A Proposal for Interregional Buildout Through Federally-Built Clean Firm Generation
The proposal applies the proven New Deal federal-power model to today's clean firm generation challenge. Its key elements:
After two decades of essentially flat electricity demand, U.S. load is growing again — driven primarily by data centers and AI infrastructure, but also by electrification of transportation and heating, the reshoring of manufacturing, and the retirement of dispatchable thermal generation that needs to be replaced. The Tennessee Valley Authority reports that data center load reached 18% of its industrial demand in 2025 and is projected to double by 2030; similar trajectories are reported by Dominion Energy in Virginia, Duke Energy in the Carolinas, Southern Company in Georgia, and others. Most of these utilities cannot independently build enough generation to meet their projected load growth on the timeline required.
The obvious solution is interregional transmission: lines that let power flow from regions with generation surplus or new build capability to regions with concentrated load growth. The grid analytically supports this. North America has multiple regions where generation can be sited more easily and cheaply than in the high-load coastal corridors, and existing interregional transfer capacity is far below what optimal economic dispatch would call for. Multiple studies — the U.S. Department of Energy's National Transmission Needs Study, MIT's The Future of the Electric Grid, the National Renewable Energy Laboratory's interconnection studies — converge on the conclusion that the U.S. needs roughly double its current interregional transfer capacity to meet 2040 demand reliably.
Beyond economic dispatch, interregional transmission delivers substantial resource adequacy benefits through geographic diversity: load peaks, weather stress, and generation forced outages do not coincide across regions, so utilities connected by adequate interregional capacity need less redundant in-region capacity to meet reliability targets. Winter Storm Elliott in December 2022 demonstrated this concretely and painfully for the exact region this proposal targets. Extreme cold across the Southeast caused widespread natural gas plant forced outages and fuel deliverability failures, and both TVA and Duke Energy Carolinas were forced to implement rolling blackouts on December 23–24, 2022 — the first such events in either utility's history. Limited interregional transfer capacity meant that the Southeast could not adequately draw on power from regions experiencing different conditions, and that imbalances within the region could not be resolved by leaning on neighbors. The episode made the resource adequacy case for interregional transmission in the TVA and neighboring IOU footprint not theoretical but operationally urgent.
The obstacles to interregional transmission are not technical or economic but structural and financial. Interregional lines cross multiple state jurisdictions, multiple utility territories, and often multiple RTO/ISO seams. The benefits accrue partly to generators on the supply end and partly to load customers on the demand end, while the costs fall somewhere in between. Investor-owned utilities (IOUs) routinely oppose interregional projects on stated grounds of uncertain benefits and unfair cost allocation, and on unstated grounds of competitive threat to their owned generation. Moreover, the kind of clean firm generation that would justify new interregional transmission — principally new nuclear — has a well-documented history of catastrophic construction cost overruns that imposes risk no individual utility can readily absorb. Vogtle 3 & 4 finished at approximately $35 billion against an original $14 billion estimate. VC Summer was abandoned at $9 billion sunk cost with the units never completed. The combination of weak cost-allocation mechanisms and unbearable construction risk is what has prevented new nuclear plus interregional transmission from being built at the scale the load growth requires.
The federal interregional transmission that does exist in the United States — TVA's multi-state network, the Pacific Northwest–Southwest Intertie, the Bonneville Power Administration's network in the Pacific Northwest, the Western Area Power Administration's network — was nearly all built before 1990 under structural conditions that no longer exist, principally a pre-restructuring environment where IOUs faced no competitive threat from generation flowing across their borders and where federal entities bore both construction and operating risk on federal balance sheets.
This proposal aims to identify what can be replicated from those historical precedents under modern conditions, and to propose a specific structure that captures their workable features.
The single most important historical precedent for this proposal is the way federal hydropower has been built and operated in the United States since the 1930s. The Bureau of Reclamation (and parallel federal entities, principally the U.S. Army Corps of Engineers) builds federal dams as federal capital projects on the federal balance sheet. Construction is financed through Treasury borrowing, federal appropriations, and other federal mechanisms — not through the balance sheets of the utilities that ultimately market the output. Once dams achieve operational status, marketing of the power output is handled by the Power Marketing Administrations (BPA in the Pacific Northwest, WAPA in the West, Southwestern Power Administration in the South-Central states, Southeastern Power Administration in the Southeast). The PMAs are responsible for recovering federal investment over time through power sales, but they do not bear dam construction-cost overrun risk.
This model has worked for nearly 90 years across the Columbia Basin federal hydropower system, the Colorado River system, the Tennessee Valley (where TVA itself operates under a related model), and elsewhere. The cleanest property of the structure is that it separates construction risk (federal, absorbed by Treasury and ultimately taxpayers) from operating risk (utility, recovered through rates from beneficiary customers). Construction overruns on Grand Coulee, Hoover Dam, the Tennessee Valley dam system, and many others were absorbed federally and never devastated the balance sheets of the marketing utilities. Operating costs, by contrast, are routinely recovered through wholesale power rates that customers accept because they reflect the actual ongoing costs of producing electricity.
The applicability of this structure to nuclear is direct: nuclear plants in the post-Vogtle era share the property that made dams candidates for federal construction in the 1930s — they are large, lumpy capital investments with significant construction risk, serving long-lived public purposes, where private or utility-only financing is unreliable. What worked for federal hydropower can work for federal nuclear, with the additional advantage that the federal government already has substantial institutional infrastructure for nuclear oversight (NRC, DOE, the national laboratories, the existing federal nuclear regulatory framework).
The Pacific Northwest–Southwest Intertie (commonly the "Pacific Intertie") is a corridor of four high-voltage transmission lines connecting the Columbia River area of Oregon and Washington to load centers in California, principally the Los Angeles basin. It was authorized by Congress in 1964, funded in part by a $45.5 million federal appropriation, and built between 1965 and 1970 in its original three-line form, with a fourth line added in 1993. The corridor today carries approximately 8,000 MW of combined transfer capability — comparable to the load of a mid-sized U.S. state — and has operated reliably for 55+ years.
The Intertie's importance to this proposal is its ownership structure. Rather than being built or owned by a single entity, the lines are segmented at the territorial seams between participating utilities. The HVDC line that forms the corridor's backbone is owned by the Bonneville Power Administration (a federal entity) on its northern portion from the Celilo Converter Station near The Dalles, Oregon to the Oregon-Nevada border, and jointly owned by a consortium led by the Los Angeles Department of Water and Power (LADWP) on its southern portion from the Oregon-Nevada border to the Sylmar Converter Station near Los Angeles. The Southern Owners consortium includes LADWP, Southern California Edison, and the cities of Burbank, Glendale, and Pasadena. The two original AC lines that complete the corridor have similarly mixed ownership: one is owned by the Western Area Power Administration (a different federal entity), one by Pacific Gas & Electric and PacifiCorp jointly. The fourth AC line, added in 1993, is owned principally by a joint powers agency of 15 California publicly-owned utilities, with WAPA, PG&E, and two water districts as minority participants.
