Who decides how large loads connect to the grid?

A developer planning a 400 MW data center campus or a new semiconductor fab in early 2025 faced a question with no single answer: which regulator approves the grid connection. As of June 18, 2026, when FERC issued six show cause orders to the country's six regional grid operators, the decision splits between two levels of government. States keep siting and construction approvals, and they keep retail service, meaning the terms of the power sale and the choice of which entities may sell power to the facility. FERC, the Federal Energy Regulatory Commission, now supervises how the connection is studied and priced inside the six organized wholesale markets, and the operative rules are being drafted right now in six dockets with responses due August 17, 2026.

Energy Secretary Chris Wright started the current fight on October 23, 2025, when he invoked Section 403 of the Department of Energy Organization Act, a rarely used authority that lets DOE direct FERC to consider a rulemaking, and ordered the commission to open a proceeding on large load interconnection (Docket RM26-4).

That directive ran into a boundary that has organized grid regulation for decades, because interconnection has historically split into two things:

1. Generator interconnection, which is the process for connecting a power plant to the high-voltage transmission system, and which FERC governs under the Federal Power Act.

2. Load interconnection, which is the process for connecting a consumer of power, and which states and their utilities have governed for roughly a century.

DOE's directive proposed collapsing that split by putting loads above 20 MW, a threshold low enough to capture mid-size factories alongside hyperscale campuses, under federal interconnection rules. State utility commissions objected to the reach, FERC staff ended up reviewing more than 3,500 pages of comments, and proposals in the docket put the right threshold anywhere from 50 MW up to 300 MW. I would say the 20 MW number was the most contested design choice in the proceeding, because the threshold determines which projects fall under the rules at all.

FERC declined the jurisdiction it was offered and used rate authority it has held since 1935. The commission issued six show cause orders under Section 206 of the Federal Power Act, one to each regional transmission organization (an RTO is the FERC-regulated entity that runs the wholesale market and the transmission system for a multi-state region: PJM, MISO, SPP, CAISO, ISO New England, and NYISO), and it left the national rulemaking docket open in the background. A show cause order makes a preliminary finding that the existing tariff appears to be no longer just and reasonable and gives the regulated entity a deadline to either defend it or propose amendments. The jurisdictional theory is narrow on purpose. Network upgrade costs triggered by a new large load flow into wholesale transmission rates, and FERC already sets those rates. In turn, what this means is that FERC did not need to claim authority over the load itself: it claimed authority over the prices the load's arrival changes, and it left the physical hookup, the retail sale, the siting decisions, and the construction approvals with the states. FERC's PJM order states that "nothing in this order is intended to intrude upon state authority over retail service to large loads".

The commission did not start from a blank page when it wrote the June orders, because it had already approved two regional templates over the prior six months. In December 2025 FERC found PJM's tariff unjust and unreasonable on co-location, meaning arrangements where a large customer sits physically at a generator's site (e.g., a data center at a nuclear plant), and ordered PJM to write clear rules for it, including reformed behind-the-meter generation rules. In January 2026 it approved SPP's High Impact Large Load program, which created a dedicated study track for very large loads and an expedited path for generators built to serve them (the June orders separately suggest treating a generator as electrically proximate when it sits within two substations of the load). The June orders cite both as models, and they excuse PJM on co-location and SPP on study process because those two regions answered those questions in the earlier proceedings.

The six orders describe the regime FERC wants each region to propose by August 17, and four elements matter most for anyone planning a facility. First, a suggested definition of large load: a new facility with peak demand of 50 MW or more taking transmission service above 69 kilovolts and not part of a co-located arrangement, which is 2.5 times DOE's opening number, as well as tracks the definition FERC already accepted from SPP. Second, cost protection: RTOs and transmission owners should sign cost recovery agreements under which large customers make a minimum financial contribution to the transmission owner's revenue requirement, backed by strict credit support. As a result of this, a canceled project's upgrade costs are far less likely to get passed to households. Third, engineering discipline: study processes should consider alternative transmission technologies such as advanced conductors and dynamic line ratings, and a transmission owner that insists on traditional upgrades should explain why. Fourth, flexibility products: new interim and non-firm transmission services for loads willing to be curtailed (curtailment means the grid operator can instruct the customer to cut consumption) during system stress, offered as a faster path to energization.

