When this desk last wrote about the Bipartisan American Affordability and Jobs Act, S. 5653, the question was whether the Senate would take up the bill at all. That question is answered. On Monday, November 9, the Senate voted 73–25 for cloture on the motion to proceed, clearing the 60-vote threshold with 22 Democrats joining nearly all Republicans. But the bill now on the floor is not quite the bill introduced on September 30: a 494-page manager’s amendment released on Saturday, November 7, rewrote parts of the transmission title in ways that matter more to developers than the vote count.
The amendment is the reason the politics moved. On November 2, the National Rural Electric Cooperative Association and the American Public Power Association wrote to Senate committee leaders offering “strong support” — contingent on an amendment the leaders then released on November 7. The amendment, the two groups said, recognizes the role of local governance in the co-ops’ not-for-profit business model and “avoids new, burdensome Federal Energy Regulatory Commission regulation over electric cooperatives and public power utilities.” It also maintains the existing regional planning process in which co-op participation is voluntary.
What the amendment took away from developers
The most consequential transmission change is a delay, and it lands squarely on the provision this desk examined on November 4. As introduced, Section 2101 let developers of lines rated 345 kilovolts or above file with FERC simultaneously with their state application, so the federal track ran alongside the state track from day one. The manager’s amendment strips that simultaneous-processing provision wholesale. Developers must now spend a year seeking state approval before applying to FERC for the federal backstop.
That change reframes the Wisconsin test case from the earlier piece. MariBell and BECI, the two proposed 765-kilovolt lines in MISO’s Tranche 2.1 regional plan, have not yet reached the permit stage — MariBell’s developers expect to apply in the fourth quarter of 2026, BECI’s developer in early 2027 — and the Wisconsin Public Service Commission has not denied anything, because it has not yet been asked. Under the amended bill, the commission gets a year of unshadowed process first.
The amendment gives developers something in return, and it is not trivial. As introduced, the federal eminent domain power that comes with a FERC permit did not reach state-owned property — a gap that, in states holding millions of acres, could have forced lines to be rerouted many miles around state parcels. The manager’s amendment extends the backstop authority to state-owned land, letting developers route along state-owned rights-of-way rather than entirely onto private land.
Two other edits narrow the bill in ways developers should note. The manager’s amendment tightens the exception to the backstop’s 230-kilovolt voltage floor: as introduced, lines using advanced conductors could qualify below that floor at a voltage FERC deemed appropriate; now they qualify only if they offer throughput comparable to a conventional 230-kilovolt line, as determined by FERC. It also limits the consolidated planning process in Section 2106 to Transmission Organizations, dropping it for non-RTO regions such as the Southeast.
What the amendment gave merchant lines
The most developer-friendly change in the amendment may be the one that has received the least attention. The manager’s amendment allows partial cost allocation for merchant transmission lines: a merchant project can now have some of its costs allocated to customers — reflecting reliability benefits that are real but diffuse — while recovering the rest through voluntary contracts with offtakers. It also lets developers seek the bill’s federal cost allocation without applying for a federal siting permit.
That matters because cost allocation has always been the quiet half of the siting fight. A FERC permit answers who can approve a line; the tariff answers who pays for it. Section 2101 requires the owner of a qualifying line to file a tariff allocating costs to benefiting customers, at least roughly commensurate with specified benefits, and bars involuntary charges where benefits are nil or trivial relative to costs. Letting a state-sited line use that framework decouples the two questions: a developer no longer has to invite federal siting to get a federal cost-allocation answer.
What the Congressional Research Service found
The transmission title’s new shape is now the subject of an updated Congressional Research Service analysis, summarized in reporting on November 10, which assesses Section 2101 as revised by the manager’s amendment. The core finding is unchanged from the October analysis this desk relied on last week: the bill would replace the corridor system with nationwide reach. Under current law, FERC may permit an interstate line over a state’s objection only inside an area the Department of Energy has designated a National Interest Electric Transmission Corridor — and since Secretary of Energy Chris Wright announced on August 12 that DOE will designate none of the three corridors that had reached the final phase of review, that authority currently has nowhere to be exercised.
Under the bill, FERC’s backstop would apply to most of the country, with only the ERCOT area of Texas exempt, and DOE’s corridor-designation authority would be repealed. The updated analysis also confirms the eligibility tests: a line must carry power in interstate or foreign commerce, serve the public interest, protect or benefit consumers, improve reliability, and facilitate just and reasonable rates, and it must be rated at not less than 230 kilovolts or be necessary to interconnect such a facility. The changes to FERC’s authority, the analysis stresses, take effect only if the bill is enacted — a cloture vote on the motion to proceed is not a law.
The cost case, in two vintages
The economic argument for the transmission title now comes in two vintages, and the newer one is bigger. The earlier C2ES and Greenline Insights modeling, cited in law-firm analysis of the bill, projected about $7 billion in net delivery-cost savings by 2035 — after about $1.9 billion in new transmission investment — and about $1.1 billion in residential bill savings, with nearly 40 GW of added interregional transmission capacity. The expanded nationwide modeling the two groups released as the Senate debate approached lifts the numbers considerably: by 2035, the modeled reforms would enable 170 GW of additional wind, solar, and battery storage capacity, expand interregional transmission capacity by 61 GW, and cut annual electricity system costs by $11.7 billion in 2035 alone.