Three properties of this structure are critical for the present proposal:
Cost allocation was settled by ownership. Each owner recovers the cost of its segment through its own rate base mechanisms — BPA through its federal wholesale power rate, LADWP through its municipal rates, the IOUs through their state-regulated retail rates. No federal-level cost allocation methodology was required, and no decade-long fight over who should pay for what occurred. The line got built because the question "who pays" was answered upfront by the question "who owns."
The line was anchored to specific federal generation. The Intertie existed to deliver Columbia River federal hydropower (built and owned federally under the BoR/Corps/BPA model described above) to California load. It was not a generic interregional capacity addition; it had a specific resource-to-load story that gave both ends of the corridor a reason to participate. This anchor framing is what made it a federal project rather than a contested merchant project.
Each region got reciprocal benefits. The Pacific Northwest peaks in winter (heating); the Southwest peaks in summer (air conditioning). The line let each region lean on the other's off-peak generation. The "regional preference" provisions of the 1964 authorization guaranteed that each region's customers had first call on power generated in their own region.
Together, the BoR/BPA construction model and the Pacific Intertie's segmented-ownership transmission model provide a coherent template for federally-anchored interregional buildout. The first solves construction-risk absorption and capital formation; the second solves cost-allocation and IOU alignment. Combined, they produce the architecture this proposal adopts.
The New Deal–era federal generation programs were not just funding mechanisms; they were structured around an explicit public-preference principle that governed who could receive what kind of federal support. The Bonneville Project Act of 1937, the various Power Marketing Administration authorizing statutes, and the broader federal power policy framework all distinguished between publicly-owned utilities (federal, state, municipal, and cooperative entities) and investor-owned utilities, with federal generation output legally required to be offered first to public power before being made available to IOUs as surplus. The justification was that public utilities returned benefits directly to ratepayers and citizens, while IOU intermediation diverted some share of federal benefits to private shareholders.
This proposal generalizes the principle but updates the substance of the preference. The 21st-century barrier to clean firm generation buildout is not the price of power but the construction risk of new nuclear and the cost-allocation barrier to new interregional transmission. The relevant federal supports are therefore not wholesale price subsidies (which the market does not currently need; hyperscalers are willing to pay premium prices for clean firm power) but construction-risk absorption and transmission financing/siting authority.
The modernized public preference operates as follows:
Federal cost-overrun insurance applies only to publicly-owned acquirers. A federally-built clean firm plant transferred to TVA, NYPA, NPPD, or another qualifying public utility is eligible for federal absorption of construction costs above the acquisition price. A federally-built plant transferred to an investor-owned utility (or built by an IOU with federal financing) is not. This eliminates the historical objection to federal nuclear cost-overrun absorption — that it would socialize private profit — because the publicly-owned acquirer returns operating benefits to its ratepayers and citizens, not to shareholders.
Federal transmission financing and siting authority apply preferentially to anchor lines tied to publicly-owned plants. Federal credit facility support for transmission segment financing, federal backstop siting authority under a renewed Section 216, and the standardized federal joint-project documentation template all apply to anchor lines tied to qualifying federally-supported clean firm generation under publicly-owned operation. IOUs can participate as segment co-owners and wholesale buyers, but the federal support that accelerates the line's permitting and financing flows to projects anchored to public-utility plants.
The Nuclear Construction Reserve Fund applies only to qualifying public-utility-acquired plants. Hyperscaler per-MWh contributions to the Fund accrue benefits only when offtaking from qualifying federally-built plants acquired by public utilities. A hyperscaler signing a PPA with an IOU for power from an IOU-built nuclear plant would not be paying into the Fund and would not benefit from federal tail-risk absorption.
The structural advantages of this updated preference principle are substantial. It directs federal support to the institutional category — public power — that has historically been the most reliable long-term partner in federal infrastructure programs, that is most accountable to ratepayers, and that does not face the merger, acquisition, or strategic-pivot risks that have repeatedly disrupted IOU participation in federal programs. It defuses the "socializing private profit" objection that has prevented federal cost-overrun absorption for nuclear for fifty years, because the recipients are public entities returning value to public ratepayers. It creates a clear and administratively simple eligibility criterion that doesn't require complex ongoing assessment of project structures — either the acquirer is a publicly-owned utility or it isn't. And it preserves a meaningful and durable role for IOUs as transmission partners and wholesale buyers without giving them direct access to federal construction-risk absorption that would create misaligned incentives.
The principle also generalizes geographically. The New Deal hydropower programs were necessarily geographically concentrated because federal dams could only be built where federal rivers flowed. Nuclear plants can be built almost anywhere with adequate cooling water and grid access, which means the program can scale across multiple regions wherever qualifying public utilities have suitable sites and operational capability. The TVA pilot is the lead example because TVA brings together the most assets in one place, but the framework's geographic reach is much broader.
Eligibility as an acquiring utility under the Federal Anchor Generation Authority requires four properties: publicly-owned status (federal, state, municipal, or cooperative); operational scale sufficient to absorb GW-scale plant acquisitions; existing nuclear operating capability or credible pathway to develop it; and willingness to participate in the long-term federal-state-utility framework the program requires.
TVA is the lead pilot for reasons developed extensively in subsequent sections: pre-assessed never-completed nuclear sites, existing nuclear operating workforce, active SMR development pipeline, and direct geographic adjacency to the highest-growth IOU data center markets in the country.
New York Power Authority (NYPA) is the second-strongest candidate. NYPA is the largest state-owned electric utility in the United States, currently operates several major hydroelectric facilities (Niagara, St. Lawrence-FDR), and has the statutory authority and balance sheet capacity to acquire new generation. New York State's 2019 Climate Leadership and Community Protection Act mandates carbon-free electricity by 2040, and NYPA has been authorized under recent state law to develop new clean energy generation. NYPA does not currently operate nuclear plants, but the operating workforce can be developed in partnership with the existing U.S. nuclear operating fleet. Anchor lines from NYPA-acquired plants could serve data center load growth in upstate New York and (via inter-IOU coordination) downstate New York and northern New Jersey, addressing one of the largest concentrated data center load growth challenges in the country.
The Nebraska public power group — Nebraska Public Power District (NPPD), Omaha Public Power District (OPPD), and Lincoln Electric System (LES) — is uniquely positioned because Nebraska is the only U.S. state with 100% public power. NPPD already operates the Cooper Nuclear Station, providing existing nuclear operating capability. OPPD operated Fort Calhoun until its 2016 retirement and retains substantial nuclear engineering experience. Anchor lines from Nebraska-acquired plants could serve rapidly growing data center clusters in Omaha (where Meta and Google have major facilities), Kansas City, and the broader MISO/SPP region, with coordination across multiple state lines because the public utility consortium spans them.
Los Angeles Department of Water and Power (LADWP) is a strong candidate in the West. As the largest municipal utility in the United States and a long-standing partner in the Pacific Intertie, LADWP has the scale and operational capability for major capital projects. LADWP could acquire federally-built nuclear (or other clean firm generation) to serve Los Angeles basin load directly and contribute to broader Western Interconnection resource adequacy.
Salt River Project (SRP) in Arizona is a smaller candidate but a credible one given Phoenix-area data center growth and SRP's substantial municipal utility scale. CPS Energy in San Antonio operates a substantial share of the South Texas Project nuclear plant and has both operating experience and scale. JEA in Jacksonville is a similar candidate in Florida.
