires sympathy toward the regulatory and activist apparatus that treats fossil fuel production as a problem to be solved rather than an industry to be understood. It requires framing every emissions figure as a crisis, every permit as a fight, and every coal or gas project as something that must clear a moral burden of proof that wind and solar projects are rarely asked to clear. The environmental beat, as currently constituted in the trade, has largely become an advocacy beat wearing a press badge.

Ask any assigning editor to be honest about which master gets served when the two collide, and the answer is not close. The reporter who covers “energy and environment” is embedded, professionally and socially, in a media ecosystem built by outlets, foundations, and journalism fellowships that treat decarbonization as the correct outcome and treat energy producers as the subjects of investigation rather than sources of expertise. The Society of Environmental Journalists, the Covering Climate Now consortium, the various foundation-funded climate desks that now supply wire copy to hundreads of local papers — these institutions exist to accelerate environmental advocacy at the expense of energy coverage, dressed up as balance. They have succeeded in training an entire generation of reporters to see the “energy” half of their beat as something to be managed, mitigated, and eventually phased out rather than covered on its own terms.

This is where the two-masters problem becomes structural rather than personal. A reporter of genuine integrity can try to split the difference, quoting a coal association spokesman in one paragraph and a Sierra Club attorney in the next, and calling the result balance. Balance in sourcing and balance in framing are different animals entirely, and framing is where the real editorial decisions get made. Which side gets the benefit of the doubt when a study is disputed? Which side’s numbers get printed as fact and which side’s numbers get printed as “claims”? Which industry gets described as providing jobs and tax revenue to struggling counties, and which industry gets described as providing jobs and tax revenue only in the reporter’s own private notes, never in the finished story? A reporter serving the environmental master, even unconsciously, will resolve these judgment calls one way, over and over, story after story, until the pattern is unmistakable to anyone who reads the paper for a living rather than skims it for headlines.

The coal industry in Appalachia has lived with the consequences of this arrangement for three decades. Coverage of mine closures routinely treats the closures as inevitable, even virtuous, without applying the same scrutiny to the regulatory decisions and subsidized competition that helped force them. Coverage of the communities left behind treats economic devastation as a human interest sidebar rather than the central policy failure it is. Meanwhile, a wind or solar project backed by federal tax credits and state mandates gets covered as an unambiguous community win, with the land-use conflicts, grid reliability costs, and Chinese supply chain dependencies relegated to a paragraph near the bottom, if they appear at all. Individual reporters rarely intend it. The asymmetry is the predictable output of a beat structure that asks one person to represent two masters with fundamentally opposed interests, and then expects the public to trust the result as neutral.

The fix is not complicated, even if it is unwelcome in most newsrooms. Energy coverage and environmental coverage should be separated into distinct beats, staffed by reporters who are not required to internalize both value systems simultaneously. An energy reporter should be free to treat reliability, affordability, and industrial employment as core public interests without constantly weighing them against a climate framework imposed from the editor’s desk. An environmental reporter should be free to cover regulatory and activist concerns without being asked to also serve as the paper’s de facto energy correspondent, expected to render fair verdicts on drilling permits and coal leases in the same afternoon. No structural fix eliminates bias entirely, and separation would be no exception. What it would accomplish is more modest and still worth having: it would stop asking a single human being to hold two irreconcilable loyalties inside one professional identity, and it would let readers judge each reporter’s coverage against a coherent standard rather than a blended one that serves neither subject well.

Editors will object that most newsrooms cannot afford two beats where they currently fund one, and the objection has some force in an industry gutted by two decades of layoffs. But a budget constraint is a business problem, not a journalistic principle, and dressing it up as one only compounds the dishonesty. A paper that genuinely cannot staff separate energy and environmental beats has other options short of pretending the conflict away: it can rotate the assignment on a fixed schedule so no single reporter accumulates years of institutional sympathy toward one side, it can require disclosure of foundation funding tied to climate coverage the way it would require disclosure of any other conflicted revenue source, or it can simply drop the “environment” half of the title and call the position what it functions as in practice, an energy beat with an activist lens. Honesty about the limitation costs nothing. Pretending the limitation does not exist costs the paper its credibility with half its readership.

There is also a simpler, more constitutional point buried in this argument, one that conservatives should not be shy about making. A free press exists to inform citizens. Managing public opinion toward a predetermined policy outcome is the job of an advocacy shop, and the two functions have no business sharing a byline. The “energy and environment” beat, as currently practiced, functions less like journalism and more like an editorial court where fossil fuels are perpetually the defendant and climate advocacy is perpetually the plaintiff, with the reporter serving simultaneously as bailiff and character witness for both sides. That arrangement has a defensible name, and the name is advocacy work. Newsrooms that keep presenting it as neutral reporting are asking the public to accept a fiction that most working journalists, if they were honest with themselves, would admit they cannot actually deliver.

West Virginia families who depend on coal severance taxes, on mining and pipeline paychecks, and on affordable, reliable electricity deserve coverage from reporters who are not structurally required to hold their industry’s future hostage to a competing editorial mandate. The two-masters problem shows up here in very concrete terms, every time a mine layoff gets four paragraphs and a solar ribbon-cutting gets four hundred words and a photo spread. Scripture identified the mechanism two thousand years ago, and it has lost none of its accuracy in the intervening centuries. American journalism would do well to take the warning seriously and stop pretending that any reporter, however skilled or however well-intentioned, can love the one master and despise the other while filing under a single, conveniently combined beat. Until newsrooms make that separation, readers in coal country are entitled to treat every “energy and environment” byline with the same skepticism they would apply to a referee who also owns a stake in one of the two teams on the field.

CHARLESTON, W.Va. — Tuesday, August 25, 2026
Vol. 1, No. 6 | Covering the Previous 24 Hours in American Energy

First Read

Treasury Secretary Scott Bessent put a name on it Monday: “Operation Economic Outcast.” The new sanctions package targets Iran’s shipping, gold, digital-asset, aviation, and technology sectors, adds a naval blockade of Iranian ports, and sanctions roughly 60 entities and vessels tied to nuclear procurement, cyber operations, and oil smuggling. Bessent said there’s now a “cure period” for nations still trading with Tehran to cut ties — and made clear China isn’t exempt. Oil actually fell on the news: WTI dropped about 2.5% to $84.89 and Brent slipped below $93, as markets weighed whether total financial isolation might succeed where military pressure hasn’t, and Iran’s Revolutionary Guard immediately pushed back, insisting Tehran has ways around the squeeze. Today’s commentary digs into why that uncertainty — nobody actually knows if this works — matters more for West Virginia’s own energy planning than the headline itself.

