A data center wants power. The fight is over who signs the check if it never shows up. This is Power Grid Daily. Approvals, private arbitration, a Texas peak, and the factories trying to keep up with all of it. First up: two very different regulatory fights, with the same uncomfortable exposure for utilities. Here's Paul Kiefer at Wisconsin Watch:
Wisconsin regulators voted Thursday to send the American Transmission Company (ATC) back to the drawing board as the utility attempts to build the grid infrastructure needed to plug in the Port Washington data center.
ATC wants permission for a $1.3 billion package—five substations and a high-voltage line—to serve Port Washington by December 2027. After repeated design changes, Wisconsin's PSC is making it file a coherent case before those costs start hardening into someone else's bill. A December 2027 service date was already tight when ATC first filed last September. Restarting the application won't restart transformer factory slots, substation engineering, or construction seasons. ATC's warning about investment needs a cooler read. The PSC chair called it a reasonable reset: the design kept moving, and ratepayers need to see what they're underwriting—and what backstop the data-center customer provides if its load changes. Right. This century-old commission apparently hadn't forced this kind of restart before— which tells you how unusual it is to bring five substations to the table with the picture still blurry. From Marin Holt at MGRID:
The utility frames the case as a jurisdiction question, not a contract fight. Who gets power, and who pays to deliver it, are questions for the Public Utilities Commission of Nevada. A private arbitrator answers to the two parties in the room. Every other ratepayer in the state sits outside that room.
NV Energy is right to put this before the PUC. A 2,025-megawatt request—nearly a third of its generating capacity, per MGRID—can't have its cost allocation decided in a room where Nevada ratepayers don't get a chair. And 362 megawatts of behind-the-meter generation sounds big until you do the subtraction: Tract still needs 1,663 megawatts from somewhere else. Before NV reserves that capacity, put the interruptibility terms and walk-away penalties in public. Tract says it has put more than $127 million into Nevada infrastructure and committed nearly $1 billion in network upgrades. Fine—Rule 9 is where the parties should establish which costs are truly customer-funded and which could migrate onto everyone else's bill. We just saw Wisconsin regulators demand a fresh process for a data-center connection. Different state, same pressure point: utilities are being asked to build first and trust a giant-load forecast later. That's a very expensive order of operations. Rigzone writes:
In its statement, the EIA noted that, according to data reported to the EIA for its Hourly Electric Grid Monitor, hourly peak load in ERCOT, which the EIA described as the regional transmission organization serving most of Texas, reached a record 91.1 gigawatts (GW) on July 22.
ERCOT hit 91.1 gigawatts at 6 p.m. on July 22, and the mix matters: 48 percent gas, 32 percent solar. That solar share is a big assist in a Texas evening peak—but gas was still carrying nearly half the load. Call it what it is: an EIA hourly-monitor record, with the usual settlement-data caveat. Don't turn it into a permanent planning number. The peak-hour resource mix tells you far more than the headline. Right. Solar at 32 percent at 6 p.m. is very different from solar at 32 percent after sunset. If the next heat wave moves the peak two hours later, ERCOT needs different resources on the bench—gas, storage, imports where it can get them. Which hits differently after those two data-center fights we just covered. A 91.1-gigawatt peak is manageable. The politically radioactive part is building ahead of speculative load without a customer backstop. The Globe and Mail writes:
As expansion plans for North America’s electrical grid begin to take shape after a period of relative stagnation, few components have been more difficult to obtain than power transformers. Their availability has dwindled, to the point where utilities can wait several years to get their hands on one.
Hitachi buying land beside Varennes and aiming to triple transformer output is a real supply-side move. But utilities are already waiting years; the hard question is how much of that added capacity is already spoken for before the first transformer from the expanded plant leaves Quebec. And Stella-Jones reopening Candiac in August to double steel-tower production matters for the same reason: these are physical capital commitments. The procurement calendar now has to meet the planning calendar. Exactly. You can clear approvals and have a load customer waving a contract around—then still wait on the transformer. Concrete and rebar in Varennes are encouraging; they don't make equipment appear in a substation. The Globe notes more than half of Canadian utility equipment purchases come from the U.S., during a trade war. After the Port Washington and NV Energy fights, the question gets sharper: before utilities build for giant new loads, who is underwriting the equipment exposure if the customer's timeline slips? From Modern Power Systems:
Copenhagen Infrastructure Partners (CIP) has reached final investment decision and financial close for the La Esperanza Solar project, a 420 MWdc solar photovoltaic plant paired with a 150 MW/750 MWh battery energy storage system in Mexico.
CIP has financial close, $510 million of debt, and construction under way on a 420-megawatt DC solar plant plus a 150-megawatt, five-hour battery. Good. But a 2028 COD still leaves a tight equipment schedule for a project this size. And the five-hour duration matters on the Yucatán Peninsula. That 750-megawatt-hour battery gives CIP something to sell into the evening peak, not just another midday solar profile. Financial close means the lenders signed off; it doesn't solve procurement. We just covered manufacturers expanding capacity, but La Esperanza's procurement slots had better already be locked in if 2028 is a real date. CIP is also bringing Profuturo in as its expected Mexican pension-fund co-investor. That local capital will be watching closely to see whether the project reaches commercial operation on schedule—not just whether it had a closing ceremony. If Power Grid Daily is useful, please subscribe and leave us a review wherever you're listening. It helps more people find the show and start their day informed.
We'll be watching La Esperanza as construction gets underway, with commercial operations expected in 2028.
Links to every story are in the show notes, so take a look at the ones you'd like to explore further. Thanks for listening. We'll be back tomorrow with Power Grid Daily. This is a Lantern Podcast.