The framework can be sized to the candidate. A NYPA pilot might be a single AP1000 unit at a designated site (the Sterling Renaissance / Nine Mile Point area in upstate New York has been studied as a potential new nuclear site). A Nebraska pilot might be a twin-AP1000 at a brownfield Fort Calhoun site or a greenfield site that NPPD identifies. The TVA pilot at Bellefonte is the largest near-term candidate because of the existing site infrastructure, but the program is not gated by TVA's pace; multiple public-utility acquirers can be advanced in parallel.
The framework also remains open to additional qualifying public utilities as the program matures. State-owned generation entities that might be created under future state legislation (analogous to NYPA's expansion of authority in recent years) could qualify. New municipal utility consortiums analogous to the Transmission Agency of Northern California (which built the third 500 kV line of the Pacific Intertie in 1993) could qualify. The defining requirement is publicly-owned operation; the institutional vehicle can take multiple forms.
TVA serves as the lead pilot for the Federal Anchor Transmission Program because it brings together more program-relevant assets than any other qualifying public utility in the United States. The framework's broader applicability is established above; this section develops the specific case for TVA as initial implementation partner.
TVA was created by Congress in 1933 as a federally-owned corporate entity to develop the Tennessee River basin through flood control, navigation improvement, and electric power generation. By the mid-1950s its mission had expanded substantially beyond hydropower; today TVA operates a generation fleet that is majority non-hydro (nuclear, coal, gas, with hydro at roughly 10–13%) and owns approximately 16,200 miles of transmission lines serving 153 local power companies (LPCs) — the municipal and cooperative distributors that resell TVA power at retail — plus directly-served industrial customers and federal facilities across seven states.
TVA is currently the most active federal entity in the United States for new nuclear development. It is the first U.S. utility to file an SMR construction permit (for a GE Hitachi BWRX-300 at Clinch River, Tennessee), the first U.S. utility to sign a power purchase agreement for an advanced reactor (with Kairos Power for the 50 MW Hermes 2 molten salt reactor at Oak Ridge, with output committed to Google data centers in Tennessee and Alabama), and a participant in a 6 GW SMR development agreement with ENTRA1. TVA's data center customers include Google, Oracle, and Meta facilities currently operating or under construction within its territory.
Equally important: TVA owns a portfolio of pre-assessed large nuclear sites that were started in the 1970s and never completed, but retain decades of accumulated environmental review, site characterization, water rights, transmission interconnection capacity, rail access, and in some cases substantial unfinished plant infrastructure. The most prominent is Bellefonte in Hollywood, Alabama — a 1,600-acre site on the Tennessee River where construction of two pressurized water reactors began in 1974 and was suspended in 1988 with Unit 1 approximately 88% complete and Unit 2 approximately 58% complete. Bellefonte was the reference site for the NuStart Energy consortium's combined construction and operating license application for the Westinghouse AP1000 in 2007, and remains TVA-owned with substantial residual infrastructure (transmission switchyard, cooling water access, rail lines, helicopter pad, and the cores of two reactor buildings). Other never-completed TVA nuclear sites include Hartsville (Tennessee, 4 units cancelled), Phipps Bend (Tennessee), and Yellow Creek (Mississippi). These sites collectively represent multiple gigawatts of pre-permitted, pre-characterized nuclear capacity that could be redeveloped with new large reactors on a timeline substantially shorter than greenfield siting.
The federal policy environment for large reactor deployment has shifted decisively in TVA's favor over the past year. In October 2025, the Department of Commerce announced an $80 billion strategic partnership with Westinghouse Electric Company, Cameco Corporation, and Brookfield Asset Management to deploy a fleet of Westinghouse AP1000 reactors across the United States, with federal support for permitting acceleration, supply chain coordination, and project financing. Separately, the Department of Energy's Loan Programs Office, rebranded as the Office of Energy Dominance Financing under the One Big Beautiful Bill Act, has authority to support roughly 10 additional AP1000 reactor deployments through its expanded "energy infrastructure" lending mandate. Industry analysts now project up to 20 new AP1000s in the U.S. construction pipeline over the next decade, supporting the federal target of quadrupling U.S. nuclear capacity from approximately 100 GW today to 400 GW by 2050.
The combination of TVA's pre-assessed sites, its operating nuclear expertise, its existing SMR development pipeline at Clinch River and Oak Ridge, and the federal backing now available for large reactor deployment positions TVA as the natural fleet operator and acquiring utility for federally-built clean firm generation. The 1959 TVA Bond Act, however, imposes two structural constraints: TVA's debt is statutorily capped at $30 billion (with $22.1 billion currently outstanding as of September 30, 2025, leaving roughly $7.9 billion of headroom that must cover all TVA capital needs across nuclear, gas, and transmission), and TVA cannot sell power outside its statutory service territory except to fourteen specific neighboring utilities under reliability exchange arrangements grandfathered from 1957. Both constraints require legislative attention as part of the proposal's implementation.
The proposal's core architecture has four integrated elements: a federally-supported clean firm generation project built and owned by the federal government during construction (the "anchor"), a defined transfer of that project to TVA at commercial operation at an agreed acquisition price (the "transfer"), a jointly-owned transmission line connecting the anchor generation to load in a neighboring utility territory (the "anchor line"), and a federal support package providing construction-phase financing, cost-overrun absorption, siting authority, and a Nuclear Construction Reserve Fund (the "federal enablement").
New AP1000s (and other federally-supported clean firm generation projects in the program) are built and owned by the federal government during construction. The federal owning entity is the Department of Energy, the Department of Commerce under the existing $80 billion AP1000 partnership, a new dedicated federal nuclear construction office, or some combination determined by program design. Construction is financed through Treasury borrowing, DOE appropriations, the DOC/Westinghouse partnership's existing $80 billion authority, the Office of Energy Dominance Financing's lending authority, or some mix thereof.
The federal entity contracts with Westinghouse (and supporting contractors) for plant construction under the framework of the DOC partnership. The federal government bears construction risk; the contractor delivers a plant against defined specifications. The federal entity also engages TVA from the outset as the designated future operator, with TVA providing operating-readiness review, workforce training, and procedural integration during construction so that TVA can assume operational responsibility at commercial operation without delay.
Siting is on TVA's pre-assessed sites (Bellefonte initially, then Hartsville and others as the fleet scales). TVA retains site ownership during construction and grants the federal construction entity necessary access and use rights for the construction period. The pre-assessed status of these sites — prior NRC reference-site designation, existing environmental impact statements, established water rights, intact transmission switchyards — substantially accelerates the construction timeline relative to greenfield siting.
At commercial operation, the federal government transfers the plant to TVA at a pre-agreed acquisition price reflecting the original cost estimate at financial close, with a defined methodology for adjustments only for unforeseeable circumstances unrelated to construction execution (force majeure, fundamental regulatory changes, etc.). The acquisition price is set at financial close and is contractually firm.