Washington had a second big moment Monday that had nothing to do with Iran: Secretary of State Marco Rubio, flanked by Bessent, Interior Secretary Doug Burgum, and Energy Secretary Chris Wright, unveiled FORGE, a new critical minerals trade-and-investment framework, at a ministerial gathering of 54 nations. It’s the kind of long-horizon industrial policy that rarely leads a newscast but matters enormously to anyone tracking where America’s next generation of energy and defense infrastructure gets built — squarely in Seneca Center territory.

Coal picked up real tailwinds and real headwinds on the same day. Thermal coal prices climbed above $131 a ton on firm Asian demand, the highest level in weeks. But closer to home, Virginia regulators partly denied AEP cost recovery for environmental compliance upgrades at the Amos and Mountaineer plants — a cross-state cost fight that complicates AEP’s plan to run those units through 2040. Closer still, the Seneca Center filed comments this week with FERC in the ongoing PJM restructuring docket, Case No. AD26-7-000, pressing the Commission on whether the RTO is running its existing paid-off coal capacity before buying replacement power at auction.

Nuclear had a mixed morning of its own: NuScale shares slid nearly 4% after a dismal revenue quarter, while two much smaller advanced-reactor developers — Apollo Atomics and Deployable Energy — each landed fresh funding and a state partnership. And in California, a startup wants to moor a floating 10-megawatt reactor at the Port of Long Beach, the first real test of the state’s decades-old restrictions on new nuclear development.

Domestic Energy News

Axios / NBC News — Aug. 24, 2026

Treasury Secretary Scott Bessent announced a new sanctions campaign, dubbed “Operation Economic Outcast,” targeting Iran’s shipping, digital-asset, gold, aviation, and technology sectors, alongside a naval blockade of Iranian ports. The Treasury Department sanctioned roughly 60 entities, individuals, and vessels tied to nuclear and missile procurement, cyber operations, and oil smuggling, and Bessent said a “cure period” now applies to any nation still trading with Tehran — with China explicitly not exempted.

Read more: https://www.axios.com/2026/08/24/bessent-dday-iran-secondary-sanctions

2. Oil Falls to $84.89 as Markets Digest Sanctions Details; Iran’s Revolutionary Guard Vows to Route Around Them

CNBC — Aug. 24, 2026

WTI crude fell about 2.5% to $84.89 a barrel and Brent dropped below $93 on Monday as markets weighed whether Bessent’s economic-isolation campaign might succeed where military pressure hasn’t. Iran’s Revolutionary Guard Corps pushed back through state media, saying Tehran has ways to “counter the adverse effects of the enemy’s war” and can still establish economic relations with other countries.

Read more: https://www.cnbc.com/2026/08/24/oil-price-today-wti-brent-us-sanctions-iran.html

3. U.S. Unveils FORGE Critical Minerals Framework at Ministerial With 54 Nations

Metal Tech News / U.S. State Department — Aug. 24, 2026

The Trump administration unveiled FORGE, a new critical minerals trade-and-investment framework, at the 2026 Critical Minerals Ministerial in Washington. Secretary of State Marco Rubio, joined by Treasury Secretary Bessent, Interior Secretary Doug Burgum, and Energy Secretary Chris Wright, hosted delegates from 54 nations and the European Union to sign bilateral frameworks and announce new financing aimed at diversifying supply chains away from China.

Read more: https://www.metaltechnews.com/story/2026/08/25/critical-minerals-alliances-2026/forgeing-a-critical-minerals-ecosystem/2905.html

4. Thermal Coal Prices Climb Above $131/Ton on Firm Asian Demand

Trading Economics — Aug. 24, 2026

Thermal coal prices rose above $131 per ton in late August, their highest level since early August, amid firm Asian demand and ongoing supply risk. Japan’s power prices have climbed to their highest level since 2023 as a heat wave drives cooling demand, adding further support to thermal generation and coal demand.

Read more: https://tradingeconomics.com/commodity/coal

5. Virginia Regulators Partly Deny AEP Cost Recovery for Amos, Mountaineer Coal Plant Environmental Upgrades

POWER Magazine — Aug. 23, 2026

The Virginia State Corporation Commission on August 23 partly denied cost recovery for expenses American Electric Power’s West Virginia units need to comply with the federal Steam Electric Effluent Limitations Guidelines rule, complicating AEP’s plans to operate the 2.9-GW John Amos and 1.3-GW Mountaineer coal plants through 2040. The ruling creates a cross-state cost-allocation dispute between Virginia and West Virginia over who pays for compliance upgrades at plants serving both states.

Read more: https://www.powermag.com/tag/west-virginia/

6. NuScale Power Shares Slide Nearly 4% as Analysts Cut Price Targets After Q2 Revenue Miss

Market data via Timothy Sykes — Aug. 24, 2026

NuScale Power shares fell about 3.9% after the company reported second-quarter revenue of just $75,000, down from $8 million a year earlier, even as management touted NRC design certification progress. RBC Capital cut its price target from $14 to $10, calling NuScale’s near-term profile “speculative” as key projects remain years from generating meaningful cash flow.

Read more: https://www.timothysykes.com/news/nuscale-power-corporation-smr-news-2026_08_24/

7. Floating 10-Megawatt Nuclear Reactor Proposed for Port of Long Beach, California

TechRadar Pro — Aug. 22, 2026

Startup Bluecore Energy has leased space at the Port of Long Beach to develop a floating, barge-mounted 10-megawatt small modular reactor intended to power port operations and ships, with the design scalable through pairing multiple units. The proposal marks a potential return of nuclear power development in California after nearly five decades of state restrictions.

Read more: https://nuclear-news.net/2026/08/25/6-b1-floating-10-mw-nuclear-reactor-proposed-for-california-barge-mounted-smr-aims-to-power-15000-homes/

8. The Seneca Center Files FERC Comments in PJM Restructuring Docket, Citing $641.7 Million WV Net Energy Cost Under-Recovery

FERC Docket No. AD26-7-000 — Aug. 21, 2026

The Seneca Center for Energy and Critical Minerals Policy filed comments with FERC in its ongoing PJM governance and resource-adequacy docket, pressing the Commission to examine whether PJM is dispatching existing paid-off coal capacity before buying replacement power at auction. The filing cites West Virginia’s own recent record of a $641.7 million net energy cost under-recovery against $321.1 million in allowed recovery, and fourteen rate increases between 2017 and 2023.

