Infrastructure

The EV Funding Problem

The federal gas tax — last raised in 1993 — funds highway maintenance. As EV adoption grows and vehicles become more fuel-efficient, less fuel is purchased and less tax is collected, while road usage remains constant. The Highway Trust Fund is running a structural deficit that will only grow. A vehicle miles traveled (VMT) tax is unworkable because many states no longer conduct vehicle inspections, making it effectively an honor system.

EV Annual Registration Fee — $75

Electric vehicles pay an annual registration fee of $75 to contribute to highway infrastructure they use but do not fund through fuel taxes. A politically accessible entry point that scales as EV adoption grows.

EV Charging Tax

A 9% point-of-sale tax is applied to the sale of EV chargers and charging accessories. Point-of-sale collection means enforcement happens at the manufacturer and retailer level — no individual compliance required, no honor system. A Level 2 home charger costs $500–$2,000; even a modest percentage generates meaningful infrastructure revenue per unit and scales with adoption.

The 9% rate is a starting figure, not a final Treasury-modeled number — it was derived as a round placeholder pending formal revenue modeling, the same honesty standard applied elsewhere on this page (see the pending figures noted in Economics). It should be treated the same way: directionally right, not yet precisely scored.

Maintenance First

American infrastructure doesn't need more ribbon-cuttings. It needs upkeep. ASCE's 2025 Infrastructure Report Card grades US roads D+ — 39% of major roads are in poor or mediocre condition. FHWA's own breakdown of the $151.1 billion needed annually for highways shows $87 billion required for rehabilitation and maintenance, against roughly $64 billion for expansion and enhancement combined — the maintenance backlog is already the bigger number, not a rounding error next to expansion spending. ASCE itself warns the recent modest gains are 'vulnerable without sustained post-2026 investment.' This platform's position: federal infrastructure dollars prioritize bringing the existing system into a state of good repair before funding new capacity. Take care of what exists first.

Remote-Capable Contractor Preference

Federal procurement — not just infrastructure contracts, but the full range of federal contracting: IT services, database hosting, professional services, administrative support, call centers, software development — gives scored preference to contractors built around remote work, wherever the work itself doesn't require a physical presence. This doesn't apply to contracts that inherently require people on-site — construction crews, physical maintenance work, in-person services keep the same requirements they have today. It applies to the large share of federal contracting that doesn't.

The strongest case for this is direct and well-established, not speculative: remote-capable contractors typically carry lower overhead (office lease costs the government isn't paying for, directly or indirectly, through contract pricing), and remote hiring gives contractors access to a nationwide talent pool instead of being restricted to expensive metro areas clustered around federal facilities — including qualified workers in rural and small-town America who currently have no practical path into federal contracting work without relocating.

There's a real, secondary infrastructure benefit too, and it deserves an honest accounting rather than an inflated one. Rigorous pandemic-era research (Nature Cities, 2024) found a nearly 1:1 relationship between reduced on-site work and reduced vehicle miles traveled — a 1% drop in on-site workers corresponded to a 0.99% drop in state-level VMT. But more recent research complicates the larger claim: a 2025 peer-reviewed study found traffic congestion returned to pre-pandemic levels despite sustained remote and hybrid work, because remote work has a 'complementary' effect on travel, not a purely substitutive one — more leisure trips, more delivery traffic, and in some cases longer total daily travel distance for full-time remote workers than for regular commuters.

The preference is conditioned on a specific safeguard aimed directly at that problem: eligibility requires the contractor's remote workforce be geographically tethered — employees verified, through VPN or equivalent network-location technology, to be based within a defined radius (for example, 50 miles) of a designated home location, not free to work from anywhere. This targets the actual mechanism the 2025 research identified as driving the increase in total travel: 'workcation'-style remote work, where employees travel widely while remaining nominally employed, drives sprawl and long-distance travel that fully offsets the commute savings. Tethering a worker to a home region closes that specific failure mode.

Be precise about what this does and doesn't solve. It meaningfully strengthens the case against the long-distance, sprawl-driving version of the rebound effect. It does not eliminate the local-trip version — the same research found remote workers generate more discretionary local trips (errands, midday driving) than commuters, and a geographic tether doesn't touch that. The honest claim this platform makes: geographically-tethered remote-capable contracting reliably reduces peak-hour commute congestion and mitigates, but doesn't eliminate, the broader rebound effect on total travel. It is not a claim that this alone solves the national road-maintenance funding gap — that gap gets closed by the funding prioritization above, not by fewer commuters.

This isn't a new category of employer oversight — it's the same oversight federal contractor employees already work under, in a different medium. An in-office federal contractor employee is already tracked: badge access logs, building security cameras, sign-in requirements, and in security-cleared roles, considerably more intensive monitoring than that. VPN-verified geographic tethering for a remote employee is the same underlying employer interest — confirming where work is actually being performed — implemented digitally instead of physically. The workplace environment changes. The fact that federal contractor employees' work location is subject to verification does not.

Data Centers Pay Their Own Way on the Grid

A large data center campus can draw as much power as a mid-size city. Nationally, data centers are on pace to require 167 gigawatts of capacity by 2030, and one estimate puts the total electricity cost attributable to data centers at nearly $1 trillion over the next 25 years. The fight happening in statehouses right now is over who pays for that — the company that needed the power, or the household next door whose rate goes up to fund the grid upgrade that made it possible.