For a Bellefonte twin-AP1000 with an estimated cost of $16 billion, the acquisition price would be set at approximately $16 billion. If actual construction cost comes in at $16 billion or below, the acquisition price covers federal investment. If actual construction cost comes in above $16 billion — at $20 billion, or $25 billion, or higher — the federal government absorbs the difference on its balance sheet. TVA's basis in the plant remains the $16 billion acquisition price, regardless of actual construction cost.
TVA finances the acquisition through bond issuance under its existing or expanded debt authority. The acquisition is a discrete transaction at a known, fixed price, which means TVA's debt requirements are knowable in advance and can be sized precisely without the contingent overruns that have historically destabilized utility nuclear financing. TVA's rate base reflects the acquisition price as the plant's value, and TVA recovers that capital from its customers through wholesale power rates over the plant's operating life, in the normal manner that utility rate bases are recovered.
This structure means TVA's customers never pay for construction-cost overruns. The TVA CEO's public commitment that data center growth will not pressure rates for other electric customers is preserved in all scenarios, including catastrophic overrun scenarios, because catastrophic overruns simply don't flow into TVA's rate base. They are absorbed federally.
For each anchor generation project that will serve load in a neighboring IOU territory, an anchor transmission line is built as a jointly-owned segmented project on the Pacific Intertie model.
TVA owns and rate-bases the segment of the anchor line within its territory. The neighboring IOU owns and rate-bases the segment within its own territory. The two segments meet at a border substation jointly owned or jointly operated by both. Each segment's capital is recovered from its host utility's customers through its host utility's normal rate base mechanisms — TVA's wholesale rate for the TVA segment, state-regulated retail rates for the IOU segment.
The federal government may also build and own segments of the anchor line in cases where the line crosses multiple IOU territories or where federal siting authority is needed to overcome state-level obstruction. In those cases, the federal segment is recovered through wholesale rates charged to the receiving utilities or to direct-served load.
The Pacific Intertie pattern solves the cost-allocation problem by design: each utility pays for the segment it owns and benefits from. There is no FERC-jurisdictional cost-allocation dispute, no inter-utility fight over benefit shares, no need for a complex allocation methodology. The line gets built because each participating party has a defined ownership share, a defined capital recovery mechanism through its own customer base, and a defined operational benefit from the completed line.
The workhorse offtake mechanism for cross-territory delivery is a two-stage wholesale-to-retail structure.
TVA sells output from the federally-built, TVA-acquired plant to the host IOU at wholesale, under a long-term firm capacity contract (typically 20-25 years). The wholesale price reflects TVA's recovery of the acquisition price plus operating costs, fuel costs (including used fuel disposal), and a defined federal financing margin. This wholesale sale is the transaction authorized by the narrow fence carve-out described under "Legislative Requirements" below.
The host IOU then resells the contracted capacity to one or more hyperscaler data centers in its territory at retail, under PPA terms approved by its state PUC. The retail PPA covers the IOU's wholesale purchase cost from TVA, the IOU's segment of the anchor line, the IOU's intra-territory delivery infrastructure, and the IOU's regulated retail margin.
This structure has several advantages. The IOU keeps the retail customer relationship with the hyperscaler, which is the politically essential property — the IOU isn't bypassed in its own territory. The IOU keeps its rate-base position in the transmission and distribution infrastructure serving the data center. The hyperscaler gets a long-term clean firm PPA at federally-financed cost (passed through with the IOU's margin) without taking nuclear construction risk. TVA gets capital recovery on the federal acquisition price through reliable long-term wholesale revenues. The federal government's role ends once the plant is transferred and the acquisition price is paid; ongoing operating economics flow through TVA and the IOU.
The hyperscaler does not, under this structure, become a customer of TVA directly. The Hermes 2 / Google / Kairos structure that TVA operates today within its territory provides an operational template for the three-way structure (developer, utility, hyperscaler), but for cross-fence delivery the wholesale-to-IOU mechanism replaces the direct-to-data-center mechanism that operates within the fence.
The proposal's most important structural innovation is its handling of construction-cost overrun risk. Historical nuclear cost overruns of 50–150% are not tail risks; they are the modal outcome. The proposal's federal construction-phase ownership model addresses this directly: above the acquisition price, the federal government absorbs overruns. But the federal government should not be the sole absorber, because hyperscaler offtakers are the demand driving the program, have substantial financial capacity, and would otherwise free-ride on federal risk absorption.
The structure is therefore a defined allocation:
Owner band (up to acquisition price). The federal construction entity bears the first slice of cost up to the acquisition price. Below acquisition price, this is simply the plant's expected cost. Construction discipline is maintained because the federal entity has appropriations and Congressional oversight responsibility for keeping costs in this band where possible.
Hyperscaler band (acquisition price up to 120% of acquisition price). Hyperscalers offtaking power from federally-supported plants contribute to a federal Nuclear Construction Reserve Fund through a per-MWh contribution on their offtake. The fund is fleet-wide rather than project-specific, allowing risk-pooling across the AP1000 deployment portfolio. The contribution rate is calibrated to expected overrun magnitudes across the fleet — initial estimates suggest a rate of approximately $30–40/MWh applied to hyperscaler offtake would generate sufficient fund accumulation to cover expected overruns in the 0–20% range above acquisition price across a 10–20 plant fleet. The fund's first call is to cover overruns in this band; only if and when the fund is depleted does the federal balance sheet absorb additional overruns in this band.
Federal tail band (above 120% of acquisition price). Construction costs above 120% of acquisition price are absorbed directly on the federal balance sheet through Treasury financing or Congressional appropriations, with potential project-specific review for overruns above a defined catastrophic threshold (perhaps 150% of acquisition price). This is the federal tail-risk absorption that makes the entire structure work, justified by the principle that when the builder is a federal instrument, the federal government appropriately bears construction tail-risk.
The Nuclear Construction Reserve Fund is administered by Treasury or DOE as a dedicated federal trust fund. Inflows are the per-MWh contributions from hyperscaler offtakers, paid through the operating life of plants from which they offtake. Outflows are disbursements for documented construction-cost overruns in the hyperscaler band on qualifying projects.
The fund operates on actuarial principles. Contribution rates are calibrated based on historical nuclear construction cost data, updated annually as fleet experience accumulates. Early plants in the fleet have higher implicit overrun probabilities and the fund absorbs proportionally more of their potential overruns; later plants benefit from accumulated standardization experience and the fund's reserves are correspondingly less drawn down. Risk-pooling across the fleet allows the first AP1000s to be financeable in a way they wouldn't be on a stand-alone basis, with later, lower-risk plants effectively underwriting the higher risk on earlier plants.
Excess accumulation in the fund (if fleet construction performance exceeds initial expectations) can be returned to contributing hyperscalers pro rata over time, applied to plant decommissioning reserves, or rolled forward to fund subsequent generation in the program. The fund's governance includes federal oversight with transparent annual reporting on inflows, outflows, and accumulated reserves.
Federal absorption of nuclear cost overruns has historically been politically toxic when proposed for privately-owned utility nuclear construction, because it amounts to socializing private profit-seeking. The structure here avoids that pitfall by design. The builder is the federal government itself, acting through DOE or DOC. The federal cost-overrun absorption is therefore not the federal government insuring someone else's commercial risk; it is the federal government bearing its own risk on its own capital projects, exactly as it has done for federal dams, federal buildings, military infrastructure, the Strategic Petroleum Reserve, and many other federal capital programs.