Read more: https://americascoal.substack.com/p/seneca-files-comments-with-ferc-in

9. Apollo Atomics Secures $31 Million for Factory-Built Nuclear Reactors

iGrow Renewable Energy News — Aug. 21, 2026

Apollo Atomics announced it has secured $31 million in funding to advance development of factory-built nuclear reactors, part of a broader wave of private capital moving into modular and advanced reactor manufacturing as developers race to shorten construction timelines.

Read more: https://igrownews.com/renewable-energy-news/

10. Deployable Energy Signs MOU With Utah Office of Energy Development for Factory-Built Reactors

iGrow Renewable Energy News — Aug. 24, 2026

Deployable Energy signed a memorandum of understanding with the Utah Office of Energy Development to advance siting and permitting groundwork for factory-built nuclear reactors in the state, adding Utah to the growing list of states courting advanced reactor manufacturers ahead of commercial deployment later this decade.

Read more: https://igrownews.com/renewable-energy-news/

The Day Ahead

• Iran-Oman Hormuz Talks: diplomatic talks between Iran and Oman over managing Strait of Hormuz transit continue today — watch for any sign of de-escalation running alongside the sanctions campaign.

• Sanctions “Cure Period” Response: watch for which nations, if any, publicly signal they’ll comply with Bessent’s ultimatum to cut Iranian trade ties in the coming days.

• WV PSC Case No. 26-0633-E-GI: the HB 2014 rulemaking implementing Proposed Rule 150 CSR 41 remains pending before the Commission following the reply comment period; a scheduling order or further Commission action could issue at any time.

• EIA Weekly Petroleum Status Report: next release Wednesday morning — first look at the week’s crude and distillate draws following this week’s price action.

Commentary

Operation Economic Outcast and the Case for Planning West Virginia’s Grid Around Uncertainty, Not a Bet

Treasury Secretary Scott Bessent gave his new Iran sanctions campaign a name Monday: “Operation Economic Outcast.” Whether it works is genuinely uncertain, and that uncertainty is exactly why American energy policy shouldn’t be built around betting on the answer.

Consider what “working” would actually mean here. If the campaign succeeds the way Bessent describes — total financial isolation, the regime cut off from shipping, gold, and digital-asset revenue until it either negotiates seriously or collapses outright — the most likely outcome for energy markets is a reopened Strait of Hormuz, restored Iranian production coming back online in some negotiated form, and downward pressure on the same crude prices that have kept Brent hovering near $90 for months. That’s the optimistic case, and it’s a real possibility; markets already took oil down more than 2% on Monday on exactly that speculation. If the campaign fails — if Iran finds workarounds the way sanctioned regimes usually do, routes oil through the same shadow fleets and ship-to-ship transfers that have kept some exports moving for months already — then the Hormuz standoff grinds on indefinitely, prices stay elevated, and nothing about the fundamental supply picture changes.

Those two outcomes point in opposite directions for crude prices, and nobody — not Bessent, not the intelligence community, not the oil majors modeling their capital budgets around this — actually knows which one the country is going to get. That’s not a knock on the administration’s strategy. Economic warfare against a determined adversary state is inherently uncertain; if sanctions worked with mechanical predictability, the Iranian regime wouldn’t have survived four decades of them already. That uncertainty is baked into the tool itself, regardless of how skillfully it’s being wielded this time.

What that uncertainty should tell anyone setting West Virginia energy policy is that betting on either outcome is a mistake. A resource plan built on the assumption that sanctions succeed and prices retreat toward $70 gets caught flat-footed if Tehran routes around the pressure and the standoff drags into 2027. A resource plan built on the assumption that prices stay elevated indefinitely gets caught overpaying for capacity if the diplomatic track this administration keeps insisting is still open actually produces a deal. Either bet is a bet on Iranian regime behavior, which is precisely the kind of variable no serious utility planner should be underwriting a decade of capital investment against.

This is the strongest practical argument for the capacity-factor approach now pending before the Public Service Commission, and it has nothing to do with sentiment about coal’s place in this state’s history. Dispatchable, fuel-secure capacity sitting inside West Virginia’s borders is valuable precisely because its economics don’t hinge on whether Operation Economic Outcast succeeds. It doesn’t get cheaper if Iran cuts a deal, and it doesn’t get more expensive if the standoff continues. That stability is the entire point. A rate design that lets utilities idle that capacity and lean on PJM’s wholesale market instead is a rate design that imports Iranian regime uncertainty directly into West Virginia electric bills, whether ratepayers know it or not.

Every West Virginia family paying $4 a gallon at the pump should hope Bessent’s campaign works exactly as designed. The point here is narrower: this state’s electricity resource planning shouldn’t be built as though the outcome were knowable in advance. The Commission doesn’t need to guess whether Tehran capitulates. It needs a capacity framework that performs the same either way, and it already has the tool sitting in front of it.

By T.L. Headley, MBA,

President

The Hedley Company

AI DISCLOSURE: AI assistance used in research/drafting under author’s direction; all judgments author’s own.

THE BASELOAD | Published by The Hedley Company | 169 Raceview Drive, Ona, WV 25545 | tlheadley@hedleycompany.com | Ph. 681.356.1776

Vol. 2, No. 33 | Week Ending August 15, 2026 | Data: Week 33 (Aug 15, 2026)

FAST FACTS

Sources: EIA Weekly Coal Production Report; EIA Coal Markets Report; AISI AIS-7; AAR Weekly Rail Traffic Report; STB Docket FD 36873. EIA data carries an 8–10 day reporting lag; figures reflect the week ending Aug. 15, 2026 (Week 33), released Aug. 21, 2026.

EXECUTIVE SUMMARY

U.S. coal production rose to 10,307 KST in the week ending August 15 (Week 33), up 3.9 percent from the prior week but still 5.5 percent below the corresponding week of 2025. Year-to-date production of 319.8 million short tons trails 2025’s pace by 2.7 percent, with the decline concentrated in the Interior Basin (-4.9 percent YTD) and Appalachia (-4.2 percent YTD) while the Western Basin holds closer to flat (-1.1 percent YTD) on Wyoming’s continued strength. Wyoming production is up 1.7 percent YTD even as most other producing states run behind last year’s pace, underscoring the degree to which the national total is being carried by the Powder River Basin’s cost advantage rather than broad-based demand recovery.

