FERC MISO Tranche 2.1 Cost Recovery PJM: No Bid Required

FERC approved MISO Tranche 2.1 cost recovery for PJM-side facilities on August 14, and the part with immediate commercial consequence is not the money. It is that the companies who will build the work are already named, and none of them had to win it. The order lands in docket ER26-1538-000, and it settles a question the plan had been stuck on since MISO’s board approved Tranche 2.1 in December 2024: who pays for the pieces of a MISO portfolio that have to be built inside PJM.

For anyone who sells into transmission construction, that is the whole story. Under a competitive solicitation an incumbent has to win the right to build, and the supply chain waits out developer selection, protests, and the live possibility that a merchant transmission company takes the project. Here the counterparties are fixed as of the order. There is no selection to wait out.

Approval was never the missing piece on interregional transmission. A recovery mechanism is what converts an approved plan into a funded one.

What the order actually approved

MISO filed on February 27, 2026 under Section 205 of the Federal Power Act. The mechanism is a set of Cost Recovery and Funding Agreements, which the filing calls CRAF Agreements, and the shape is unusual enough to be worth stating precisely: MISO funds the facilities, the PJM transmission owner constructs, owns and operates them, and the finished assets go under PJM’s functional control. Each PJM owner develops an annual revenue requirement, submits it to MISO, and MISO recovers it from MISO customers under a new Schedule 26-J.

Schedule 26-J is built on substantially the same multi-value project cost allocation methodology MISO already uses, with two substantive deviations: it uses the non-MISO owner’s rate template to set the revenue requirement, and it drops the grandfathered-agreement energy term from the usage rate divisor, because that term does not apply to a non-MISO owner.

MISO’s filing names five counterparties. Commonwealth Edison Company, Indiana Michigan Power Company, AEP Indiana Michigan Transmission Company, American Transmission Systems Incorporated and Duke Energy Ohio. Trade coverage of the August order reported dollar figures for two of the five, putting Commonwealth Edison at roughly $904 million of work and Duke Energy Ohio at $5.3 million. We could not open the order text itself to confirm whether that $904 million is total installed project cost or ComEd’s recoverable share, and the distinction matters if you are sizing an equipment budget from it. Treat the reported figure as the program’s order of magnitude, not as a bill of materials.

One structural note that most coverage skipped. ER26-1538 is the tariff framework. The individual CRAF Agreements were filed in their own dockets, ER26-1676 and ER26-1761 among them, and FERC’s acceptance of the framework was written as a condition of those agreements taking effect. If you are tracking this, the framework docket tells you the rules and the agreement dockets tell you the scope.

Why the transmission competitive solicitation exemption held

MISO’s argument is jurisdictional rather than economic. Its authority as transmission provider extends to the MISO transmission system only, so it can neither run its Competitive Developer Selection Process for external facilities nor designate an owner for them. PJM transmission owners, for their part, are under no obligation to build anything MISO wants. What is left is a voluntary contract, which is what a year of arms-length negotiation between MISO, PJM and the owners produced.

The second half of the reasoning is the part with teeth, and it lives in PJM’s rulebook rather than MISO’s. Because these facilities are not required for PJM’s own reliability, operational performance, public policy or economic criteria, they are classified as Supplemental Projects under PJM’s governing documents. Under the PJM tariff, each transmission owner has the right to build and own Supplemental Projects in its zone. So the absence of a bid is not a waiver granted case by case. It follows from how the work got classified.

The filing then closes the gap in MISO’s own tariff, amending Attachment FF to state that eligible projects located in another transmission provider’s region will not be subject to MISO’s competitive process. That amendment is the durable part. It is written to cover “any other similar agreements that may be filed in the future,” which means this is a template and not a one-off.

The objection, and why a buyer should read it

The Industrial Energy Consumers of America and the Electricity Transmission Competition Coalition fought this and lost. Their answer is blunt: the filing “attempts to update the language of its Tariff so as to allow a loophole for MISO to cherry-pick developers and avoid the competitive solicitation process,” and a Section 205 filing “does not operate as a backdoor option for utilities to bypass their existing tariffs by making changes after the violation has already occurred.” They asked FERC to reject it outright and order MISO into the Attachment FF process.