Hyperscaler contributions to the Nuclear Construction Reserve Fund provide additional defensibility: the corporate beneficiaries of clean firm power are paying meaningful contributions toward the risk they're creating, not free-riding on federal absorption. The corporate contribution rate is structured as transparent, mechanical, and proportional to offtake — there is no scenario in which hyperscalers benefit from federal nuclear without paying into the risk pool.
The result is a structure where the federal government absorbs the tail risk it has chosen to create (by authorizing the program, by financing the construction, by partnering with Westinghouse, by supporting the build-out for federally-prioritized purposes), hyperscalers absorb the middle band of risk proportional to their use of the output, and TVA's ratepayers — the demographic that has historically born the worst of nuclear cost overruns — bear no construction risk at all.
The proposal leverages multiple federal financing instruments already in place and adds modest new authority where needed.
For construction-phase financing of plants, the existing toolkit is largely sufficient. The October 2025 Department of Commerce / Westinghouse / Brookfield / Cameco $80 billion partnership provides federal industrial-base support, permitting acceleration, and project-level financing facilitation for the AP1000 fleet. The Department of Energy's Office of Energy Dominance Financing provides credit support for clean firm generation projects. Treasury borrowing through DOE or DOC appropriations covers any gap. The Inflation Reduction Act's nuclear and clean energy tax credits (Sections 45U, 48E) provide tax-side support, though some of these may need restructuring to flow to the federal construction entity rather than to a utility owner.
For TVA's acquisition financing, modest debt cap relief is needed. TVA needs sufficient borrowing capacity to acquire plants at the agreed acquisition prices, plus its ongoing non-nuclear capital needs. The current $30 billion cap with $7.9 billion of headroom is insufficient. Raising the cap to $50–60 billion, or carving out a specific acquisition-financing exception, would provide adequate capacity for the initial fleet of plants without requiring a structural reorganization of TVA's debt authority.
For anchor line financing, federal credit enhancement reduces the cost of capital for both federal and IOU segments. The Office of Energy Dominance Financing's expanded "energy infrastructure" lending mandate can be applied. A dedicated federal credit facility for federally-anchored interregional transmission, modeled on BPA's revolving fund, could be created as a further enhancement; this is achievable as an expansion of Office of Energy Dominance Financing authority rather than as a new freestanding institution.
For the Nuclear Construction Reserve Fund, the fund itself is administered by Treasury or DOE and is funded by hyperscaler contributions, not by federal appropriation. The federal contribution to construction risk absorption flows through Treasury borrowing or Congressional appropriations only for overruns in the federal tail band (above 120% of acquisition price), which is the unusual case rather than the routine case. Most plant construction should not require federal tail-band absorption if the fleet standardization theory holds; the tail absorption is a backstop that makes the structure financeable in worst-case scenarios.
The proposal can be piloted in two parallel phases. Phase 1 pilots leverage TVA's pre-assessed sites and existing nuclear operating capability to demonstrate the structure with the fastest possible deployment timeline. Phase 2 pilots extend the framework to other qualifying public utilities (NYPA, Nebraska public power, LADWP, and others), demonstrating that the framework is genuinely portable beyond TVA. Both phases can be pursued simultaneously; Phase 2 does not wait on Phase 1 completion.
Bellefonte twin-AP1000 with Southern Company as offtaker. Two Westinghouse AP1000 reactors (approximately 2,300 MW combined) built by the federal government on TVA's Bellefonte site in northern Alabama, transferred to TVA at commercial operation at a defined acquisition price (perhaps $16–18 billion). TVA wholesales a defined share of output (perhaps 800–1,000 MW) to Southern Company under a long-term firm capacity contract; Southern Company resells to data center load clusters in metro Atlanta under a retail PPA. An anchor line carries Southern's share from Bellefonte to a border substation with Georgia Power, with TVA owning the Alabama segment and Southern owning the Georgia segment. Bellefonte offers the strongest first-project case: an existing 1,600-acre TVA-owned site with prior AP1000 reference-site NRC review, transmission switchyard already in place, Tennessee River cooling water access, and proximity to both TVA and Southern Company territory. Southern Company's recent AP1000 construction experience from Vogtle 3 & 4 provides operational continuity that benefits both the federal construction entity (during build) and TVA (during operations).
Duke Energy anchor project. A federally-built AP1000 deployment at Hartsville (Tennessee) or another TVA pre-assessed site, transferred to TVA at commercial operation, with wholesale offtake by Duke Energy for resale to data center load in Charlotte and the Research Triangle. The anchor line crosses from TVA territory into Duke's North Carolina footprint. Duke's recently announced SMR exploration suggests interest in this type of structured nuclear access, and the federal-balance-sheet structure offers Duke firm clean capacity at substantially lower effective cost and risk than Duke building independently.
Dominion Energy anchor project. The most ambitious of the Phase 1 pilots: a federally-built AP1000 deployment in eastern Tennessee, transferred to TVA, with wholesale offtake by Dominion for resale to data center load in Northern Virginia, the largest data center market in the world. The distance and intervening utility territories make this the highest-difficulty pilot. The anchor line crosses TVA territory, potentially crosses through additional territories before reaching Dominion's, and may require federal siting authority to clear state-level obstruction. Dominion's data center load problem is severe enough that the political alignment for an ambitious solution may be more accessible than for the other pilots.
This pilot also crosses a major RTO seam: TVA is a non-RTO balancing authority, while Dominion is a full member of PJM Interconnection. Power flowing from TVA-acquired federal generation into Dominion's PJM-coordinated grid therefore requires the full cross-RTO interconnection architecture: FERC-approved transmission service across the seam, interregional planning coordination among TVA, PJM, and FERC, an appropriate cost-allocation framework for cross-RTO transmission, and either a pseudo-tie arrangement or a back-to-back DC interconnection at the seam point. These mechanisms are well-developed in U.S. interregional transmission practice; the Pacific Intertie crosses comparable jurisdictional boundaries, and TVA's existing interties with PJM-area utilities use similar frameworks at smaller scale. Building this architecture into Phase 1 establishes the precedent that federal anchor generation can serve RTO load through non-RTO public utility acquirers, which significantly broadens the framework's applicability to subsequent pilots.
Yellow Creek → Entergy Mississippi (Phase 1+ TVA expansion candidate). A near-term expansion option within TVA's pilot phase, leveraging the same federal-construction / TVA-acquisition architecture but extending westward instead of eastward. Yellow Creek's pre-assessed site in northeastern Mississippi sits adjacent to Entergy Mississippi's central-MS service area, where Meta's Forest, MS data center and Amazon's Madison County investment have established a growing data center cluster. The proposed anchor line would carry federal-anchor generation from a Yellow Creek AP1000 (or SMR) westward to a border substation with Entergy Mississippi for retail delivery to the Central MS cluster. Like the Dominion pilot, this line crosses an RTO seam (TVA non-RTO into MISO South), and it uses the same cross-RTO architecture established by the Dominion pilot. Yellow Creek's residual construction completion is lower than Bellefonte's (~35% vs. ~90% in the original 1980s build), which is why it is treated as a near-term expansion candidate rather than a top-three Phase 1 pilot, but the geographic case is strong: the cluster is real and growing, the existing TVA-Entergy interties at the Mississippi River provide engineering precedent for the interconnection, and the addition of a westward MISO-direction pilot alongside the eastward PJM-direction pilot (Dominion) makes the program a more robust demonstration of federal anchor generation as a cross-RTO bridge.
