On October 8, the Federal Energy Regulatory Commission accepted an interconnection agreement for the North Plains Connector, the proposed high-voltage direct-current line that would tie the Western and Eastern interconnections together across Montana and North Dakota. The agreement, among the Southwest Power Pool, Basin Electric Power Cooperative, and North Plains Connector LLC, was scheduled to take effect October 11. It is a modest document as federal actions go — a contract filing, not a ribbon-cutting — but it is the kind of milestone that separates projects actually advancing from those that exist only as lines on a map.
The North Plains Connector matters because of where it would go, not just how big it is. The United States operates, in effect, as two giant grids that barely touch. The Eastern and Western Interconnections are linked today by seven small back-to-back direct-current ties with a combined transfer capability of about 1,320 megawatts — a rounding error against systems with hundreds of gigawatts of generating capacity. The North Plains Connector alone would carry 3,000 megawatts in either direction, more than doubling everything that currently crosses the seam. If it is built, it will be the first large-scale, long-distance HVDC line to span the divide.
What the line is
The project is a roughly 422-mile, 525-kilovolt HVDC overhead line running from an existing substation near Colstrip, Montana, to two eastern endpoints in North Dakota: one near St. Anthony and one near Center. The direct-current segment itself runs about 339 miles between two AC/DC converter stations — one near Colstrip, the other in Morton County, North Dakota — with alternating-current lines fanning out from each converter station to the points where the project meets the existing grid. In Montana, short 500-kV lines link the western converter station to the Colstrip substation. In North Dakota, a roughly 22-mile double-circuit 345-kV line would run to a future Southwest Power Pool switchyard in Morton County, to be built and owned by Basin Electric, and a roughly 51-mile double-circuit 345-kV line would run to a future Center substation in Oliver County, to be developed by Minnesota Power.
That three-ended design is what makes the project unusual. Most transmission lines connect two points; the North Plains Connector is designed to interface with three regional systems at once — the Western Electricity Coordinating Council footprint through Colstrip, the Southwest Power Pool through St. Anthony, and the Midcontinent Independent System Operator through Center. The developer describes it as the first HVDC connection spanning three regional markets in the United States. The practical consequence is that power could move not only east-west across the seam but between SPP and MISO, two Eastern Interconnection markets whose own seam is a perennial source of congestion.
The developer is North Plains Connector LLC, a subsidiary of Grid United, jointly developing the project with ALLETE. Around it sits a consortium of nine utilities that have signed agreements tied to the project: ALLETE, Avista, BHE U.S. Transmission, Great River Energy, Montana-Dakota Utilities, Minnkota Power Cooperative, NorthWestern Energy, Portland General Electric, and Puget Sound Energy. The arrangements vary — NorthWestern Energy, for example, signed a nonbinding memorandum to own 10 percent of the line, or 300 megawatts of its capacity, while Minnkota signed a memorandum for 150 megawatts — but the shape is the anchor-tenant model this desk has described before: contracted customers underwriting a merchant line’s revenue so it can be financed without a regional cost-allocation fight.
The full project is estimated at about $6 billion, with the North Dakota portion accounting for roughly $3.2 billion. On the public side, the project received a $700 million grant from the Department of Energy’s Grid Resilience and Innovation Partnerships program, awarded in 2024 to support the Montana portion. The developer’s stated schedule calls for major construction to begin in 2028, the line operational in 2032, and roughly 800 workers at the peak of construction. Hitachi Energy is already performing early-stage engineering under an agreement announced in October 2025, covering technical specifications for the converter stations and system modeling for integration with MISO, SPP, and the West.
What FERC’s acceptance does — and does not — decide
It is worth being precise about what happened on October 8, because transmission milestones are routinely overread. FERC accepted an interconnection agreement — the contractual terms governing how the North Plains Connector plugs into the grid at its eastern end, where SPP and Basin Electric facilities are involved. Under Section 205 of the Federal Power Act, such agreements are filed with the Commission, which reviews them to determine whether their rates, terms, and conditions are just and reasonable. Acceptance means the contract can go into effect as filed. It does not mean FERC has approved the line.
What the acceptance does not decide is a long list, starting with siting: siting authority rests with Montana and North Dakota, not FERC. It does not allocate the project’s costs to ratepayers or determine who ultimately pays for the line. It does not resolve the MISO-side interconnection arrangements at Center, which involve different parties. And it does not guarantee construction. An accepted interconnection agreement is a necessary piece of paper for a project that intends to interconnect — the electrical equivalent of a signed lease on a building that still needs a construction permit — but plenty of projects have collected such papers and never been built.
None of that makes the step trivial. Interconnection agreements are where the abstract physics of a new line meets the operating reality of the existing grid: protection schemes, metering, dispatch coordination, the division of responsibilities when something trips. Getting SPP, Basin Electric, and the developer to a filed, accepted agreement means the technical and commercial terms of the eastern connection are settled enough to write down. For a seam-crossing project, where no single grid operator controls both ends, that kind of bilateral settlement is the unglamorous work the whole enterprise depends on.
Why the seam matters
The case for crossing the seam rests on two ideas: diversity and timing. The Eastern and Western Interconnections experience different weather, different renewable output patterns, and different demand peaks. The sun sets in the West hours after it sets in the East; a cold snap that stresses one grid often leaves the other with spare capacity. A transfer link lets each system lean on the other in exactly the hours when its own resources are scarcest. That is the geographic-diversity argument from the transmission bottleneck explainer: interregional transfer capacity is effectively shared insurance, cheapest when the risks on either side are least correlated.
