SPP members vote this week on their answer to FERC: a cap on shared grid costs for big new loads and a $25 cutoff for flexible ones

Southwest Power Pool's members vote this week on the rules the grid operator plans to send federal regulators by Nov. 20 to defend how it connects data centers. Large new loads would pay directly for grid upgrades above a cap, and flexible customers would get a cheap, interruptible service that stops drawing power whenever prices rise above $25 a megawatt-hour.

SPP's Markets and Operations Policy Committee takes up four revision requests on Tuesday and Wednesday, Oct. 13 and 14, in Little Rock, Ark., according to its posted agenda. Together they form SPP's response to a June 18 order in which the Federal Energy Regulatory Commission found that SPP's tariff "appears to be unjust, unreasonable, or unduly discriminatory or preferential" in how it handles large and co-located loads. The Regional State Committee of state regulators is scheduled to take up the cost pieces on Nov. 16, and SPP's board meets Nov. 17. SPP staff told members that "further extension of the Show Cause compliance deadline is not a good option."

The biggest change for developers is who pays for the grid. Today, upgrades needed to connect new load backed by enough generation are folded into regional and zonal transmission rates that every customer pays. Under the proposed Load Safe Harbor Limit, those rates would cover a new delivery point's upgrades only up to the lower of $500,000 per megawatt of requested load or $25 million per request. Anything above that would be charged directly to the transmission customer serving the load, backed by financial security, and collected even if the load never materializes. SPP's CARE Team, which led the cost work, recommended capping that direct charge at 20 years and applying the rule only to requests made after the effective date FERC sets.

The cap is contested. In SPP's own data, 16 of the 41 delivery-point studies that led to construction orders from 2012 to 2025 cost more than $25 million, topped by a 1,200 MW request at $466 million. The Regional State Committee's cost allocation working group voted 6-4, with five abstentions, for a flat $21.25 million limit for loads of 50 MW or more. North Dakota's commission, which opposed that motion, warned the 50 MW line risked "creating powerful incentives for loads to disaggregate." AEP, OG&E, Evergy and Xcel Energy's Southwestern Public Service asked SPP in joint comments to drop the $25 million cap and apply the rule only to the largest loads.

The second piece is Price Adaptive Load Service, a design FERC singled out in June. Customers would bid for power in SPP's day-ahead and real-time markets with bids capped at $25/MWh. They would have to be able to cut to zero within five minutes and would be taken offline when SPP enters conservative operations or declares an energy emergency. In return, SPP's study would set their service limit without requiring network upgrades, and they would carry no resource adequacy obligation and pay non-firm transmission rates only for the hours they draw power, capped at the monthly rate. Terms would run one to 10 years, renewable after a new 90-day study. SPP cites thermal storage and crypto mining as the kind of load it has in mind, though any size of load can apply.

The economics are tight. SPP's simulation of 2 GW of such loads found load factors averaged 45% under a $20 cap, and below 35% in summer, which is why staff settled on $25. Commenters told SPP that "the fixed 10-year term is misaligned with typical 15–20-year financing horizons," in SPP's summary. The state regulators' working group voted on Oct. 1 to have PALS customers pay off-peak transmission rates only, which SPP staff opposes. SPP estimates the service would take 18 months to put in place.

The other two requests are narrower. One would make SPP weigh options such as dynamic line ratings before ordering upgrades for large loads, and post upgrade costs online. The other sets study and registration rules for co-located and behind-the-meter generation.

SPP was early to this fight. FERC accepted its High Impact Large Load process on Jan. 14 in Docket No. ER26-247. A HILL is new or expanded commercial or industrial load at one site of 10 MW or more connected at 69 kilovolts or below, or 50 MW or more at higher voltages. SPP offers a 90-day study-and-approval process, and a companion assessment fast-tracks generation built within two substations of the load. "Large loads want answers now," Casey Cathey, SPP's vice president for engineering, said when the board approved the policy in September 2025. Commissioner David Rosner wrote that it encourages "bring-your-own-new-generation" solutions.

On June 5, FERC accepted Conditional High Impact Large Load Service, a curtailable, as-available service capped at seven years that lets a large load take power before the generation or upgrades needed for firm service are in place. Thirteen days later, in one of six show-cause orders issued that day, FERC said it was "encouraged by SPP's stakeholder efforts" but that the conditional service "differs from" the interim service it required of PJM. It ordered SPP either to defend its tariff or to fix it. SPP and a group of transmission owners won a pause on Aug. 14 that pushed the deadline to Nov. 20.

The pressure is in SPP's numbers. FERC's order cites SPP figures showing large-load requests peaked at nearly 11 gigawatts in 2022 and fell to about 6 GW in 2024, a drop SPP said may partly reflect its inability to study and connect them quickly enough. In Missouri alone, SPP reported 11 HILL requests totaling 3,871 MW as of August, 568 MW of them already under service agreements.

FERC Commissioner David LaCerte warned SPP in June that a deficient response would end with "the Commission dictating the solutions for you." SPP has five weeks to show it doesn't need the help.