NYPA SMR or AP1000 with downstate IOU offtakers. A federally-built SMR cluster or single AP1000 unit deployed at a New York site (potential candidates include the Nine Mile Point area in upstate New York where prior nuclear development has occurred, or other state-designated locations), transferred to NYPA at commercial operation. NYPA wholesales a defined share to Con Edison and National Grid for resale to data center load in downstate New York and northern New Jersey, with anchor lines from upstate generation to downstate load. The NYPA pilot establishes that the framework works in a different regulatory environment (New York State public utility commission, NYISO market structure) and with a different qualifying public utility (state-owned rather than federally-owned).
Nebraska public power AP1000 with regional IOU offtakers. A federally-built AP1000 deployment at a Nebraska site selected by NPPD (potentially the Fort Calhoun area, which has prior nuclear operating history under OPPD, or another NPPD-identified site), transferred to NPPD at commercial operation. NPPD wholesales a defined share to MISO and SPP IOUs serving Omaha, Kansas City, and broader Midwest data center clusters, with anchor lines crossing into multiple states. The Nebraska pilot demonstrates the framework's portability to 100%-public-power state structure and to MISO/SPP regional market conditions, expanding the program's geographic reach beyond the Southeast.
LADWP pilot in the Western Interconnection. A federally-built clean firm project (potentially geothermal or new nuclear, depending on California regulatory pathway) acquired by LADWP, with anchor transmission improvements coordinated with the existing Pacific Intertie infrastructure. LADWP's existing role as a Pacific Intertie co-owner and its scale as the largest U.S. municipal utility make it the natural Western Interconnection pilot.
Beyond the initial pilots, the broader pipeline of qualifying public-utility-owned sites supports a multi-decade federally-built clean firm deployment program. TVA's pre-assessed sites alone (Bellefonte's two unit-equivalents plus Hartsville's four, plus Phipps Bend and Yellow Creek) support 8–12 GW of new nuclear capacity. The Yellow Creek site in particular supports the westward Phase 1+ expansion concept described above (Yellow Creek → Entergy Mississippi), giving TVA a path to anchor generation that demonstrates the framework across both eastern (TVA → PJM via Dominion) and western (TVA → MISO South via Entergy MS) cross-RTO seams. NYPA, NPPD, LADWP, and other public-utility acquirers could collectively add another 10–20 GW depending on site identification, NRC licensing pace, and program implementation. The Hermes 2 project at Oak Ridge and the BWRX-300 at Clinch River provide proof-of-concept generation precedents that demonstrate TVA's regulatory pathway and operating capability for advanced nuclear deployment; analogous demonstrations at non-TVA sites accelerate the framework's scaling beyond TVA.
The proposal can be implemented through a combination of administrative action under existing authorities and several pieces of new legislation.
Available under existing authority: Federal construction-phase ownership of capital projects (existing federal capital program authorities, Treasury borrowing, DOE appropriations). DOE Loan Programs Office credit support for transmission and clean firm generation (IRA Sections 50141, 50151; Title 17). Federal production tax credits and investment tax credits for nuclear (IRA Sections 45U, 48E, and successor instruments — may require modification to flow to federal construction entities rather than utility owners). The DOC/Westinghouse $80 billion partnership framework for AP1000 deployment. FERC transmission incentives under Order 679.
Requiring new legislation:
Federal Anchor Generation Authority. New legislation authorizing federal construction-phase ownership of clean firm generation plants, with defined transfer mechanisms to acquiring utilities at agreed acquisition prices. This is the principal new statutory authority required and is the core enabler of the federal-balance-sheet construction model. The legislation defines eligible projects (federally-supported clean firm generation as defined by the Secretary of Energy), eligible acquirers under the modernized public-preference principle (TVA, NYPA, NPPD, OPPD, LES, LADWP, SRP, CPS Energy, JEA, and other publicly-owned utilities meeting defined operational scale and nuclear-readiness criteria), and the acquisition price methodology. Eligibility is explicitly limited to publicly-owned utilities; investor-owned utilities can participate as transmission segment co-owners, wholesale buyers, and retail offtake intermediaries, but cannot be acquirers of federally-built plants and cannot directly receive federal cost-overrun absorption.
Nuclear Construction Reserve Fund. Statutory establishment of the federal Nuclear Construction Reserve Fund as a dedicated trust fund administered by Treasury, with defined inflow rules (per-MWh contributions from hyperscaler offtakers), outflow rules (disbursements for documented construction overruns on qualifying plants in the hyperscaler band), and governance.
Federal cost-overrun absorption authority. Statutory authorization for federal absorption of construction costs above the hyperscaler band, drawn from Treasury borrowing or Congressional appropriations. The authorization should include defined limits, project-specific review thresholds for catastrophic overruns, and ongoing reporting requirements.
TVA Act amendments. Two specific amendments: a narrow fence carve-out authorizing TVA to sell power from federally-acquired anchor program plants on a wholesale basis to neighboring IOUs for resale to defined hyperscaler load classes; and an expansion of TVA's statutory debt limit to accommodate plant acquisition financing plus ongoing TVA capital needs (raising the cap from $30 billion to approximately $50–60 billion, or creating a dedicated acquisition-financing exception outside the existing cap).
Federal transmission siting authority. Renewed and strengthened federal backstop siting authority for anchor lines tied to federally-supported clean firm generation. The Section 216 backstop authority created by EPAct 2005 has been effectively neutered by court decisions and DOE deference to state processes; a renewed federal authority limited specifically to lines anchored to federally-supported generation under the anchor program would have a narrower scope and stronger constitutional footing.
Requiring administrative action: Standardized federal joint-project documentation template for anchor lines (DOE or FERC, drawing on Pacific Intertie agreements as the starting reference). Interagency coordination among DOE, DOC, FERC, TVA, NRC, and Treasury to align program criteria, construction oversight, transfer mechanisms, fund administration, and rate-setting protocols. A federal Anchor Program Office to administer the program criteria, evaluate candidate projects, oversee construction-phase activities, manage plant transfers, administer the Nuclear Construction Reserve Fund, and coordinate federal support packages.
The proposal's durability depends on every major stakeholder having a clear and defensible stake in the program's success. The federal-balance-sheet construction model, the segmented transmission ownership, the Nuclear Construction Reserve Fund, and the wholesale-to-retail offtake structure combine to produce different but coherent benefits for each stakeholder class.