West Virginia production rose 5.6 percent week-over-week to 1,540 KST but remains 3.3 percent below the same week last year and 6.4 percent behind on a year-to-date basis. The state’s two basins continue to diverge: Northern Appalachia held its ground at 861 KST, down only 2.6 percent YTD, while Central Appalachia’s 679 KST reading is off 10.8 percent YTD. That gap is a coking-coal story as much as a thermal one — Central Appalachia’s export-linked met coal tonnage is more exposed to the Australian benchmark, which firmed 5.4 percent week-over-week to $236.00/MT but remains a level Appalachian producers must compete against on freight-adjusted terms.

Dispatch economics by basin remain unchanged in direction if not magnitude. On an energy-equivalent basis, CAPP coal at $3.24/MMBtu and NAPP at $2.70/MMBtu both continue to price above Henry Hub’s $2.94/MMBtu, a gas advantage of $0.30 and a coal disadvantage of $0.24 respectively when NAPP is measured against the wider spread — meaning Central Appalachian coal faces a real dispatch penalty against gas at current prices while Northern Appalachia sits closer to competitive. Illinois Basin coal at $2.35/MMBtu undercuts gas by $0.59, and Powder River Basin coal at $0.83/MMBtu undercuts gas by $2.11 — the PRB’s structural advantage over gas-fired generation remains enormous and is the single largest reason Western production is outperforming the rest of the country.

Steel output data continue to support a stable, if unspectacular, met coal demand signal. AISI-reported raw steel production came in at 1,833 kt for the week, up 3.3 percent year-over-year, with capacity utilization at 79.4 percent, 1.4 points above the same week in 2025. Midwest and Northeast districts posted the sharpest year-over-year gains (34.2 percent and 18.6 percent respectively), a mini-mill and specialty-steel signal more than a blast-furnace one, which matters for how Appalachian met coal producers should read this data: it supports scrap-adjacent and EAF-linked steel activity more than it signals a broad manufacturing rebound that would pull harder on coking coal.

Rail performance was mixed but generally constructive. CSX originated 10,822 coal carloads for the week against a combined Northern and Central Appalachian loading plan of 9,100, translating to an actual of 8,803 — a shortfall of 297 cars, or 3.3 percent under plan, driven entirely by Northern Appalachia’s 296-car miss against a 4,027-car plan. Norfolk Southern originated 11,555 coal carloads, its highest of the six-week window, but its Appalachian plan-versus-actual gap was proportionally worse: 1,110 planned against 780 actual, a 330-car, 29.7 percent shortfall. NS’s shortfall has now persisted at a double-digit percentage for six straight weeks, which crosses from noise into pattern; shippers who depend on NS-originated tonnage should be building a documented record now in case an STB service complaint becomes warranted. West Virginia river barge loadings rose to 319 for the week, the strongest reading of the six-week window and consistent with a stable, if unspectacular, secondary transportation channel.

The week’s dominant regulatory and structural story is the Surface Transportation Board’s August 18 decision lifting the abeyance on the Union Pacific-Norfolk Southern merger docket (FD 36873) and adopting a procedural schedule that pushes a final ruling into the second quarter of 2027 — later than the applicants had hoped for, and a signal that the Board intends a full record rather than an expedited resolution. Applicants must resubmit certain data by August 28. On the generation side, PJM’s 2028/2029 Base Residual Auction cleared at the $325/MW-day price cap for a second consecutive cycle, 6,831 MW short of the reliability requirement, with a special backstop procurement now planned for September — a reliability gap that keeps the policy case for coal capacity retention, including continued DOE Section 202(c) emergency orders, squarely on the table. On the regulatory front, EPA’s proposed amendments to the coal combustion residuals rule remain in comment, with the Alabama CCR permit program proposal open through September 14 and a general permitting notice open through October 13; MSHA’s silica exposure rule remains in legal limbo after an August 10 Eighth Circuit order granting the agency another two months to reconsider it. Internationally, Indonesia’s export-control tightening and softer Chinese and Indian offtake are producing a more fragile foundation under the recent price recovery than the headline Newcastle number suggests, a dynamic that bears watching for its knock-on effect on U.S. export competitiveness heading into the fourth quarter.

SECTION 1 | U.S. COAL PRODUCTION

Source: U.S. Energy Information Administration, Weekly Coal Production Report (DOE/EIA-0218); WVCA Weekly Report (Jason Bostic). Data Week 33, week ending Aug. 15, 2026, released Aug. 21, 2026. EIA data runs 8–10 days behind the calendar week.

KST = thousand short tons. YTD figures are cumulative through the week ending Aug. 15 of each year. Black rows = national totals; dark gray = regional subtotals; dark green = West Virginia totals.

Production Analysis

National production of 10,307 KST in Week 33 was up 3.9 percent from Week 32 but 5.5 percent below the corresponding week of 2025, and the year-to-date deficit of 2.7 percent has held essentially steady for the past month rather than narrowing. The national total remains structurally propped up by Wyoming, whose 4,354 KST reading is not only the largest of any state by a wide margin but one of the few showing a positive year-to-date comparison (+1.7 percent) against 2025. Strip Wyoming out and the underlying U.S. trend is meaningfully worse than the headline -2.7 percent YTD figure suggests.

The largest negative contributors on a year-to-date basis are Maryland (-23.6 percent), Utah (-21.3 percent), Montana (-13.6 percent), and West Virginia CAPP (-10.8 percent) — a mix of small-tonnage states with concentrated buyer exposure and one of the nation’s two largest met-coal-producing regions. The largest positive contributors are Alabama (+17.4 percent YTD) and New Mexico (+13.5 percent YTD), both benefiting from specific plant and export commitments rather than a broad regional recovery. Illinois Basin production continues to run behind (-9.3 percent YTD), consistent with the sustained softness in Midwest utility coal burn this cycle.

West Virginia’s internal divergence between NAPP and CAPP is the state’s central storyline this year. NAPP’s -2.6 percent YTD reading reflects a basin still serving contracted utility tonnage on relatively stable terms. CAPP’s -10.8 percent YTD reading is a function of softer met coal demand and pricing pressure from Australian HCC, which despite this week’s 5.4 percent rally to $236.00/MT remains well below levels that would meaningfully re-incentivize Central Appalachian met production growth. Producers evaluating capital allocation between the two basins should weight this divergence heavily; it is not a single-week anomaly but a full-year pattern.