The evidence for the value is unusually strong for a transmission proposition. The Department of Energy-backed Interconnections Seam Study, a multi-year modeling effort by national laboratory researchers, found that increasing transfer capacity between the interconnections could enable more economically efficient and flexible exchange of power across the country, with scenarios showing up to $2.50 in benefits for every $1 of cost. The study’s headline insight was not that the seam could be crossed — engineers have known that for decades — but that the economics of crossing it at scale were favorable under a wide range of assumptions. The binding constraints were institutional, not technical.
The renewables argument runs in parallel: some of the country’s best wind sits in the Great Plains, near the seam itself; some of its best solar sits in the Southwest. A seam-crossing line does not just move power between grids — it widens the market for the generation on either side, letting a windy night in the Dakotas serve load in the Pacific Northwest, or Western solar serve an Eastern evening peak. That is the same logic that has driven every major interregional proposal for a decade: the resource is in one place, the load is in another, and the line is the arbitrage between them.
There is also a reliability argument that has sharpened with experience. In extreme-weather events, the regions that fared best were often those that could import power from neighbors not simultaneously stressed. The seam is, in this sense, the largest unhedged risk on the American grid: two continental systems that cannot help each other at scale in the hours when help is most valuable. A 3,000-megawatt link does not solve that problem — it is a fraction of either system’s peak demand — but it changes the worst case from “nothing can cross” to “something can.”
What still has to go right
The obstacles ahead are the familiar ones from the transmission bottleneck, now in their concrete, project-specific form. Start with siting. In Montana, the project applied in September 2024 for a Major Facility Siting Act Certificate of Compliance. The Department of Energy and the Montana Department of Environmental Quality issued a final environmental impact statement on August 28, 2026, after a draft statement in January 2026 and a 45-day public comment period. Montana regulators said the record of decision and the siting certificate — which is required before construction can begin — could be issued no sooner than 15 days after the final statement. In North Dakota, the developer filed its application with the Public Service Commission in February 2026 for a certificate of corridor compatibility and route permit covering about 168 miles of HVDC line and about 74 miles of associated AC lines across six counties; public and technical hearings were held in early September, and as of the last public docket entries, no final order had been issued.
Land is the quiet variable underneath the siting proceedings. The developer told North Dakota regulators that it had obtained the required conditional or special-use approvals from the six affected counties and Havelock Township, and that land options were in place for 99 percent of the North Dakota route. Those are applicant representations, not independently audited findings, but they matter: voluntary land agreements are the difference between a siting case decided on its merits and one that becomes a referendum on condemnation. The developer says it made roughly 400 route changes from its initial concept in response to landowner input — slow, unglamorous work that rarely appears in announcements but often determines whether a line is built.
Financing is the second obstacle. The anchor-tenant consortium is the project’s answer to the cost-allocation problem that has killed so many regional lines: instead of litigating who benefits and by how much, the developer lined up utilities willing to contract for capacity. But memoranda of understanding are not final investment decisions. The consortium members’ commitments must harden into definitive agreements, and the project must reach financial close on a roughly $6 billion build — in a market where converter stations, transformers, and construction crews are all in short supply. The $700 million federal grant helps; it does not close the gap.
Construction itself is the third obstacle, and the timeline is honest about it: even on the developer’s schedule, the line would not energize until 2032, six years from now. That is the transmission bottleneck doing what it always does — converting a straightforward engineering task into a decade-long institutional marathon. A converter station is not a commodity purchase; it is a multi-year procurement from a thin global supplier base. The project’s engineering agreement with Hitachi Energy is a hedge against exactly that lead time.
The test
What makes the North Plains Connector worth watching is that it tests every theory of how interregional transmission gets built in the United States, simultaneously. If the consortium model works — if contracted customers can carry a $6 billion seam-crossing line to completion without a regional cost-allocation proceeding — it becomes a template for the other seam projects that exist today only as proposals. If the Montana and North Dakota siting processes conclude on schedule, it demonstrates that two-state permitting, while slow, is navigable when a developer does the landowner work early. And if FERC’s acceptance of the interconnection agreement holds without a rehearing fight, it shows that the seams between grid operators can be bridged contract by contract, even without a single institution charged with planning the continental grid.
Failure would teach something too. The project has, by the standards of American transmission development, nearly everything going for it: a federal environmental review complete, a federal grant, a nine-utility consortium, land options across nearly the entire North Dakota route, and now an accepted interconnection agreement. If a project with that tailwind still stalls — on financing, on a siting condition, on a converter-station supply chain — it will confirm the darkest reading of the bottleneck: that the system is not merely slow but structurally incapable of building the lines its own studies say are worth two and a half times their cost.
For now, the honest characterization of October 8 is narrower than either the celebration or the skepticism. A contract was accepted. A line that would more than double the transfer capacity between the two halves of the American grid cleared one of its many gates. The gates that remain — state certificates, definitive customer contracts, financing, construction — are the ones that have stopped transmission lines before, and they will decide this one. The seam has waited a century for a wire across it. It will wait a few more years, and the wait will be decided in hearing rooms and boardrooms, not in engineering labs. That has always been the bottleneck’s lesson, and the North Plains Connector is its latest exam.