title: "Large Load Interconnection: What to Model Before FERC Acts on RM26-4 in June 2026"
On April 16, 2026, FERC stated it would act on its large load interconnection rulemaking, Docket RM26-4, by the end of June 2026 — meaning FERC will issue some form of regulatory action (ANOPR, NOPR, or order) by that date, not necessarily a final rule. For any data center developer, hyperscaler procurement team, or generator dealer staging behind-the-meter equipment, that date anchors the next decision point for whether and how FERC may move toward standardized treatment of large load interconnection rights, network-upgrade cost exposure, and staged-energization options.
The stakes are concrete. ERCOT reported large-load interconnection requests climbing from roughly 63,000 MW in December 2024 to 226,000 MW by November 18, 2025. Dominion Energy's queue contains roughly 70 GW of new load against a 24.6 GW current peak. NERC's corrected 2024 Long-Term Reliability Assessment forecasts North American summer peak demand to rise by more than 132 GW over the 10-year horizon — the highest growth rate in two decades. Procurement teams that treat large load interconnection as a utility back-office process will lose schedule and capital to teams that treat it as the gating risk on the project.
Key Takeaways
- June 2026: FERC stated it will act on RM26-4; status is ANOPR with comments solicited, outcome uncertain.
- 20 MW: federal threshold under consideration for standardized large load interconnection rules.
- 100%: caused network-upgrade cost assignment under consideration for interconnecting loads, with possible crediting.
- 60 days: expedited study window raised as a question in the DOE filing for curtailable loads.
- Dec 18, 2025: FERC's PJM co-location order is already shaping co-located data center deals today.
What changed: FERC's June 2026 action window on RM26-4
The procedural sequence matters. The Department of Energy issued its Section 403 proposal on October 23, 2025, directing FERC to consider a rulemaking on direct transmission interconnection of large loads. FERC subsequently stated on April 16, 2026 that it would act on RM26-4 by the end of June 2026; the supporting RM26-4 docket page contains the ANOPR materials and comment record.
This is an Advance Notice of Proposed Rulemaking. It is not a NOPR, not a final rule, and not enforceable on transmission providers today. Comments solicited under the ANOPR will shape — but do not predetermine — what FERC ultimately issues. Any procurement decision premised on the ANOPR terms surviving intact carries rulemaking risk.
The practical read: budget and schedule against the PJM co-location order that already exists (see below), and treat RM26-4 outcomes as a forward sensitivity, not a baseline.
What the rulemaking would standardize: 20 MW threshold, 100% caused-cost, expedited studies
DOE's filing, if FERC adopts it substantially, would apply standardized large load interconnection rules to loads greater than 20 MW interconnecting directly to FERC-jurisdictional transmission. The threshold is under consideration; the ANOPR explicitly solicits comment on raising or lowering it.
Four substantive provisions matter for equipment and project planning:
- 100% caused-cost assignment. DOE's filing raises whether interconnecting large loads should be assigned 100% of caused network-upgrade costs, with potential crediting back. That moves transmission upgrade exposure squarely onto the load customer's pro forma.
- Expedited studies for curtailable loads. The filing raises whether expedited studies could complete in as fast as 60 days for loads accepting curtailability. This is a question, not a finalized timeline.
- Hybrid load-generation facilities would be studied on a net injection/withdrawal basis. DOE's illustrative example: a 500 MW load with a 600 MW generating facility could request no withdrawal rights and 100 MW of injection rights. This is illustrative within DOE's filing, not a generic rule.
- Option-to-build comparable to the generator interconnection regime, letting load customers self-construct certain network facilities.
For procurement: a curtailable-load posture trades operational firmness for schedule. That tradeoff is exactly where on-site generator pricing and behind-the-meter gas turbine economics get re-evaluated, because curtailment hours should be modeled as potential runtime on owned generation — net of load shifting, batteries, PPAs, or other mitigation the buyer brings to the deal.
The PJM co-location precedent: December 2025 order shapes deals now
FERC has already acted on a discrete piece of the large load interconnection problem. On December 18, 2025, in EL25-49-000, FERC directed PJM to develop tariff treatment distinguishing full network service, no-withdrawal co-location, and intermediate cases. This was preceded by FERC's November 1, 2024 rejection of the Susquehanna Nuclear ISA expansion from 300 MW to 480 MW. For supplemental context on the commission's reasoning, see Commissioner Rosner's concurrence on the PJM co-location action.
