The Federal Energy Regulatory Commission’s October 15, 2026, open meeting will not be remembered for a single dramatic vote. It produced no new market design and no headline price. What it produced was the machinery that decides what markets can actually do next year: the budgets funding the reliability organization, a still-open compliance case on how generators connect to the grid, a cooperative’s conditional entry into two Western market constructs, and two project-level orders showing how slowly individual cases move through the system.
For context only: Fracmoo has already covered the PJM fights that drew the headlines — the rejection of key elements of PJM’s large-load proposals, the suspension of its Reliability Backstop Procurement, and the refiling fight over who pays for new capacity. This piece does not re-litigate them; it covers the rest of the Commission’s day.
The 2027 reliability budget: what $316 million buys
The most consequential action on the agenda was also the least quotable. In Docket No. RR26-3-000, the Commission accepted the 2027 business plans and budgets for NERC, the six Regional Entities, and WIRAB, and authorized billing invoices to fund fiscal year 2027 operations.
The numbers behind that sentence are large, and worth stating plainly because they are assessed, ultimately, on the industry the reliability organization oversees. In its August 24, 2026, filing, NERC proposed a 2027 budget of $140,044,000 for itself and a total Electric Reliability Organization statutory funding requirement of $316,816,272 to be funded by assessments, comprising $125,055,568 for NERC and $191,760,704 for the Regional Entities and WIRAB. The distinction matters: the budget is what NERC plans to spend, while the assessment figure is what must be collected after accounting for reserves, penalties, and other funding sources. Conflating the two misstates the cost of reliability oversight by tens of millions of dollars.
The Commission also granted limited waivers of the NERC Rules of Procedure to permit specified deposits into, and withdrawals from, assessment stabilization reserves, and approved WECC’s use of Peak Reliability Donation Reserves to fund a gas-electric interface study, artificial intelligence projects, and data management projects. Read skeptically, those are not footnotes: stabilization reserves smooth year-to-year swings in what entities are billed, and WECC’s approved uses point to where the West expects its next pressures — the gas-electric interface, and the data demands of a grid adding large loads and variable resources at once.
A budget acceptance is administrative in one sense — FERC did not redesign reliability standards here — but it is also a statement of priorities in staffing and programs: the 2027 plans fund the compliance, enforcement, assessment, and situational-awareness functions that determine whether standards are paper or practice, and the assessments authorized here are how they get paid.
PJM’s interconnection compliance: accepted in part is not accepted
The meeting’s other PJM action had nothing to do with capacity prices. In Docket No. ER24-2045-005, the Commission issued an order accepting in part, and rejecting in part, PJM’s proposed revisions to its Open Access Transmission Tariff intended to comply with Order Nos. 2023 and 2023-A and with the Commission’s April 2026 order on compliance, and it directed PJM to submit further compliance filings.
To understand why a partial acceptance matters, start with what Order No. 2023 was supposed to do. Issued in 2023, it reformed generator interconnection procedures across the country: moving from serial, first-come-first-served studies toward cluster studies, imposing study deadlines backed by penalties, and reforming how customers share study costs and post deposits. The theory was straightforward: the queue had become a graveyard of speculative projects and multi-year waits, and a market cannot build the generation it needs if the door to the grid is jammed. Compliance filings are where that theory meets each region’s tariff — and where the details deciding whether reform works or stalls get settled.
That distinction — between an order and a compliance filing — is the one this desk returns to most often, because it is where announcements go to be qualified. An order announces a policy; a compliance filing implements it, provision by provision. Accepting in part and rejecting in part is the Commission saying PJM got some of the implementation right and some wrong, and the wrong parts must come back. It is not a rejection of interconnection reform, nor an endorsement of PJM’s tariff as filed. It is a work order, and the further compliance filings the Commission directed are now the next document to watch.
The practical stakes are easy to state. Every month interconnection procedures remain contested is a month projects in PJM’s queue face uncertainty about study timelines, cost responsibility, and withdrawal penalties. The capacity debate asks what price will call forth new supply; the interconnection debate asks whether new supply, once it answers that price signal, can actually get studied, approved, and built. The October order does not answer that question. It keeps it open, with directions for another round of filings.
The West moves: Deseret into SPP West and EDAM
The clearest forward motion at the meeting came from the West, and from a participant most readers outside the cooperative world have never heard of. In Docket No. ER26-3333-000, the Commission accepted Deseret Generation & Transmission Co-operative’s notice of change in status and conditionally accepted its market-based rate tariff revisions, authorizing Deseret to participate in SPP West and in CAISO’s Extended Day-Ahead Market at market-based rates, subject to conditions.
The order, 197 FERC ¶ 61,028, is worth reading closely because its conditions are the substance. Deseret must offer its SPP West units at or below each unit’s mitigated energy offer, and its EDAM units at or below each unit’s Default Energy Bid as defined in the CAISO tariff. It must also submit compliance filings within 12 months of beginning SPP West participation and nine months of beginning EDAM participation. Those are not boilerplate: mitigated offers and Default Energy Bids are the market-power screens that keep a participant with local market power from setting prices it could not sustain competitively. Conditional acceptance means participation is permissible only inside the mitigation framework — and the paperwork proving compliance is still to come.
The timeline behind the order shows how market integration actually happens, in increments rather than announcements. Deseret told the Commission it became a market participant in SPP’s Western expansion — the new balancing authority area operated as part of a single, expanded SPP footprint — effective April 1, 2026, and in the PacifiCorp East area of EDAM effective May 1, 2026. It filed its notice on July 30, 2026; the Commission’s October order made the tariff revisions effective September 28, 2026. Participation thus preceded the tariff acceptance that formally recognized it, and the compliance filings testing the mitigation conditions are still months away. Anyone describing Deseret as fully cleared should add the Commission’s own qualifier — conditionally, subject to mitigation and compliance.