Interior Basin output (-4.9 percent YTD) continues to lag the national average, driven by Illinois and Indiana softness that has shown no sign of stabilizing across the six-week window in this report. Western Basin production (-1.1 percent YTD) is essentially flat and remains the strongest-performing region, a direct function of the Powder River Basin’s dominant cost position against natural gas detailed in Section 2. Railcar loadings of 60,219 for the week were up 3.9 percent from the prior week and down 1.9 percent YTD — tracking the production trend closely and offering no independent signal of transportation-side constraint on the production numbers themselves.

SECTION 2 | COAL & NATURAL GAS PRICES

Source: U.S. Energy Information Administration, Coal Markets Report and Natural Gas Weekly Update. Data Week 33, week ending Aug. 15, 2026.

ARA = thermal coal delivered Northwest Europe (Amsterdam/Rotterdam/Antwerp). Newcastle = Asia-Pacific thermal benchmark. AUX Met Coal = Australian Premium Hard Coking Coal. Source: EIA, publicly available commodity trading data.

Price Commentary

CAPP held flat at $81.00/ton for a second straight week, a price that on an energy-equivalent basis ($3.24/MMBtu) sits $0.30 above Henry Hub — a real, persistent dispatch penalty for CAPP coal against gas-fired generation at current gas prices. NAPP was similarly flat at $70.25/ton ($2.70/MMBtu), narrowly disadvantaged against gas by $0.24/MMBtu after Henry Hub’s 4.3 percent weekly rise to $2.94. Both Appalachian grades are more exposed to gas-price swings than western coal is, because their $/MMBtu premium over PRB and ILB leaves far less cushion before a utility with fuel-switching capability shifts dispatch order.

ILB at $55.50/ton ($2.35/MMBtu) and PRB at $14.55/ton ($0.83/MMBtu) both continue to price well under Henry Hub, by $0.59 and $2.11 respectively. The PRB’s advantage is not a marginal one — it is the difference between coal remaining the marginal generation source in the SPP and MISO footprints versus being priced out entirely, and it explains why Western Basin production has held essentially flat for the year while every other major coal-producing region has declined.

These are spot indicators, not clearing prices for the term-contracted tonnage that moves most utility volume; producers and buyers negotiating term should treat this table as a directional signal rather than a transaction benchmark. International benchmarks moved more than domestic ones this week. AUX Met Coal jumped 5.4 percent to $236.00/MT, the sharpest single-week move in this report, while remaining 22.6 percent above year-ago levels — a price level that still sits meaningfully below the mid-$240s reached earlier this summer. Newcastle thermal was essentially flat (-0.02 percent) at $129.30/MT but up 16.5 percent year-over-year, and ARA firmed modestly to $122.25/MT, up 22.0 percent year-over-year. The met coal rally is the more important signal for Appalachian producers: if it holds, it strengthens the export-netback case for CAPP tonnage that domestic dispatch economics alone do not support.

SECTION 3 | ELECTRIC GRID, DEMAND & COAL’S ROLE

Source: Edison Electric Institute, Weekly Electric Output Report; EIA Short-Term Energy Outlook (August 2026); EIA Hourly Electric Grid Monitor. Data Week 33, week ending Aug. 15, 2026.

Grid Analysis

Total U.S. electrical output rose 2.4 percent year-over-year for the week, with the Southeast (+8.3 percent) and South Central (+5.9 percent) regions posting the largest gains — both regions with substantial coal and gas capacity and both experiencing the kind of summer peak demand growth that data center load additions are increasingly driving. Coal Regions Only output, which excludes New England and the Pacific, was up a more modest 1.3 percent year-over-year, suggesting the strongest demand growth this week occurred outside the regions where coal still carries meaningful generation share — a pattern worth watching, since it does not automatically translate into higher coal dispatch even as it tightens the broader supply-demand balance.

PJM’s 2028/2029 Base Residual Auction result is the dominant reliability story of the summer: a second consecutive clearing at the $325/MW-day price cap, with the entire RTO falling 6,831 MW short of its reliability requirement for the second auction running. PJM has stated it will seek FERC approval for a special backstop procurement in September to address the near-term shortfall. This is not a one-time event — it is the clearest market signal available that PJM’s capacity base has not kept pace with load growth, driven overwhelmingly by data centers, and it is the direct economic backdrop against which DOE’s continued use of Section 202(c) emergency authority to keep coal units online should be evaluated. Whatever one’s view of the statute’s proper scope, the underlying resource-adequacy numbers PJM itself is publishing support the conclusion that premature retirement of dispatchable coal capacity in this footprint would have made this month’s shortfall worse, not better.

Coal’s role by RTO remains fundamentally a reliability and capacity-value proposition rather than an energy-market one in most footprints. In PJM, coal cleared 22 percent of the resource mix in the most recent Base Residual Auction — a real, priced commitment to be available, not a marginal or intermittent contribution. In SPP, coal remains the largest single dispatchable resource in the footprint. In ERCOT, by contrast, coal has been reduced to a genuinely marginal role, and further retirements there proceed largely without the kind of DOE intervention seen in PJM, MISO, and the Midwest — worth noting for readers comparing state and regional coal futures. Intermittent wind and solar additions do not substitute one-for-one for coal or gas capacity value in any of these footprints; PJM’s own capacity accreditation rules increasingly reflect that reality, and the analysis in this report treats them accordingly.

SECTION 4 | U.S. STEEL PRODUCTION & MET COAL DEMAND

Source: American Iron & Steel Institute, Weekly Raw Steel Production Report AIS-7. Data Week 33, week ending Aug. 15, 2026.

Steel Analysis

Weekly raw steel output of 1,833 kt was up 3.3 percent year-over-year, and year-to-date production of 59.16 million net tons is running 5.6 percent ahead of 2025’s pace with capacity utilization up 2.6 points to 79.0 percent. That is a genuinely constructive read for met coal demand, but the district-level detail matters more than the national total. Midwest output rose 34.2 percent year-over-year and Northeast rose 18.6 percent — both readings well in excess of what blast-furnace-driven, ore-and-coke steelmaking would produce on its own, and consistent instead with electric-arc-furnace and specialty-steel capacity additions that consume little to no metallurgical coal. Great Lakes, the district most directly tied to integrated blast-furnace production and therefore to Appalachian coking coal purchasing, fell 13.5 percent year-over-year — the only district posting a double-digit decline.