Both vintages rest on the same mechanism, and the mechanism is the bill’s interconnection and planning provisions as much as its siting backstop. The bill would require every planning region to use a common set of input assumptions and models and a common list of benefits, with regional and joint interregional plans due within two years of enactment; a project selected in a regional or interregional plan would be deemed to satisfy most of the Section 216(b) findings, creating a fast route from planning to permit. Regions would have to plan generation and transmission together over a 20-year horizon, and utilities would have to deploy grid-enhancing technologies where the benefit-cost ratio exceeds one, or face a FERC-determined penalty. The modeling’s own caveat is the delay case: waiting until 2030 would capture only about 40 percent of the modeled benefits by 2035, forgoing roughly $55 billion in system savings and 800 million metric tons of emissions reductions through 2040.
Who still stands in the way
A 73–25 vote looks like momentum, and it is — but it is momentum on a procedural question, and the obstacles ahead are substantive, procedural, and calendrical all at once. The first is process. The bill never had a hearing, a markup, or a committee report in either chamber; its text rides on H.R. 2347, a House-passed bill about the tax treatment of sexual abuse damages, as a legislative vehicle with nothing to do with energy or permitting. The November 9 vote was only the first of two 60-vote cloture votes the bill must clear, and the sponsors oppose substantive changes, with floor amendments requiring unanimous consent.
The second obstacle is the rest of the bill. The transmission title is the provision environmental groups have praised — the Natural Resources Defense Council calls it the bill’s principal strength — but the same bill rewrites the National Environmental Policy Act, the Clean Water Act, the Endangered Species Act, and the National Historic Preservation Act, and its Section 1401 would bar federal agencies from revoking, suspending, or changing permits in effect on or after November 6, 2026, except in narrow circumstances. The manager’s amendment softened that section, but critics, including the Center for Western Priorities, say the core protection for existing permits remains, and the National Congress of American Indians urged senators to vote no on November 8.
The third obstacle is the House. If the Senate passes the bill, it must still pass the House before becoming law, and House Democratic leader Hakeem Jeffries has said he will not rubber-stamp the bill as written. The current Congress ends January 3, 2027, which gives the bill roughly seven weeks from the November 9 vote to survive floor debate, a second cloture vote, and a House with its own permitting politics, in a form its four sponsors can still jointly defend. A bill that has not passed both houses by January 3 must start over.
The fourth obstacle is the White House, and it arrived in an unexpected form. President Trump has said he supports the legislation, but when asked around the time of Monday’s vote whether he would approve wind turbines, he replied: “No, I will not approve wind turbines.” The remark undercut a key part of the bargain for Democrats who backed the bill in part because it would ease approvals for all kinds of energy projects, including renewables, and the White House has not clarified whether the objection would apply to projects approved under the new law. The hole in the coalition is on the side that supplied 22 of the 73 votes.
What developers should actually do now
For a transmission developer, the practical read of the week is narrower than the headlines and more useful than the vote count. Nothing in current law has changed: FERC’s backstop still reaches only corridors that do not exist, and it will stay that way unless and until the bill is enacted. What has changed is the shape of the bet. A developer planning a 345-kilovolt-or-larger line should now assume a year in the state process before any federal application, and should plan its state record accordingly — because the state record is what FERC must consider, and a commission that decides within the year moots the backstop entirely.
The planning provisions, by contrast, reward early positioning regardless of the bill’s fate. A line selected in a regional or interregional plan would be deemed to satisfy most of the Section 216(b) findings, and the bill’s 20-year joint planning horizon and fixed zonal interconnection costs would change how developers value queue positions. The data-center provision is already settled in the bill’s terms: new large loads would pay the full cost of the grid service they need, with that cost barred from being passed to other customers — though the substitute dropped the introduced bill’s 20-megawatt threshold, so exactly which loads the rule reaches is still being parsed. Developers serving large loads should treat that cost rule as the direction of travel even if the bill stalls, because FERC’s own large-load tariff proceedings are moving the same way.
What to watch next
Four things will tell us whether the 73–25 vote was a breakthrough or a high-water mark. First, the second cloture vote and the floor debate: whether amendments are allowed, and whether any of them touch the transmission title or Section 1401, will show whether the sponsors’ coalition holds under pressure. Second, the House: whether its leadership negotiates a version, or whether the bill arrives as a take-it-or-leave-it Senate product, will decide whether January 3 is a deadline or a cliff. Third, the White House: any clarification of the wind-turbine remark will show whether the administration’s support extends to the full range of projects the bill would permit. And fourth, the state commissions: Wisconsin’s PSC, which has not yet been asked to approve MariBell or BECI, will be the first commission to run a major line’s proceeding under the shadow of a backstop that may or may not exist by the time it decides.
The question this desk posed last week has not changed, but its tense has. It is no longer whether a state saying no to a large interstate line should be the end of the conversation. The Senate has voted, 73–25, that it should not be — and then, in the same week, gave the states a year to have the conversation first. What the manager’s amendment changed is the answer to the narrower question underneath: when does anyone else get to ask whether that no should stand? Under the introduced bill, the answer was immediately. Under the amended bill, the answer is after a year, with the state record in hand, and with the co-ops and public power exempt from the new federal reach. The backstop is still the bill’s sharpest edge. It is now also a slower one, and the slowness was the price of the votes.