Why does one cooperative’s market status matter beyond its own service territory? Because SPP West and EDAM are the two competing visions of Western market organization, and every participant that joins both is a data point about whether the West is consolidating around a single market or learning to live with overlapping ones. SPP’s expansion, accepted in March 2025, extends its Integrated Marketplace westward; EDAM, accepted in December 2023, extends CAISO’s day-ahead market across the West without requiring full CAISO membership. A cooperative in both is operating in the seam between them — where settlement rules determine whether a megawatt offered in one market is double-counted or stranded in the other. Deseret’s order does not resolve the seam question. It adds a participant to it, under mitigation, with compliance filings to come.
Two small orders, two different lessons
Lost Island’s case is the more sympathetic of the two. In Docket No. ER26-3431-000, the Commission granted Lost Island a 24-month extension of its commercial operation deadline, from December 14, 2028, to December 14, 2030, and the order’s reasoning is worth stating fairly. Lost Island is developing a 200 MW wind facility in Palo Alto County, Iowa, under a Generator Interconnection Agreement — designated J1270 and dated June 5, 2023 — among Lost Island, MidAmerican Energy Company as transmission owner, and MISO as transmission provider. It sought a waiver because litigation in the Iowa Court of Appeals is challenging the Site Plan Review and Approval Permit issued by the Palo Alto County Board of Supervisors. Neither MISO nor MidAmerican opposed the waiver. The Commission’s order, 197 FERC ¶ 61,027, grants it: a project should not lose its interconnection position because a county permit is tied up in court, at least not when the grid operator and transmission owner both agree.
But the order also illustrates a structural fact about the queue that the Order No. 2023 reforms were meant to address. A 200 MW project with a 2023 interconnection agreement now has until the end of 2030 to reach commercial operation — seven years from agreement to deadline, with two granted by waiver. That is not a criticism of Lost Island, whose permit litigation is outside its control. It is a measure of how long the path from agreement to steel in the ground can take, even for a project that has cleared the queue — and a reminder that queue reform and project timelines are different problems.
Stony Creek’s case is the mirror image: not a project seeking more time, but a rate case finally reaching settlement. In Docket Nos. ER23-2595-000, ER23-2595-001, and EL23-98-000, the Commission approved Stony Creek’s contested settlement. Stony Creek operates a 52.5 MW wind facility in Somerset County, Pennsylvania, and filed a rate schedule in May 2019 for Reactive Supply and Voltage Control service — the service, defined in Schedule 2 of PJM’s tariff, by which generators supply the reactive power that keeps voltage stable. The filed annual revenue requirement was $310,326.82. The Commission accepted the schedule effective July 17, 2019, subject to refund, instituted a Section 206 investigation, and set the case for hearing and settlement procedures. The settlement was filed in April 2024. The October 2026 order, 197 FERC ¶ 61,029, approves it and directs a compliance filing within 30 days.
Seven years from filing to approved settlement is a long time for a $310,000 annual revenue requirement, and the length of the case is itself the point. Reactive power is one of the smallest, least glamorous services a generator sells — not energy, not capacity, and not the kind of product that makes headlines. But voltage support is a physical necessity: without it, the grid cannot maintain the voltage levels that keep equipment operating and power flowing. That a 52.5 MW wind farm’s reactive rate spent seven years in proceedings, including a contested settlement process with comments from PJM’s market monitor, says something about the cost of regulatory process itself. Settlements are supposed to be the efficient path, avoiding a full hearing by agreement on a rate. When even a settlement takes more than two years from filing to approval, the process imposes costs — legal fees, regulatory attention, uncertainty — that dwarf the revenue at stake. That is an argument for asking whether the process is proportionate to the dollars and reliability question involved.
What the meeting did not do — and what to watch
It is equally important to be clear about what the October meeting did not decide. It did not resolve PJM’s interconnection compliance, unconditionally clear Deseret’s market participation, set a new reliability standard, or approve a new market design. The budget order authorizes billing; it does not revisit the allocation methodology. The Deseret order authorizes participation; it does not decide the future shape of Western markets. That list of non-decisions is not a criticism — it is a description of a commission whose most consequential choices that month were incremental — and a warning against mistaking a conditional acceptance for a final one.
Three filings will tell whether the October meeting’s machinery actually moves. The first is PJM’s further compliance filing in the Order No. 2023 case: whether it cures the rejected provisions, and whether the Commission accepts the cure without another round of rejections, will determine whether PJM’s interconnection procedures finally conform to the reform ordered three years ago. The second is Deseret’s compliance filings — due within 12 months of SPP West participation and nine months of EDAM participation — which will test the mitigation conditions. The third is the Stony Creek compliance filing, due within 30 days, a small document that will close a seven-year case and test whether the settlement process can actually deliver finality.
The PJM capacity fight will continue to dominate headlines, and it should — who pays for new capacity in the country’s largest market is genuinely consequential. But the grid is also run, day to day, by the machinery the October meeting tended to: budgets funding oversight, compliance filings determining whether generators can connect, market authorizations letting participants trade, and settlements closing cases before they consume another seven years. The meeting did not make the grid cheaper, cleaner, or more reliable in a single vote. It kept the institutions that do those things funded, open, and moving — conditionally, incrementally, and mostly out of sight.