TVA gains scale expansion of its operating nuclear fleet without bearing construction risk. New AP1000s and SMRs on its pre-assessed sites (Bellefonte, Hartsville, Phipps Bend, Yellow Creek) come onto TVA's operating books at known, fixed acquisition prices — TVA never has to absorb a Vogtle-style overrun, regardless of how construction performs. TVA's debt requirements for acquisition are knowable in advance, contained within reasonable debt cap expansion, and matched to plant capital that will be recovered through wholesale rates over multi-decade operating lives. The arrangement effectively gives TVA the operating benefits of a substantially expanded nuclear fleet while leaving construction-phase risk on the federal balance sheet where it can be absorbed.
TVA also gains rate-base position in new interregional transmission for its segments of anchor lines, plus revenue from long-term wholesale capacity contracts with neighboring IOUs that diversify its customer base beyond its LPC system. The fleet workhorse role — hosting a substantial share of the national AP1000 buildout on TVA-owned sites with TVA as operator — positions TVA as the central institutional player in the federal clean firm generation program, which is a politically and operationally valuable position to occupy for an agency that has spent the past 30 years managing legacy debt rather than developing major new infrastructure.
IOU partners gain four distinct benefits. They get rate-base position in their segments of anchor transmission lines plus intra-territory integration infrastructure — a growing rate-base position in transmission at a moment when transmission investment is broadly favored by regulators and capital markets. They retain the retail customer relationship with hyperscaler data centers in their territory, preserving retail margin, distribution rate-base, and the long-term customer relationships that underwrite future utility investment. They gain access to firm clean capacity at federally-financed cost without taking construction risk — the wholesale rate from TVA reflects the acquisition price, not actual construction cost, which is substantially cheaper than the IOU could achieve by building nuclear itself. And they get an accelerated solution to data center capacity shortfalls they cannot independently solve, because TVA's operating expertise plus pre-assessed sites plus federal construction financing collectively compress deployment timelines below what any individual IOU can achieve.
The combination is structurally attractive even to IOUs that would otherwise resist federal involvement in their service territories, because the IOU's retail business is preserved and its rate-base position is expanded rather than threatened.
Hyperscalers gain access to long-term firm clean energy at predictable cost on a timeline meaningful to their AI infrastructure investments. The wholesale-to-retail offtake structure delivers nuclear-firmed power through their existing retail utility relationships, which simplifies their procurement and avoids the regulatory complexity of becoming federal direct-serve customers. The PPA terms can be structured for long duration (20-25 years), capacity-heavy with take-or-pay obligations matched to data center load profiles, and indexed to actual finished cost only within defined caps that protect both buyer and seller.
Crucially, the federal cost-overrun absorption structure means hyperscalers face bounded construction-risk exposure. Their Nuclear Construction Reserve Fund contributions are mechanical per-MWh payments calibrated to expected overrun magnitudes across the fleet — a known and stable component of PPA cost. Catastrophic overruns above 120% of acquisition price are absorbed federally, not passed through to hyperscalers. The fleet-wide risk pooling means hyperscalers offtaking from later, lower-risk plants effectively help underwrite earlier plants without bearing direct exposure to any single plant's outcome. The structure makes hyperscaler PPAs financeable for both sides in a way that direct hyperscaler-to-builder construction-cost-pass-through arrangements have not been.
Hyperscalers also gain something less tangible but operationally important: a clear federal commitment to completing federally-supported plants regardless of cost trajectory, which eliminates the VC Summer scenario of stranded PPA commitments for plants that never come online.
The roughly 10 million residential and small commercial customers served by TVA's 153 local power companies are the demographic that has historically borne the worst of nuclear cost overruns — TVA's existing debt portfolio still includes substantial legacy nuclear cost recovery from 1970s and 1980s overruns, generating roughly $1 billion in annual interest expense paid through TVA's wholesale rate. Under the federal-balance-sheet construction model, this category of harm is eliminated for new nuclear: TVA acquires plants at known acquisition prices, and any construction overrun is absorbed federally. TVA's wholesale rate reflects only acquisition-price capital plus operating costs, not actual construction cost. The TVA CEO's public commitment that data center growth will not pressure rates for other electric customers is structurally preserved in every scenario.
TVA residential customers also benefit from the new clean firm generation serving in-territory growth. While substantial shares of new nuclear output will go to hyperscaler load through the fence carve-out, the bulk of TVA's acquired capacity serves TVA's own territory — including ongoing residential and small commercial growth that would otherwise put pressure on TVA's gas and coal fleet. The new fleet improves long-term fuel diversity, reduces exposure to natural gas price volatility, and contributes to TVA's stated decarbonization goals without imposing the construction-cost burden that historically accompanied such transitions.
And TVA residential customers benefit from the resource adequacy improvements that come with new interregional ties. The Winter Storm Elliott rolling blackouts of December 2022 — the first in TVA's history — illustrated the cost of inadequate interregional transfer capacity. The anchor lines this proposal supports both expand TVA's import capability during regional stress events and contribute to the broader resource adequacy of the Eastern Interconnection, reducing the frequency and severity of future events like Elliott.
The roughly 30 million residential and small commercial customers in the IOU territories adjacent to TVA face the most acute version of the affordability question, because their utilities are facing simultaneous pressure from data center load growth, the cost of new generation to serve that growth, and the cost of new transmission to integrate that generation. Without the federal anchor program, these customers face two unattractive futures: either their utilities build new nuclear independently and pass construction overruns through retail rates (the Vogtle/Georgia Power experience), or their utilities decline to build sufficient capacity and reliability suffers.
Under the federal anchor program, IOU retail customers receive new firm clean capacity at the wholesale cost of federally-acquired generation plus their utility's transmission and retail margins — substantially cheaper than the all-in cost would be if their utility built nuclear independently. The construction-cost overrun risk that would otherwise hit retail rates is absorbed federally. The hyperscaler load growth that would otherwise drive massive utility capital programs is partially served by federal generation, reducing the magnitude of utility-side capital that retail customers underwrite. The transmission investment that IOU customers do underwrite (their segment of anchor lines) is bounded, defined, and generates demonstrable interregional capacity benefits.
The mechanism that protects IOU retail customers from cross-subsidizing hyperscaler load is the same mechanism that delivers cost discipline broadly: TVA's wholesale price to the IOU is fixed by the acquisition price (plus operating costs and federal financing margin), and the IOU's retail margin on hyperscaler PPAs covers the IOU's costs of serving that specific load without raiding residential rate structures. State PUCs reviewing the IOU's participation in the anchor program can verify this cost separation explicitly as a condition of approval.
Across all stakeholder classes, the proposal produces three cross-cutting benefits that no individual stakeholder captures fully but all participate in.
The first is resource adequacy improvement across the Eastern Interconnection footprint. New interregional transmission anchored to federally-supported clean firm generation expands the diversity benefits that have been demonstrably lacking during recent extreme-weather events. Every utility connected to the anchor lines gains some capacity to import and export during regional stress, reducing the redundant in-region capacity that would otherwise be required for reliable service.
The second is decarbonization at scale through deployment of a substantial new clean firm generation fleet. The 8-12 GW of potential nuclear capacity from TVA's pre-assessed sites alone represents a meaningful share of the federal target of quadrupling U.S. nuclear capacity by 2050. State clean energy mandates that currently struggle for compliance pathways (especially in IOU territories with growing data center load) gain a viable resource for compliance under structured federal arrangements.