That divergence should temper enthusiasm about what the headline steel numbers imply for met coal. The demand signal from this week’s data is stronger for scrap and EAF-linked steel activity than for the integrated, coke-consuming mills that are Appalachian met coal’s primary domestic customer base. Export markets remain the more important variable for CAPP met coal producers in the near term, and this week’s 5.4 percent rally in Australian Premium HCC to $236.00/MT is the more relevant price signal for capital and production planning than the domestic steel utilization figure, encouraging as that figure is in the aggregate.

SECTION 5 | EMPLOYMENT & ECONOMIC FOOTPRINT

Source: EIA Annual Coal Report (2024, most recent); BLS Current Employment Statistics (Coal Mining, NAICS 2121); BLS regional multiplier methodology. 3.5× is the nationally applied BLS midpoint; state-level, community-dependent multipliers documented in university IMPLAN/REMI studies run as high as 6.0×.

Employment Analysis

Every mine closure in the coalfields is a payroll number and a community number at the same time, and the arithmetic behind the 3.5x multiplier is not abstract. A 300-worker mine closure does not remove 300 jobs from a county economy — applying the national multiplier, it removes roughly 1,050 jobs when direct payroll, supplier contracts, and induced local spending are accounted for. That includes the equipment dealer whose service contract disappears, the diesel supplier who loses a fuel account, the diner near the portal that loses its lunch trade, and the county school system that loses assessed property tax value on top of income tax base. None of that shows up in a single-mine MSHA closure notice, but all of it shows up in a county budget within two years.

The divergence between the BLS-reported direct employment figure (~41,000) and the MSHA-reported figure (54,000–63,000) is not a rounding difference — it reflects two different scopes of who counts as a coal mining worker, and readers modeling county-level or state-level impact should use the MSHA figure, which more completely captures contractor and support employment on active mine sites. Holding to the standard applied throughout this publication, both figures are disclosed rather than the more flattering one selected.

Dynamic Weekly Payroll Methodology

Applied to this week’s national production of 10,307 KST: 10,307,000 short tons ÷ 5.22 st/employee-hr (2024 ACR baseline) = 1,974,521 implied employee-hours. Divided by 40 hours = 49,363 FTE-equivalent. At an inflation-adjusted average annual wage of $102,000 ($1,961.54/week), that implies direct weekly payroll of approximately $96,827,476. Applying the BLS 3.5× multiplier yields an implied economy-wide weekly impact of approximately $338,896,165.

This figure is a production-throughput model, not a headcount — it estimates the labor and economic activity implied by a given week’s tonnage at national average productivity, and will run higher than the static direct-employment figure above in weeks of strong production and lower in weeks of weak production. It should be read as a directional weekly indicator of production-linked economic activity, not as a claim about actual employment levels, which move far more slowly than weekly tonnage.

SECTION 6 | RAIL & BARGE TRANSPORTATION

Source: Association of American Railroads, Weekly Railroad Traffic Report; STB Form EP-724 (CSX, Norfolk Southern); WVCA Weekly Report (barge data). Data Week 33, week ending Aug. 15, 2026.

Rail Performance Analysis

National coal carloads of 60,219 for the week were down 5.7 percent year-over-year and down 1.9 percent YTD, tracking closely with the broader production decline rather than signaling any independent rail-side constraint. Total AAR traffic, by contrast, was up 2.4 percent year-over-year and 3.3 percent YTD — coal continues to be the one major rail commodity category moving against the grain of an otherwise growing freight base.

CSX’s performance against its Appalachian coal loading plan was mixed but directionally sound: 8,803 actual against a 9,100 plan for the week, a 3.3 percent shortfall driven almost entirely by Northern Appalachia (3,731 actual against 4,027 planned, an 7.3 percent miss), while Central Appalachia came in essentially on plan (5,072 actual against 5,073 planned). CSX’s unit train speed of 20.9 mph and near-zero holding-time figures across the six-week window indicate no meaningful network congestion; this looks like a demand-planning gap on the Northern Appalachian lane rather than a service failure.

Norfolk Southern’s picture is less reassuring. NS originated 11,555 coal carloads for the week, its strongest reading of the six-week window, but its Appalachian plan-versus-actual performance was 780 actual against 1,110 planned — a 29.7 percent shortfall, and the sixth straight week NS has missed its combined Appalachian plan by more than 20 percent. That is no longer noise; it is a pattern, and shippers dependent on NS-originated Appalachian tonnage should be building a documented weekly record now — dates, planned volumes, actual deliveries, and any resulting customer impact — in the event that record becomes the basis for an STB service complaint. NS’s average unit train speed of 18.2 mph, the slowest reading in the six-week window, is consistent with, though not conclusive proof of, network congestion contributing to the shortfall.

West Virginia river barge loadings of 319 for the week were the strongest of the six-week window, up from a low of 269 in Week 32, and both NAPP and CAPP barge volumes rose on the week. Barge remains a secondary channel relative to rail for West Virginia coal, but this week’s reading offers no sign of stress in that channel.

SECTION 7 | DOMESTIC COAL INDUSTRY NEWS

STB Lifts Abeyance, Adopts Procedural Schedule Pushing UP-NS Merger Decision Into Q2 2027

Surface Transportation Board, Docket No. FD 36873 | Aug. 18, 2026

WHY IT MATTERS: The Board’s decision ends the pause placed on the Union Pacific-Norfolk Southern merger review in May and sets a formal procedural schedule running into late May 2027 — later than the applicants’ hoped-for expedited timeline. This is the single largest structural development pending in U.S. rail and directly affects every coal shipper captive to either railroad. Coal producers and utilities with CSX- or NS-originated tonnage should review the applicants’ voluntary customer-protection commitments filed July 27 and consider whether to file comments before the Board’s amended deadlines; competing carriers including BNSF and CSX are already active parties in the docket.

DOE Renews Section 202(c) Emergency Order for Campbell Coal Plant

U.S. Department of Energy, Order No. 202-26-39 | Aug. 2026

WHY IT MATTERS: DOE’s latest order directs MISO to keep the J.H. Campbell coal plant in Michigan available and to employ economic dispatch to minimize ratepayer cost. This is one of more than 40 Section 202(c) emergency orders and extensions DOE has issued since May 2025 to delay coal retirements amid PJM and MISO reliability concerns. Coal suppliers serving these plants should treat continued 202(c) coverage as likely but not permanent — several orders remain under D.C. Circuit challenge from state attorneys general, and a reversal would accelerate retirement timelines with little notice.

