FERC just made the fight over who builds—and who pays—far more immediate. Quick catch-up if you're joining us: FERC’s June 18 Section 206 show-cause orders told six RTOs and ISOs to explain or revise how they connect data centers, manufacturing facilities, and other large electricity users. The proceeding asks whether interconnection rules can move those loads onto the grid faster while protecting reliability and assigning infrastructure costs. Final reforms and timelines are still undecided. This is Power Grid Daily. FERC’s large-load rulebook is moving, and one developer has walked away. Let’s start at the MISO-PJM border. We'll keep tracking this story — FERC large-load interconnection show-cause orders. Follow the show so the next update finds you. Here's RTO Insider:
FERC ruled MISO can circumvent a competitive bidding process when it taps PJM transmission owners to build parts of its long-range transmission projects that cross into the neighboring RTO ( ER26-1538, et al. ). The commission decided Aug. 14 that MISO’s competitive selection process does not apply to facilities outside its system and under another RTO’s functional control.
FERC’s line is functional control: once that segment sits in PJM territory, MISO can’t run its own competitive process over it. But putting a $904 million assignment on ComEd’s books doesn’t speed up a single substation build. The date that bites is June 1. FERC let these new recovery schedules take effect retroactively, so Midwest customers can be charged under an arrangement the commission approved August 14. The competitive groups have a legitimate gripe. MISO’s nearly $22 billion portfolio crosses a seam, and the $904 million ComEd piece bypasses bidding because the work is under PJM control. Duke’s assigned share is $5.3 million; ComEd’s is $904 million. Same legal theory, but radically different consequences for ratepayers. FERC chose jurisdictional boundaries over competitive pressure. From RTO Insider:
The commission recently granted ISO-NE a 90-day abeyance on the proceeding, pushing the deadline for the RTO to make a Section 205 filing to Nov. 16 ( EL26-72 ). ISO-NE said its filing “will put eligible customers on notice that large loads must ‘bring your own new generation’ … and that large loads will be excluded from the installed capacity requirement.”
ISO-NE’s drawing the line at 50 MW: bring your own new generation and stay out of the installed-capacity requirement. It gives FERC an actual policy answer instead of another workshop calendar. And it’s unusually preventive. ISO-NE forecasts less than 120 MW of large-load peak growth through 2035, yet one hyperscale facility could still move prices on a grid this small. The filing is due Nov. 16; the detailed tariff mechanics wait until 2027. BYOG sets a commercial condition; it doesn’t shorten the substation queue. A 50-MW customer still needs equipment, studies, and a buildable generation project—but at least ISO-NE is refusing to socialize the capacity obligation while all that gets sorted out. FERC’s large-load order has produced a concrete ISO-NE response: a BYOG filing now, detailed rules in 2027. For a region that has mostly avoided the hyperscale rush, they’re writing the guardrails before the traffic arrives. From RTO Insider:
Tech firm Oracle has voluntarily dismissed its lawsuit against the Public Service Commission of Wisconsin, leaving strict financial safeguards intact on giant data center development. Oracle in late June mounted a legal challenge to the state’s collateral and credit rating requirements for large customer rates, arguing they were too severe and admitting it did not have enough tangible net worth or liquidity to meet security requirements for its 670-acre Stargate project in Port Washington.
It’s the same Port Washington data-center buildout we covered through ATC’s reset: Oracle has dropped its PSC financial-safeguards lawsuit. So the commission’s collateral and credit standards remain in place for a project seeking 1.3 gigawatts from We Energies. Oracle said it lacked the tangible net worth and liquidity to post the required security, and it couldn’t meet the A-minus or A3 credit-rating floor. For a $15 billion, 670-acre campus, that is exactly when a regulator should ask for collateral. Oracle says its WEC contract proves it’ll pay its own way. But the case is gone, the PSC guardrails survived, and Oracle still hasn’t said how it will satisfy them. Ratepayers aren’t being asked to rely on a promise in a press release. After the ISO-NE piece, there’s a useful distinction: a 50-megawatt tariff threshold tells you who enters the large-load regime. Wisconsin’s rules test whether the customer can actually carry the financial commitment once it gets there. RTO Insider writes:
Ontario’s renewed electricity market has been active for more than a year, and a new analysis from the Ontario Energy Board’s Market Surveillance Panel says that locational pricing has made regional congestion more transparent. However, the new pricing scheme has revealed ongoing constraints in northern Ontario and rare but severe congestion around Ottawa, which emerged as Ontario’s most volatile zone, according to the report.
Ontario’s first full year of locational pricing found Northwest congestion in 46.8% of hours. Surplus hydro can be sitting there, prices go negative, and the wire south is still full — that’s a very physical kind of inefficiency. And Ottawa is the sharper warning. Congestion showed up only 1.4% of the time, but its 95th-percentile absolute value reached $671.30 per megawatt-hour. Rare is not cheap when the constraint binds behind a single interface. The panel also flags hydro shifting output between hours, which may be efficient optimization but can look a lot like withholding when prices whip around intraday. You need the dispatch data before declaring that behavior benign. Locational pricing did what it was supposed to: it put numbers and a map on northern constraints and Ottawa exposure. Now Ontario has to decide whether those signals make the case for transmission investment, or just explain volatile bills. From RTO Insider:
Portland General Electric says creating a holding company would help the utility compete for capital and tackle increasing energy demand in the Pacific Northwest, but skeptics say the proposal could end up benefitting shareholders to the detriment of customers. The Oregon Public Utility Commission is weighing whether to approve the application.
PGE’s asking Oregon regulators for a familiar bargain: more financing flexibility through a parent company, with a promise of lower capital costs for customers. By Sept. 25, the PUC needs to decide how much of that benefit is enforceable at the regulated utility, rather than merely available somewhere in the corporate family. They’re pointing to a regional need for roughly 11 gigawatts of new generation by 2032. But a holding company doesn’t shorten transformer lead times, clear a substation site, or make a project construction-ready. PGE is the only major Pacific Northwest investor-owned utility without this structure, according to RTO Insider. Being the last one standing might put it at a capital disadvantage. It also gives Oregon a chance to write tighter customer protections before approving the conversion. And “financial instruments” covers a lot in that pitch. The PUC needs a plain-English answer: how does this lower customer rates, and who takes the hit if demand forecasts come in light? Have feedback, story ideas, or a correction? Email us at powergriddaily at lantern podcasts dot com. Your notes help make Power Grid Daily more useful, accurate, and relevant.
Looking ahead, ISO-NE’s Section 205 filing in EL26-72 is due November 16, and the Oregon PUC decision on PGE’s holding-company application is expected by September 25.
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