Six regional stakeholder processes, each on a 60-day clock, replaced the national rulemaking DOE asked for, and that swap changes who holds leverage. Under a rulemaking, influence ran through comment filings addressed to five commissioners in Washington. Under show cause orders, the drafting happens inside each RTO's stakeholder process over the next few weeks, with any pause capped at 90 days and heavy scrutiny promised for anyone requesting one. What this comes out to: incumbent utilities and whoever staffs those meetings in July and August will write the first draft of the rules, and FERC's later orders will review and adjust those drafts region by region. The orders also leave a gap. They bind regions serving around two-thirds of the load under FERC-jurisdictional rates, per FERC staff estimates, while non-RTO utilities across most of the Southeast and the interior West, plus ERCOT in Texas, sit outside them. FERC kept RM26-4 open as a placeholder for those regions. In practice, a project in Georgia or Arizona still negotiates its connection utility by utility.

The orders apply by megawatt and interconnection voltage, with no industry test, which matters for manufacturers more than the data center headlines suggest. A 200 MW fab or an electrolyzer plant exceeds the 50 MW threshold the same way a data center campus does. As a result of this, it inherits the same study rules, the same cost recovery agreements, the same minimum contributions, and the same credit support terms. The flexibility products will not benefit both kinds of customer equally, though. A data center can shift compute jobs to another region during a system peak, while a fab running a multi-week wafer lot generally cannot stop mid-process without scrapping the material in the line, since there is no equivalent of moving the workload to another site. In turn, what this means is that the interim and non-firm services that buy queue speed are worth a great deal to data centers and much less to continuous-process manufacturers, who should concentrate on the cost allocation terms and on the co-located generation pathway, where the two-substation study track gives a factory a recognized process to pair itself with a dedicated plant. We follow all six dockets as part of our energy regulatory advisory work, on both the developer side and the utility side.

An energy or siting team with a project above roughly 50 MW in an RTO region has a short list of concrete work between now and autumn: read its region's June 18 order rather than a summary of it, calendar the comment window (interested parties get 30 days after each RTO files its response), model the minimum contribution and credit support in the project pro forma before term sheets are signed (lenders will ask...), and decide early how much curtailment the operation can physically tolerate, because that answer now determines which service products the region will offer it. Teams outside RTO regions should pressure-test their utility agreements against the FERC template, since FERC encouraged non-RTO transmission owners to file comparable rules and some state commissions are likely to borrow the cost protection language in their own proceedings.

FERC's orders fixed the schedule for the rest of the year, and the dates run as follows: abeyance requests are due August 3, RTO and transmission owner responses are due August 17, public comments close 30 days after each regional filing, and the commission has said it will act in the still-open RM26-4 docket if the regional answers fall short.

If you are unsure where your project or portfolio sits across these six dockets, the Energy Exposure Diagnostic, a two-week screen, is the entry point. If you already know what you need, get in touch and we can scope it.

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Arif Gasilov is partner for Natural Resources & Built Environment at Gasilov Group, where he works on energy regulatory analysis, water governance, utility rate cases, and the resource footprint of large development. Meet Our Partners →

Frequently Asked Questions (FAQ):

Does FERC's 50 MW definition apply outside the six RTO regions? The June 18 orders bind the six RTOs/ISOs and their member transmission owners, so non-RTO utilities in the Southeast and the interior West (and ERCOT, for separate jurisdictional reasons) fall outside them. FERC kept the RM26-4 docket open for those regions and encouraged non-RTO transmission owners to propose comparable large load rules voluntarily.

Is the 50 MW / 69 kV threshold final? The threshold is a suggested definition in the show cause orders, modeled on tariff language FERC already accepted from SPP, and each region's August filing can propose different terms. FERC will then accept, modify, or reject each regional proposal in separate orders later in 2026.