Eighth Circuit Grants MSHA Two More Months on Silica Dust Rule Reconsideration

U.S. Court of Appeals for the Eighth Circuit / MSHA | Aug. 10, 2026

WHY IT MATTERS: The court’s order keeps the Biden-era respirable silica dust exposure limit in legal limbo for at least two more months while MSHA continues reconsidering the rule, which was originally finalized in 2024 and has already been delayed multiple times. This is squarely a mine-safety and compliance-cost issue: operators should not assume the lower exposure limit is permanently shelved, and should continue tracking the docket rather than treating the delay as a final resolution.

SECTION 8 | INTERNATIONAL COAL INTELLIGENCE

Australian Premium Hard Coking Coal Rallies 5.4% on the Week to $236.00/MT

ICE / Trading Economics, via EIA commodity data | Aug. 15, 2026

WHY IT MATTERS: This week’s rally is the sharpest single-week move across any benchmark tracked in this report and puts AUX Met Coal 22.6 percent above year-ago levels, even as it remains below the mid-$240s reached earlier this summer. Given West Virginia CAPP’s greater exposure to met coal pricing than any other segment of the state’s production, this is the most consequential single data point in this issue for Central Appalachian producers’ near-term revenue outlook.

EIA Raises 2026 U.S. Coal Export Forecast to 102 Million Short Tons on Strong Metallurgical Shipments

U.S. Energy Information Administration, Short-Term Energy Outlook | Aug. 11, 2026

WHY IT MATTERS: EIA’s August STEO cites a 32 percent year-over-year jump in total U.S. coal exports in June and continued year-over-year growth in metallurgical coal exports through the first half of 2026, supported by new and reopened mines. This is a direct, favorable data point for Appalachian met coal producers and should be read alongside this week’s Australian HCC rally as confirmation that export markets, not the domestic utility market, remain the primary growth channel available to CAPP producers over the balance of 2026.

IEA: U.S. Coal-Fired Generation Rose 10% in 2025, Bucking the Global Decline Trend

International Energy Agency, Global Energy Review 2026

WHY IT MATTERS: The IEA’s review found global coal demand growth slowed to just 0.4 percent in 2025, but noted the United States as a specific exception, with strong coal use in the power sector driving a 10 percent rise in U.S. coal-fired generation even as China’s growth diverged in the opposite direction on other metrics. This is useful, citable evidence for the domestic policy argument that U.S. coal retention decisions in 2025 and 2026 reflect genuine reliability need rather than mere policy preference, distinct from the global demand picture.

SECTION 9 | LEGISLATIVE & REGULATORY DEVELOPMENTS

SECTION 10 | SWOT ANALYSIS & STRATEGIC OUTLOOK

Strategic Outlook

This week’s data draws a sharper line than usual between coal’s two demand channels, and producers, utilities, and policymakers should read the two separately rather than blending them into a single national narrative. On the domestic dispatch side, the story remains what it has been for the past year: the Powder River Basin and Illinois Basin retain a decisive cost advantage over natural gas, Wyoming production is the only major state running ahead of 2025, and PJM’s second consecutive capacity auction shortfall — 6,831 MW short at the $325/MW-day price cap — is the clearest evidence available that premature coal retirements would worsen, not solve, a resource-adequacy problem grid operators themselves are documenting. Anyone arguing that coal retirement schedules set years ago under different load assumptions should proceed unchanged is arguing against PJM’s own auction results, not against this newsletter’s editorial position.

On the export and met coal side, the picture is more encouraging but also more fragile. Australian Premium HCC’s 5.4 percent rally to $236.00/MT this week, alongside EIA’s upward revision to the 2026 U.S. coal export forecast to 102 million short tons, gives Central Appalachian producers a real reason for optimism after a year in which CAPP production has run 10.8 percent behind 2025. But that optimism rests on a foundation The Coal Hub itself has described as more fragile than the headline price suggests: Indonesian export curbs are a policy choice that could reverse, and Chinese import demand is being structurally displaced by rising domestic Chinese output. CAPP producers and the communities that depend on them should treat this month’s price strength as a genuine opportunity to capture margin, not as evidence that the underlying export market has become durably tighter.

The single most important near-term action item in this issue is not a market signal but a documentation task: Norfolk Southern’s Appalachian coal loading plan-versus-actual shortfall has now exceeded 20 percent for six consecutive weeks, a pattern rather than an anomaly, and shippers dependent on NS-originated tonnage should be building a dated, specific record of planned volumes, actual deliveries, and resulting customer or contract impact now, before the STB’s UP-NS merger review reaches the phase where historical service performance becomes directly relevant evidence. That review itself, now extended into the second quarter of 2027 after the Board’s August 18 decision, is the structural threat that most deserves sustained attention over the next several quarters: every additional month of regulatory uncertainty over the nation’s rail network structure is a month in which coal shippers cannot fully plan long-term transportation contracts around a known set of carriers and service commitments.

The structural trend most threatening to long-term coalfield employment and production volume remains the same one this publication has flagged consistently: the widening gap between West Virginia’s two basins. NAPP’s -2.6 percent YTD decline is manageable and consistent with a mature, utility-contracted basin. CAPP’s -10.8 percent YTD decline is not manageable at the same pace indefinitely, and it is a met-coal-pricing problem more than a policy problem — no regulatory relief under discussion in Section 9 of this issue will offset a sustained Australian HCC price below the level CAPP needs to remain competitive on freight-adjusted export terms. This week’s price rally helps. Whether it holds through the fourth quarter is the single most consequential open question for Central Appalachian production and employment for the remainder of 2026.

Week’s Bottom Line

Coal production is down year-over-year but the decline is concentrated, not universal — PRB and ILB dispatch economics remain firmly favorable, Wyoming is growing, and this week’s Australian met coal rally gives Central Appalachian producers a genuine, if fragile, reason for optimism. The structural threats worth watching closely are Norfolk Southern’s persistent Appalachian service shortfall, the newly extended timeline on the UP-NS merger review, and the reversibility of the Indonesian export policy currently supporting international benchmark prices. PJM’s back-to-back capacity auction shortfalls continue to provide the strongest available evidence that coal capacity retention, not retirement, is the reliability-consistent policy path for the balance of this decade.