Two provisions in the December 2025 order have immediate procurement consequences, subject to PJM's compliance filings. The framework directs that generators cannot remove capacity from the grid to serve co-located load until necessary reliability upgrades are in service, with associated upgrade costs to be allocated to the existing generator. The order also contemplates an interim non-firm service mechanism so co-located load and generation can access the grid faster while upgrades are pending.
For data center developers pursuing bring-your-own-power deals at existing generation sites in PJM, the upgrade-cost allocation on the host generator changes the commercial split, and the interim non-firm service window changes how bridge-power fleets are sized.
NERC's parallel track: reliability standards for large load interconnection
The reliability layer is moving in parallel. NERC formed its Large Loads Task Force in August 2024 and published an incident review of a roughly 1,500 MW simultaneous load loss event reviewed in January 2025. NERC notified FERC on March 20, 2026 that it intends to file revised registry criteria and Reliability Standards for large loads by December 31, 2026.
The practical implication: NERC's planned filing could expand registration criteria and reliability obligations for certain large loads, potentially affecting ride-through, monitoring, operations, controls, and protection requirements. That would change commissioning scope, control-system specs, and protective relaying at the customer substation.
Regulatory Watchlist
| Docket / Action | Status | Date | Buyer Impact |
|---|---|---|---|
| FERC RM26-4 (large-load ANOPR) | ANOPR, comment-stage | FERC stated it will act by June 2026 | Could standardize 20 MW threshold, cost allocation, study timelines |
| FERC EL25-49-000 (PJM co-location) | Order issued; compliance filings pending | Dec 18, 2025 | Directs PJM to develop co-located service classes; framework subject to compliance filings |
| FERC ER24-2172 (Susquehanna ISA) | Rejected | Nov 1, 2024 | Blocks 300→480 MW co-located expansion absent new framework |
| NERC LLTF standards filing | Filing target | Dec 31, 2026 | Potential NERC registration, ride-through obligations for large loads |
Where the procurement risk shows up
The risk is not abstract. It shows up in three line items.
Equipment lead times against staged energization. If interim non-firm service or curtailable-load expedited studies are how a project gets early MW, the on-site generation fleet — for example, diesel and gas reciprocating sets (Standby or Prime, depending on dispatch assumptions) and gas turbines (ISO-rated / continuous-service) for larger blocks — should be ordered against the non-firm energization date, not the firm-service date. That may require earlier procurement planning if equipment lead times are tight.
Network-upgrade cost exposure on the customer. A caused-cost regime could move more upgrade exposure into the customer's capital stack, depending on the final tariff design and regional practice. Buyers should pressure-test interconnection studies for transformer and medium-voltage switchgear scope before signing a facilities study agreement.
Curtailment hours as generator runtime. Accepting curtailability to win a 60-day study window can convert grid risk into fuel and maintenance cost on owned generation, depending on how load shifting, storage, and supplemental PPAs are layered in. Tier 4 emissions compliance, fuel logistics, and lifecycle overhaul reserves all move with curtailment-hour assumptions.
SecondWatt tracks pricing, availability, and procurement risk across generators, gas turbines, transformers, and switchgear most affected by these large load interconnection shifts — including the equipment classes most often deployed for bridge and behind-the-meter service while transmission upgrades are pending, with generator capacity tracked as MW (Standby/Prime) and turbine capacity tracked as MW (ISO-rated / continuous-service).
What buyers should do now
- Re-baseline the interconnection assumption. If the project is >20 MW and tied to FERC-jurisdictional transmission, model both the current regional process and a post-RM26-4 sensitivity with 100% caused-cost and curtailability options.
- In PJM, read the December 2025 order against your co-location LOI. Confirm who bears the reliability-upgrade cost and how interim non-firm service maps to your ramp schedule.
- Lock bridge-power equipment against the non-firm date. Use the power system configurator to size generator MW (Standby/Prime) and switchgear scope against staged MW.
- Track NERC's December 31, 2026 filing. If future NERC registration criteria capture your facility, control-system and protection scope changes before commissioning.
- Pressure-test capital allocation. A caused-cost regime could shift material capital exposure in transformer and substation scope onto the customer — get that scope into the deal model before the facilities study, not after.
The regulatory window between now and June 2026 is short. Procurement decisions made in that window — generator orders, transformer reservations, co-location LOIs — will be executed while FERC is deciding whether to advance an ANOPR, NOPR, order, or final rule. Build the sensitivity into the deal, not into a post-mortem.