FERC RM26-4: What the June 2026 Large-Load Interconnection Rule Means for Data Center Developers

FERC will issue standardized interconnection rules for loads above 20 MW by the end of June 2026. Developers who haven't priced this into their queue strategy and co-location economics are operating on borrowed time.

On April 16, 2026, the Federal Energy Regulatory Commission issued a formal order committing to act in Docket No. RM26-4-000 by the end of June 2026. The docket addresses how large electrical loads, specifically those above 20 megawatts connecting directly to FERC-jurisdictional interstate transmission, enter and progress through interconnection queues.

This will be the first standardized federal framework for large-load interconnection in U.S. history. The rules for how generators connect to the grid have existed for decades. The rules for how large loads, including data centers, connect have been governed by a patchwork of regional tariffs, case-by-case approvals, and informal utility practices. That changes in June.

For data center developers with projects in PJM, MISO, SPP, CAISO, or NYISO, the rule sets a new baseline for queue strategy, co-location economics, and behind-the-meter power arrangements. Projects underwritten under prior assumptions need to be revisited.

What the Rule Is Expected to Contain

The FERC Advance Notice of Proposed Rulemaking outlined 14 guiding principles. Based on the comment record, the SPP HILL precedent from January 2026, and analysis by Holland & Knight and Steptoe & Johnson, the June order is expected to standardize the following:

Queue entry requirements for large loads. Uniform study deposit requirements, readiness standards, and withdrawal penalties for loads above 20 MW, mirroring what generators already face under FERC's pro forma Large Generator Interconnection Agreement and Procedures. Developers who currently hold queue positions without firm site control or financial assurance should model the impact of retroactive or transition-period requirements.

100% caused-cost assignment. Large-load interconnection customers would bear 100% of the cost of network upgrades required for their connection, with possible crediting mechanisms. This moves transmission upgrade exposure directly onto the developer's pro forma. For projects that assumed some cost sharing with other queue entrants or with ratepayers, the revision can be material.

Expedited pathway for curtailable loads. The ANOPR proposed a study window as short as 60 days for loads willing to accept contractual curtailability, meaning the utility can reduce delivery during grid stress periods. This is a significant compression from standard study timelines, which currently run 18 to 36 months in most RTOs.

Hybrid facility treatment. Co-located load and generation facilities, including data centers paired with on-site natural gas, nuclear, or solar, would be studied on a net injection basis rather than full capacity. FERC's illustrative example: a 1,000 MW generator paired with a 900 MW data center can request interconnection rights for only the 100 MW of net grid injection. This reduces network upgrade scope, compresses study timelines, and improves cost certainty for hybrid projects.

Threshold ambiguity. The proposed 20 MW threshold has drawn significant comment, with alternatives ranging from 30 MW to 300 MW proposed. The final threshold matters: a higher threshold would exempt smaller data centers from the new framework entirely. Developers should model both scenarios.

What This Means for Queue Strategy

The withdrawal penalty structures expected in the final rule will make speculative queue reservations more expensive. The current environment in which developers hold multiple queue positions simultaneously as options, withdrawing losing positions, will face higher financial friction. Projects with genuine offtake commitments and real capital behind them benefit from this. Projects staged as options are exposed.

Curtailability agreements will become a substantive commercial tool. A 60-day expedited pathway in exchange for accepting grid curtailment hours changes the make-vs-buy calculation on backup generation. If curtailment events average 150 to 250 hours per year at a large MISO or PJM site, the developer must model whether owned backup generation covering those hours is cheaper than the premium for an uncurtailable queue position.

Queue positioning should now be sequenced with site control. Several RTOs have already moved toward requirements that queue applicants demonstrate site control before advancing to facilities study. The RM26-4 framework is expected to standardize this expectation. Developers who file queue applications without confirmed site control are likely to face new deposit and milestone requirements that accelerate the development timeline pressure.

Co-Location Economics Need to Be Re-Underwritten

The December 2025 PJM co-location order and the anticipated FERC rule together represent a significant reset for the economics of bringing data centers to power sources rather than bringing power to data centers.

Under the prior informal framework, co-located generation at an existing power plant could structure its interconnection at full nameplate capacity, effectively reserving transmission rights for both the generator and the data center load. The net injection approach changes that. A data center co-located with a 500 MW generator that consumes 400 MW has 100 MW of net injection rights, not 500 MW. The transmission infrastructure cost basis shrinks significantly.

This is favorable for hybrid project economics where most power is consumed on-site. But it requires developers to model load curtailment hours, ramp rates, and redundancy requirements against the new reliability-upgrade cost exposure that comes with net-injection status.

Projects that have term sheets or LOIs structured under the prior co-location framework should be audited for the cost implications of the expected rule changes before those agreements advance to construction financing.

ERCOT Is Different

FERC's jurisdiction does not extend into ERCOT, which is an islanded grid under the Texas Public Utility Commission. The large-load interconnection rules will not apply to Texas data center development directly.

Developers building across multiple markets need a bifurcated strategy. ERCOT operates under its own interconnection procedures and has its own large-load dynamics, including ERCOT's 2026 caution that projected AI-driven power demand may not fully materialize on the timeline originally forecast. ERCOT queue management and load forecasting are governed separately and will not mirror the RM26-4 framework.

The practical implication is that Texas remains a relevant market for behind-the-meter and off-grid development strategies, where the FERC interconnection framework does not apply and private generation can advance on state permitting timelines.

What Developers Should Do Before June 30

The action items are specific and time-sensitive.

Re-baseline interconnection assumptions for every FERC-jurisdictional project above 20 MW. Model two scenarios: the current regional process and a post-RM26-4 sensitivity with 100% caused-cost assignment and curtailability options. Identify which projects have financial exposure to the caused-cost scenario and whether the pro forma survives.

Audit co-location LOIs and term sheets. Confirm who bears the reliability-upgrade cost under the expected PJM and MISO frameworks, and how interim non-firm service maps to the project ramp schedule. Agreements that assumed a different cost-sharing structure need to be renegotiated or repriced.

Map queue positions against site control. Any queue position that lacks firm site control should be evaluated for whether the expected withdrawal penalty structure makes that position tenable. Releasing positions that cannot be advanced to site control before the new requirements take effect may be preferable to paying escalating withdrawal penalties.

Pressure-test electrical equipment scope. A caused-cost regime shifts transformer and substation upgrade costs onto the load customer. Those costs should be in the facilities study scope and the deal model before the facilities study agreement is signed, not discovered as surprises after execution.

Model curtailability economics for qualifying projects. For projects where a 60-day expedited pathway is commercially relevant, run the curtailment exposure against owned generation costs. The crossover point determines whether accepting curtailability is NPV-positive relative to a standard queue position.

The June 2026 order will be the most consequential FERC action on load interconnection in the Commission's history. The developers who have done the preparation work will enter the second half of 2026 with cleaner deal structures. The developers who have not will be reading the final rule reactively while their deal timelines slip.