FERC Rewrites How Large Loads Join the Grid

Fourteen months from a cabinet directive to six show cause orders

The chain starts outside FERC. On 23 October 2025 the Secretary of Energy, acting under section 403 of the DOE Organization Act, directed the Commission to consider an advance notice of proposed rulemaking on interconnecting large loads, generally those above 20 MW, to the interstate transmission system. That became docket RM26-4-000. The comment record ran to more than 3,500 pages, which is itself a measure of how much capital is waiting on the answer.

FERC moved on the regions before it moved on the rule. On 18 December 2025, in docket EL25-49 and related, it found PJM's tariff lacked sufficient clarity for generators serving co-located load and directed revision under section 206. PJM filed on 20 January 2026. In January 2026 FERC approved the Southwest Power Pool's High Impact Large Load initiative, setting protocols to speed interconnection of large loads and associated new generation while protecting consumers. On 16 April 2026 FERC issued an Order on Compliance and Directing Further Compliance, 195 FERC paragraph 61,030, together with an Order Regarding Intent to Act, 195 FERC paragraph 61,045, partially accepting and partially rejecting PJM's filing and requiring a further compliance filing within 30 days, due 18 May 2026. The same day, Chairman Laura V. Swett framed the stakes in a sentence worth keeping: the nation stands at a pivotal moment as it faces rapid growth in demand from data centres.

The decisive step came on 18 June 2026, when FERC issued six orders to show cause under section 206: PJM in EL26-67, SPP in EL26-68, NYISO in EL26-69, MISO in EL26-70, CAISO in EL26-71 and ISO New England in EL26-72. Each grid operator and its transmission owners must demonstrate why the existing tariff remains just and reasonable given the absence of clear provisions for large load customers, or propose changes. Separately, each had to file an informational report on how it will ensure adequate generation for existing and new large loads. Deadlines were 20 July 2026 for the generation adequacy report, 17 August 2026 for the justification or tariff filings, and 3 August 2026 for any request to hold the orders in abeyance, with abeyance capped at 90 days and FERC stating it would scrutinise such requests heavily and disfavours extensions.

What the Commission said it was worried about is specific and worth reading literally. Each tariff may no longer be just and reasonable because it lacks clarity on four things: flexible large loads that can limit grid use under defined conditions, co-location, load served by behind the meter generation, and generators serving electrically proximate or co-located load. For SPP the Commission added two further items, evaluation of alternative transmission technologies and operational requirements inside large load service agreements. Those six items are the actual agenda. Everything else in the proceeding is procedure.

Projet 54A data hall and its engineer. Whether this load connects as a customer, a neighbour or a generator's private offtake is the question six grid operators were ordered to answer.

Whether a data centre is a customer, a neighbour, or a generator's private load

Strip away the dockets and one question sits underneath all of them. When a large consumer sits next to a power plant and takes power from it directly, is that a retail arrangement outside federal jurisdiction, a wholesale transaction inside it, or a transmission customer that happens to be adjacent to generation? The answer determines who studies the connection, who pays for network upgrades, who can be curtailed, and whether state or federal regulators hold the pen. It is a jurisdictional question dressed as an engineering one, and the money riding on it is the reason the comment file ran past 3,500 pages.

FERC's 16 April 2026 order shows how it is resolving the engineering half. It accepted four PJM pathways: interconnection service below a generator's nameplate capacity studied at the level actually requested; use of Decision Point I and II acceleration where no network upgrades or further studies are needed; provisional interconnection service subject to annual re-studies; and surplus interconnection service at an existing point of interconnection. Each of those is a way to get a project connected faster by using capacity that already exists rather than building new. That is the Commission's revealed preference: use the existing system harder before adding to it.

It also showed what it will not accept. FERC rejected PJM's replacement of Point of Interconnection with Point of Change in Ownership in the Co-Located Load definition, insisting on the Commission approved formulation referring to load physically connected to the facilities of an existing or planned Customer Facility, and noting the proposed change risked delay if transmission owners withheld agreement on ownership transfer points. It separately struck PJM's proposed changes to behind the meter generation application requirements as outside the scope of the proceeding. Both rejections point the same way: the Commission is guarding the definition that controls access to the fast path.

The unresolved item is the expensive one. FERC declined to address cost allocation for co-located load, including load paired with storage, as out of scope on 16 April 2026, and in the rulemaking has asked whether large loads should bear the full cost of required network upgrades with credits returned over time, what a pro forma cost recovery agreement among operator, transmission owner and customer should look like, and what minimum financial security should be required. Market monitors have raised a related reliability concern: sudden injections when a large load drops off, and system planning when a co-located generator trips or goes out of service. None of that is settled. Until it is, every project is being developed against a cost allocation rule that does not yet exist.

There is a transition question too, and it is the one most likely to catch projects already in flight. FERC asked how to handle large load requests already under review when any new requirements take effect. A developer who entered a queue under today's rules has no assurance about which rules will govern the study when it completes. That is a live commercial risk on every large load project currently in development, and it is not priced in most contracts.