This is the same fight we covered in April, when nine utilities asked FERC to suspend competitive bidding across MISO and SPP in docket EL26-58. That complaint argued competition adds 16 to 20 months. The competition coalition answered with its own numbers on cost outcomes. We laid out both sides of the Order 1000 record then, and the honest reading has not changed: each side has real data and neither has the whole picture.

What changed on August 14 is the direction of travel. The complaint route is still pending. The tariff route worked. A buyer should take from that a planning assumption rather than a policy opinion: on interregional seam work, the incumbent is now the likely builder, and the schedule is set by the incumbent’s own capital plan rather than by a solicitation calendar. That is a different, and earlier, forecasting signal than waiting for an RFP to appear.

What the MISO 765 kV backbone actually orders

Tranche 2.1 is 24 multi-value projects comprising more than 300 individual facilities, valued around $21.8 billion, creating a 3,631-mile 345 kV and 765 kV backbone across the MISO Midwest subregion. MISO’s filing puts the benefit-cost ratio at 1.8 to 3.5 and the in-service target at 2032 to 2034.

The PJM-side slice is smaller and far more legible. MISO’s filing describes twenty facilities inside Tranche 2.1 project numbers 31, 33, 35, 36, 40, 41 and 42, in exactly two forms:

1. Transmission tie-lines connecting a substation under MISO’s functional control to a substation under PJM’s functional control.
2. Interconnecting facilities located inside the substation under PJM’s functional control.

Then a second category on top of that, the Do No Harm projects, which are upgrades to existing PJM facilities identified through PJM’s do-no-harm review and the owners’ own criteria-violation analyses. Those were not planned as part of the portfolio. They exist because connecting Tranche 2.1 to PJM creates reliability impacts on the PJM side that somebody has to fix.

Read as a procurement list, those three categories are not the same business. Tie-lines are structures, conductor and line hardware. Interconnecting facilities inside an existing substation are breakers, disconnects, instrument transformers, protection and relaying, and bus work, all installed into a live yard. The Do No Harm work is brownfield substation retrofit, which under MISO’s own tariff language covers replacing plant inside an existing footprint, adding plant within it, or expanding the fence line. The brownfield category is the one worth watching, because it is the least visible in any project list and the most likely to reach distribution-adjacent suppliers.

The in-service window is the number to carry into a schedule. Work targeted for 2032 to 2034 gets ordered years before that, into the same high-voltage supply chain that the Permian 765 kV program in Texas is already loading. We wrote about that collision when the interregional portfolios stacked up behind an energization air pocket, and the FERC MISO Tranche 2.1 cost recovery PJM order is the event that pushes one of those portfolios from planned to funded. Two simultaneous 765 kV backbone programs against one high-voltage manufacturing base is the constraint story, and a municipal or cooperative buyer shopping transmission-class equipment in either footprint is queued behind both.

The move for a smaller buyer

Nothing here is addressed to a muni or a co-op. That is exactly why it is useful.

An order that names its builders removes the single biggest source of noise in transmission forecasting, which is not knowing who the buyer will be. Commonwealth Edison’s procurement organization is a known counterparty with a known footprint today rather than after a developer selection. ComEd is also a utility we have watched deliver 345 kV substations four months ahead of a backlogged schedule, so its ordering behavior is already partly readable.

Three practical reads follow.

First, watch the CRAF agreement dockets rather than the framework docket. The framework tells you the rules; the agreements carry the facility lists and the schedules.

Second, treat the Do No Harm category as the leading indicator. Greenfield 765 kV is a long lead and a closed supplier set. Brownfield upgrades at existing substations move faster, use more ordinary equipment classes, and land sooner.

Third, and this is the general rule worth keeping past this docket: interregional transmission cost allocation is the gate, not project approval. MISO could plan facilities in PJM and could not order them built. Approval had been in hand for twenty months. The thing that unlocked construction was a mechanism for who recovers the cost. If you are watching another seam, watch for the cost-recovery filing, because that is the document that converts a plan into an order.

Regulatory filings run months to years ahead of the RFQ that follows them, and the cost-recovery docket is usually the earliest readable date on the whole program. The Feeder is our free monthly briefing on what changed in the record and what it means for procurement schedules.

Related Reading

• FERC Order 1000 Under Fire: Utilities Push to Dismantle Competitive Transmission Bidding
• Interregional Transmission Just Had Its Proof Week
• Transmission Substation Procurement: ComEd Beat the Backlog