The third is economic development through industrial-base sustainment. AP1000 fleet deployment supports manufacturing, engineering, and skilled trades employment across multiple states, with the DOC partnership projecting roughly 45,000 jobs per two-unit AP1000 project distributed across 43 states. The nuclear workforce capacity built through fleet deployment is itself a national-security asset that has been atrophying since the 1980s and that the program reverses.
A proposal of this scope will attract substantial organized opposition from adjacent investor-owned utilities cast as offtakers rather than generators (Southern, Duke, Dominion, AEP), from IOUs in regions without qualifying public utilities (Ameren, Evergy, FirstEnergy, Xcel, NextEra Florida, and others, organized through the Edison Electric Institute), from independent power producers with established nuclear positions (especially Constellation, which has built substantial commercial momentum on hyperscaler PPAs), and from state public utility commissions in jurisdictions skeptical of federal involvement in retail markets. Each opposition group has different motivations, political reach, and points of leverage; each can be partially addressed through specific structural concessions that preserve the proposal's core architecture.
The most consequential single mitigation is permitting Phase 1 IOU partners to take minority ownership slices (30-40%) in plants alongside TVA's majority position, giving them rate-base participation in new federal nuclear and converting them from conditional opponents to active supporters. Additional mitigations include geographic expansion to multiple qualifying public utilities (reducing the non-adjacent IOU exclusion), operating-partnership arrangements that give IPPs revenue access without ownership or federal cost-overrun absorption, and state-level optionality that channels PUC opposition into local decision points rather than federal blocking.
The proposal optimizes interregional transmission buildout for five reasons specific to the modern political, economic, and risk environment.
It removes construction-cost-overrun risk as a barrier to buildout. The federal-balance-sheet construction model means no utility, no state PUC, and no ratepayer base has to absorb the catastrophic-overrun risk that has prevented new nuclear from being built at scale since Vogtle. The risk goes where it can be absorbed — to the federal balance sheet, with hyperscaler contributions filling the intermediate band. Every other element of the proposal becomes possible only because this central risk-absorption problem is solved.
It converts each new federally-supported clean firm generation project into an interregional transmission opportunity. Every new federally-built AP1000 or SMR becomes a candidate for an anchor line, because the federal construction model removes the financing barrier and the segmented-ownership transmission model removes the cost-allocation barrier. The transmission pipeline scales with the federal generation pipeline, both of which are already being supported through existing instruments (DOC partnership, Office of Energy Dominance Financing, IRA tax credits).
It defuses IOU opposition at the design stage rather than fighting it at the regulatory stage. The IOU has a transmission rate-base position, a retail customer relationship preserved, accelerated access to firm clean capacity, and no construction risk; it has no structural reason to oppose the program. This is the single most important political shift the proposal achieves.
It avoids the cost-allocation fight that kills modern interregional projects. The Pacific Intertie ownership pattern settles transmission cost allocation through ownership rather than through a contested allocation methodology. Sixty-plus years of operational experience demonstrate the pattern's durability.
It uses the federal toolkit that already exists, plus targeted new authorities where needed. Most of the financial and regulatory instruments required (DOC partnership, IRA tax credits, Office of Energy Dominance Financing, federal capital project authorities) are already in place. The new authorities required (Federal Anchor Generation Authority, Nuclear Construction Reserve Fund, cost-overrun absorption authority, TVA Act amendments, transmission siting authority) are substantive but coherent and can be enacted as a single integrated package. This is a more achievable lift than creating a new federal authority on the scale of TVA or BPA, while capturing the structural features that made those entities effective.
The United States built its last great interregional transmission corridor, the Pacific Northwest–Southwest Intertie, sixty years ago. It was made possible by a New Deal–era model that combined federal capital project construction (Columbia River federal hydropower built and owned on the federal balance sheet by the Bureau of Reclamation and the Army Corps of Engineers), public-utility operation under a statutory preference principle (federal hydropower marketed first to public power, cooperatives, and municipal utilities), joint segmented transmission ownership (BPA, LADWP, and IOUs each owning their transmission segments), federal financing (the 1964 appropriation), and reciprocal regional benefit. The corridor has operated reliably for 55+ years, moves roughly 8,000 MW between two regions, and has paid for itself many times over in delivered economic and reliability value.
This proposal generalizes that New Deal model to the 21st-century clean firm generation challenge. The generalization has three essential moves. First, the federal-balance-sheet construction model is extended from federal hydropower to federally-supported clean firm generation, with publicly-owned utilities as acquiring operators and ratepayers protected from construction risk. Second, the public-preference principle is modernized: where the New Deal version offered public power preference in wholesale electricity pricing, the modernized version offers public power preference in federal cost-overrun absorption and federal transmission financing/siting authority — the substantive supports that match the actual 21st-century challenge. Third, hyperscaler offtakers contribute to a Nuclear Construction Reserve Fund that absorbs intermediate cost-overrun risk, ensuring that the corporate beneficiaries of clean firm power share appropriately in the risks their demand creates. All three preserve the underlying logic of the New Deal model — federal generation anchor, public-utility operation, segmented transmission ownership, ownership-driven cost allocation, reciprocal regional benefit — while adapting it to the specific risk profile of 21st-century nuclear deployment.
The Tennessee Valley Authority is the lead pilot for reasons developed throughout this proposal: its pre-assessed never-completed nuclear sites (Bellefonte, Hartsville, Phipps Bend, Yellow Creek) offer a fleet-scale anchor generation pipeline with prior environmental review and existing infrastructure; its existing nuclear operating workforce provides the operational base; and its direct geographic adjacency to four of the highest-growth IOU data center markets in the country (Southern Company in Georgia, Duke in the Carolinas, Dominion in Virginia, and AEP in the Ohio Valley) means anchor lines from TVA territory reach the largest concentrated data center demand in the United States. The framework extends to other qualifying publicly-owned utilities — NYPA in New York, the Nebraska public power group in the Midwest, LADWP in the West, and others — that bring different geographic reach and different qualifying assets but apply the same underlying model.
Federal Anchor Transmission, as outlined here, provides the assembly of all these elements. It is not a new TVA, not a new BPA, not a new Nuclear Power Administration. It is the Bureau of Reclamation / BPA / Pacific Intertie template applied to a portfolio of federally-built clean firm generation projects, with TVA and other qualifying publicly-owned utilities as fleet operators and acquiring entities under a modernized public-preference principle, with hyperscaler offtakers as risk-sharing program participants, and with the existing federal financing, industrial-base, and tax credit toolkit as the support infrastructure. It can deliver multiple new interregional corridors within a decade, at a scale meaningful to the data center load growth currently overwhelming individual IOU planning horizons, with structural features that align participating IOUs as project partners rather than project opponents, protect public-utility ratepayers from construction risk, place catastrophic risk where it can be absorbed (on the federal balance sheet, where federal capital projects have historically borne it), and preserve the public-private distinction that has long structured federal power policy.
It is the most plausible path currently available to substantial new interregional transmission buildout in the United States, and it does so by extending — rather than departing from — the federal power infrastructure tradition that has demonstrably worked for nearly a century.