Six markets, one rulebook, and a two year spread in arrival times

Commissioner LaCerte put the regional point on the record in the SPP concurrence, observing that the Commission is further down the road in some regions as compared with others. The proceeding's own calendar proves it. SPP's High Impact Large Load initiative was approved in January 2026 and is operating. PJM has been under a specific directive since 18 December 2025 and has already been through a compliance cycle, an April order and a further compliance filing. MISO filed its generation adequacy report on 20 July 2026, then jointly with its transmission owners moved on 3 August 2026 to hold the proceeding in abeyance for 90 days while stakeholder work continued, and FERC granted that on 14 August 2026, pushing responses to 16 November 2026 and answers to 16 December 2026.

MISO's abeyance is worth reading carefully, because it is not simply delay. The same operator filed two substantive tariff changes during the pause: a Zero Injection Generator Interconnection Agreement on 18 August 2026 creating a study process and operational and market rules for zero injection generators serving load at the same substation, with an effective date requested of 18 October 2026, and Large Load Interconnection Reliability Requirements on 28 August 2026 with an effective date requested of 4 December 2026. The region asked for more time on the show cause docket while separately building the machinery through its own filings. That is a different posture from resisting the change.

For anyone making siting or capacity decisions this matters more than the eventual national rule. A project in SPP is being studied under protocols that exist today. A project in MISO is being developed while the governing reliability requirements are still pending an effective date, with the show cause record not closing until mid December 2026. The same project, with the same load and the same flexibility commitments, has a materially different schedule risk depending on which market it sits in. Regional selection has become a schedule decision, not only a cost one.

The caution against over reading this is equally important. Abeyance is capped at 90 days, FERC said explicitly that it would scrutinise such requests heavily and disfavours extensions, and the rulemaking in RM26-4-000 sits above all six regional proceedings. The present divergence is a transitional state with a stated intention to converge. Building a long term strategy on a regional gap that the Commission has said it intends to close is a bet on regulatory inertia, which is not how this proceeding has behaved so far.

Curtailability becomes a product, and the evidence for it becomes a deliverable

The first and clearest consequence is that demand flexibility acquires a price. If loads that commit to curtail receive faster interconnection studies, potentially within 60 days, then the ability to curtail converts directly into project schedule, and schedule in this market converts directly into money. That creates demand for everything that makes curtailment real and provable: load management and control systems, on site generation and storage sized to ride through curtailment events, metering and telemetry that satisfies an operator, and the measurement and verification regime that turns a commitment into an auditable fact. Firms that sell any of these are now selling into a regulatory requirement rather than an efficiency pitch.

The second is documentation. A tariff entitlement that depends on demonstrating flexibility will, in practice, be administered through evidence. Interconnection customers will have to show what they can curtail, how fast, how often, under whose command, and how it is verified. That is a documentation product, and in this sector documentation products are chronically undersold because engineers regard them as overhead. The firm that arrives with a complete, operator ready evidence pack is removing the thing standing between the client and a 60 day study.

The third is cost allocation exposure, and it needs to be handled contractually rather than hoped away. FERC has not settled who bears network upgrade cost, what credits apply, or what financial security is required, and it explicitly deferred cost allocation for co-located load in April 2026. Any contract signed now that fixes a supplier's price against an interconnection cost that a future FERC order may reallocate is an uncompensated regulatory bet. The practical protections are familiar: a change in law clause that names this proceeding and its dockets specifically rather than relying on generic wording, a cost allocation contingency that is explicit, and milestone structures that do not oblige a supplier to carry a long lead procurement commitment through a decision it cannot influence.

The fourth is the transition risk on projects already in the queue. Because FERC has asked how to treat requests already under review when new requirements take effect, every in flight large load project carries an unquantified rule change risk. For a supplier this is a qualification question as much as a legal one: a client whose project is early in a queue in a region that has not yet filed its reformed tariff is a different credit and schedule risk from one in SPP operating under approved protocols. Pipeline weighting should reflect that, and at present most of it does not.

The fifth is where the sales motion should point. The counterparty for large load interconnection work is rarely the traditional utility procurement department. It is a developer or hyperscaler with a construction deadline, advised by regulatory counsel, buying against a docket calendar. The buying signals are public: a show cause response filed, a tariff with a requested effective date, an abeyance granted. A supplier that tracks the dockets for its target regions is reading its own clients' schedules months before an enquiry arrives, which is about as close to free pipeline intelligence as this sector offers.

One honest limit on all of this. The rulemaking in RM26-4-000 has not produced a final rule, the six regional records are not closed, and MISO's does not close until 16 December 2026. Everything above describes the direction of a proceeding, not a settled rule. Commercial plans should be built so they still work if the Commission lands softer than its preliminary findings suggest, because section 206 proceedings can and do end with narrower outcomes than their opening findings imply.