What’s moving the
markets now.

Monitoring Analytics finally put a price on the thing everyone has been arguing about. Existing and forecast data center load accounts for 9% of the PJM wholesale price through July, or $10.48/MWh, and all of it arrives through capacity rather than energy. The last four auctions added $29.4 billion in capacity revenue tied to that load growth. Total PJM wholesale cost is up 46% to $116.53/MWh, $56.7 billion over seven months against $38 billion in the same stretch last year. That is not a weather story or a fuel story. It is a structural repricing of the capacity component, and the monitor says it keeps climbing until the large-load question gets settled.

The part that gets less attention is the delivery side. Ohio's consumer counsel is still waiting on a 2023 complaint while AEP, FirstEnergy, AES and Duke pushed more than $4.3 billion of local and supplemental transmission through PJM's Attachment M-3 process with no prudence review. That cost does not show up in your energy or capacity position. It shows up in delivery charges your customer sees on the same bill as your commodity rate, and you get the churn either way. MISO South falling short of the one-day-in-10 standard and Texas approving its first 765-kV segments into the Permian are the same story in different clothes: load pockets are tightening faster than wires get built, and every month of lag prices as basis and scarcity. If your 2027 and 2028 offers are built on a capacity assumption you set before this summer, rebuild them.

Hugh Brinson starts moving Permian gas toward East Texas and the Henry Hub area today, building to 2.2 Bcf/d. October futures settled at $2.862 on Friday, back under $3, with Lower 48 dry production running 113 Bcf/d and storage 5.5% above the five-year average. The interesting part is not the pipeline, it is that the market priced it before the first molecule moved. A prompt month that will not hold $3 into September, with the shoulder ahead and storage comfortable, is the market telling you it does not believe in a supply problem this winter. ISO-NE's July report backs that up from the demand side: wholesale prices came off in both the day-ahead and real-time markets, a reversal from June, and New England clears track gas more tightly than any other region's.

The risk sits further out on the curve than most gas marketers are currently hedged. Ottawa's $27.6 billion counter-tariff list deliberately spared oil and gas flows but put 50% duties on line pipe, casing and drill pipe starting Sept. 8. Alberta only sources about 2% of its pipe from the U.S., so the direct cost is trivial. The real exposure is developers sitting on capital decisions until the dispute clears, which pushes out takeaway capacity on both sides of the border and shows up as wider basis in 2028 and 2029, not in your Q4 book. The Sapphire acquisition of EDGE LNG, roughly 200,000 gal/day of modular liquefaction against 122 Bcf/d of production, is a reminder that the incremental demand growth is going to loads that infrastructure cannot reach. Small now. Worth watching. For the winter book, the story is comfortable supply and a soft prompt.

New Jersey's BPU would pay up to $200/kW a year for 10 years to residential customers of the state's four utilities who let a small battery discharge on call. It is 150 MW, the first block of a program that has to reach 2 GW by 2030, and the Board is explicit about why: shaved peak in New Jersey is capacity PJM does not have to procure. That is the right instinct and it is a genuinely useful hedge against the capacity repricing described above, because it does not need an interconnection queue position to show up. Every megawatt that answers a heat-wave dispatch is a megawatt that does not clear at scarcity.

Now put it next to the supply side. NRDC models 390 to 540 GW of wind, solar and storage disappearing over the next decade from tax credit rollbacks, tariffs and lease buybacks, with at most 9 GW of gas backfilling because turbine slots are sold out into the 2030s. They put the power sector's added fuel spend at $5 billion to $15 billion and household rates 4.2% to 5.5% higher by 2035. California's suit over the cancelled 2-GW Golden State Wind lease, bought back for $120 million, is one line item in that ledger. The executive order giving DOE 120 days to write rules limiting foreign-made transformers, batteries and inverters on the bulk power system is the other end of the same pipe, and China supplies 80% or more of some of that equipment. For a supplier, the trade is not distributed flexibility versus utility-scale supply. It is recognizing that 150 MW of home batteries and gigawatts of cancelled generation are moving the price in opposite directions and the second number is three orders of magnitude larger. Build the DER hedge anyway, because it is what you can actually control, but do not let it flatter your forward curve.