DATES & DEADLINES

• Aug. 28, 2026 — UP-NS merger applicants’ supplemental data resubmission due, STB Docket FD 36873

• Sept. 14, 2026 — Comment deadline, EPA proposed approval of Alabama CCR permit program

• Sept. 2026 — PJM target window for FERC-approved special capacity backstop procurement

• Oct. 13, 2026 — Comment deadline, EPA general CCR permit option notice

• First Tuesday following first Thursday of each month — EIA Short-Term Energy Outlook release (next: Sept. 8, 2026)

• Weekly, Thursdays — EIA Weekly Coal Production Report (DOE/EIA-0218) release

• Weekly, Wednesdays — AAR Weekly Railroad Traffic Report release

• Weekly — AISI Weekly Raw Steel Production Report (AIS-7) release

• Late May 2027 — Target date for STB final decision on UP-NS merger, per Aug. 18, 2026 procedural schedule

PRIMARY SOURCES

• West Virginia Coal Association, Weekly Production/Consumption Report, Week 33, week ending Aug. 15, 2026, prepared by Jason Bostic, distributed Aug. 21, 2026 — West Virginia and U.S. production, thermal and natural gas pricing, international benchmarks, CSX and Norfolk Southern carload and performance data, WV barge loadings, EEI electrical output, AISI steel production, and AAR rail traffic figures used throughout this issue.

• U.S. Energy Information Administration, Weekly Coal Production Report, DOE/EIA-0218, Week 33, week ending Aug. 15, 2026 — national, regional, state, and railcar production estimates (as reported via WVCA compilation).

• U.S. Energy Information Administration, Coal Markets Report and Natural Gas Weekly Update — domestic thermal coal and natural gas spot pricing (as reported via WVCA compilation).

• U.S. Energy Information Administration, Short-Term Energy Outlook, released Aug. 11, 2026 — 2026 coal export forecast and coal generation context.

• U.S. Energy Information Administration, Short-Term Energy Outlook, January 2026 vintage — coal share of U.S. generation estimate.

• Argus Media, “EIA further lowers US coal power 2-year outlook,” April 23, 2026 — 2026/2027 coal generation forecast figures (bn kWh).

• American Iron & Steel Institute, Weekly Raw Steel Production Report, AIS-7, Week 33 — steel production by district and capacity utilization (as reported via WVCA compilation).

• Association of American Railroads, Weekly Railroad Traffic Report, Week 33 — national rail carload and intermodal traffic by commodity (as reported via WVCA compilation).

• Surface Transportation Board Form EP-724, CSX and Norfolk Southern coal performance filings (as reported via WVCA compilation).

• Surface Transportation Board, Docket No. FD 36873, Decision, Aug. 18, 2026 — UP-NS merger procedural schedule and abeyance lift.

• Surface Transportation Board, News Release No. 26-18, July 22, 2026 — UP-NS employee data public-disclosure order.

• Union Pacific Corporation, press release, July 27, 2026 — UP-NS enhanced customer protection commitments.

• PJM Interconnection, “PJM Capacity Auction Procures 138,318 MW of Generation Resources,” July 14, 2026 — 2028/2029 Base Residual Auction results.

• U.S. Department of Energy, Office of Cybersecurity, Energy Security, and Emergency Response, Section 202(c) order log — J.H. Campbell plant order status.

• U.S. Environmental Protection Agency, Coal Combustion Residuals program page, updates through July 23, 2026 — Alabama CCR permit program proposal, general permit option notice, and Coronado Generating Station alternate liner approval.

• West Virginia Watch, “MSHA backs longer legal limbo for mine dust rule,” Aug. 2026 — Eighth Circuit silica rule reconsideration extension.

• West Virginia Coal Association / Lootpress, “National Coal Council Reports Will Benefit West Virginia’s Mining Industry,” July 24, 2026.

• The Coal Hub, “Indonesian coal exports face new uncertainty under state export control plan,” May 20, 2026 — Indonesian export volume and pricing trends.

• Bloomberg / China Coal Transportation and Distribution Association, coal import forecast reporting, Feb. 2026.

• TradeInt, India Import Data, coal import partner-share reporting, June 15, 2026.

• International Energy Agency, Global Energy Review 2026, Coal section — 2025 global and U.S. coal demand trends.

AI ASSISTANCE DISCLOSURE: AI assistance was used in research compilation, data formatting, and drafting of this publication under the author’s editorial direction. All data sourced from verified primary sources as cited; all editorial judgments, strategic assessments, and analytical conclusions are the author’s own. Readers should verify data directly with cited sources.

By T.L. Headley, MBA, / President / The Hedley Company

EXECUTIVE SUMMARY

U.S. coal production rose to 10,307 KST in the week ending August 15 (Week 33), up 3.9 percent from the prior week but still 5.5 percent below the corresponding week of 2025. Year-to-date production of 319.8 million short tons trails 2025’s pace by 2.7 percent, with the decline concentrated in the Interior Basin (-4.9 percent YTD) and Appalachia (-4.2 percent YTD) while the Western Basin holds closer to flat (-1.1 percent YTD) on Wyoming’s continued strength. Wyoming production is up 1.7 percent YTD even as most other producing states run behind last year’s pace, underscoring the degree to which the national total is being carried by the Powder River Basin’s cost advantage rather than broad-based demand recovery.

West Virginia production rose 5.6 percent week-over-week to 1,540 KST but remains 3.3 percent below the same week last year and 6.4 percent behind on a year-to-date basis. The state’s two basins continue to diverge: Northern Appalachia held its ground at 861 KST, down only 2.6 percent YTD, while Central Appalachia’s 679 KST reading is off 10.8 percent YTD. That gap is a coking-coal story as much as a thermal one — Central Appalachia’s export-linked met coal tonnage is more exposed to the Australian benchmark, which firmed 5.4 percent week-over-week to $236.00/MT but remains a level Appalachian producers must compete against on freight-adjusted terms.

Dispatch economics by basin remain unchanged in direction if not magnitude. On an energy-equivalent basis, CAPP coal at $3.24/MMBtu and NAPP at $2.70/MMBtu, CAPP continues to price above Henry Hub’s $2.94/MMBtu. meaning Central Appalachian coal faces a real dispatch penalty against gas at current prices while Northern Appalachia sits competitive. Illinois Basin coal at $2.35/MMBtu undercuts gas by $0.59, and Powder River Basin coal at $0.83/MMBtu undercuts gas by $2.11 — the PRB’s structural advantage over gas-fired generation remains enormous and is the single largest reason Western production is outperforming the rest of the country.
See more when the full Coal Currents posts Monday evening