This is fundamentally a local and state matter, not a federal one — retail electricity rates, utility cost allocation, and grid interconnection terms are set by state Public Utility Commissions and local utility boards, not federal agencies. A Sunsetter serving on a PUC, in a state legislature, or on a local utility board brings the same standard to every case, built from the strongest pieces of real, already-enacted state models rather than invented from scratch: a dedicated large-load rate class for data centers above a defined power threshold (Oregon uses 20 megawatts; Texas uses 75); a ratepayer-benefit test, modeled on Alabama's law, requiring a data center's grid connection to demonstrate it won't raise costs for existing customers before approval, not after; an explicit rule against shifting data-center infrastructure costs onto residential and commercial households, modeled on Florida's law; and minimum-bill contract structures, following Texas's model, so a company can't trigger an expensive grid upgrade and then walk away from paying for it. A Sunsetter who abandons this standard once in office answers to the same mechanism as everywhere else in this platform — a primary challenge.

None of this is about blocking data centers — it's about making sure the company that needs the power pays for the power, not the neighborhood next to the substation.

Residential Solar: Restore the Incentive, Mandate for New Construction

The aggregate rooftop surface area across America's roughly 140 million homes represents a genuinely enormous, currently untapped generation capacity. But a federal mandate requiring solar on every existing home isn't legislatively realistic — building codes are state and local police power, not federal authority, and retrofitting tens of millions of already-built homes raises real cost and practicality problems a new-construction requirement doesn't.

The real, proven state-level precedent is California's Title 24 (effective 2020) — the first and still only state mandate, applying solely to new construction and low-rise multifamily buildings, adding roughly $9,500–$10,000 to construction cost, offset by a projected $19,000 in energy savings over 30 years. A Sunsetter serving in state or local government supports this same new-construction requirement, following the one model that's actually been built and tested — not a broader mandate with no working precedent behind it.

For the existing housing stock — the vast majority of American homes — the real, urgent problem isn't the absence of a mandate. It's that the primary federal incentive for voluntary adoption was just eliminated. The 30% Residential Clean Energy Credit (Section 25D), in place for over a decade and scheduled under the Inflation Reduction Act to run through 2032, was repealed outright by the One Big Beautiful Bill Act, effective December 31, 2025 — with no phase-down, a hard cliff to zero. Homeowners who buy or finance their own solar system in 2026 receive no federal credit at all; the only remaining path to any federal value is a third-party lease or power purchase agreement, where a company owns the panels and captures the commercial credit instead — a materially worse deal for the homeowner than owning the system outright. This platform's position: restore the Section 25D credit, at least at its prior 30% rate, as the actual mechanism for reaching the existing housing stock a building-code mandate can't touch.

Undergrounding Electrical Distribution Lines: Targeted, Not Blanket, With Ratepayer Safeguards

Undergrounding overhead distribution lines reduces wildfire ignition risk by an estimated 98% — a real, substantial safety benefit, not a marginal one. But it costs $2.6 million to $6.1 million per mile, and a blanket national requirement isn't realistic: fully undergrounding just one utility's overhead lines (PG&E's 81,000 miles) has been estimated at roughly $240 billion, about $45,000 per customer. Treating this as an 'underground everything' mandate would be a fiscal and ratepayer disaster, not a workable policy.

The real, working model: all new and retrofitted distribution lines are required to be underground going forward — the same new-construction-first logic as the solar requirement above, since undergrounding is dramatically cheaper when a road or development is already under construction than as a standalone retrofit. For existing overhead lines, undergrounding is prioritized specifically in areas of genuine, documented wildfire risk — not applied uniformly regardless of actual risk — following the same targeting utilities already use in high fire-risk regions today.

This needs a real ratepayer safeguard this platform has already built elsewhere: utilities earn a guaranteed rate of return on capital investment, not on the electricity they sell, which financially rewards choosing the more expensive infrastructure option regardless of whether it's the most cost-effective way to reduce risk. The same ratepayer-benefit test already required for data center grid connections elsewhere in this platform applies here directly: an undergrounding project has to demonstrate it's the most cost-effective way to achieve the safety or reliability goal — not just the most capital-intensive one a utility's own financial incentives favor — before its cost gets passed to ratepayers.

Community Battery Banks in Housing Developments

Rooftop solar generates power when the sun shines. A community battery bank is what converts that intermittent generation into reliable power — storing midday surplus and discharging it during evenings, weather events, and grid failures. This is the third piece of the grid-modernization picture, alongside rooftop solar and underground distribution lines, and the economics of it have changed fundamentally in the last few years.

For new housing developments specifically, a shared community battery bank is cheaper and more effective than individual home batteries — the same infrastructure logic that makes a shared water main cheaper than 50 individual wells. A subdivision-scale Lithium Iron Phosphate (LFP) battery system, integrated at the development stage rather than retrofitted home by home afterward, can be sized to carry the whole development through an outage, supply backup power to any home in the community regardless of whether that individual home has its own solar panel, and be managed by a single smart controller rather than 50 separate residential systems. LFP specifically — the chemistry preferred for residential-scale stationary storage in 2026 — carries a 15-20 year lifespan and an excellent safety profile compared to earlier lithium chemistries.

New housing developments above a defined unit threshold are required to include a shared community battery system sized for the development's baseline load — the same new-construction logic applied to the rooftop solar requirement above. This is a state and local planning/building code matter, not a direct federal mandate, and follows the same Sunsetter-commitment pattern: a Sunsetter serving in local planning or state housing code roles supports this requirement as part of subdivision approval standards, the same way water and sewer infrastructure is already treated as a non-negotiable part of what a development is required to provide.

The economics make this easier to build politically than it might sound: a community battery bank isn't only a resilience cost — it's a potential revenue source. Through Virtual Power Plant (VPP) programs, neighborhoods are now leasing their spare battery capacity back to utilities during peak demand periods in exchange for monthly stability credits, offsetting the cost of the storage infrastructure over time. Minnesota's Public Utilities Commission approved Xcel Energy's 200-MW battery-based VPP program in April 2026; Illinois approved VPP tariffs in June 2026 under the Clean and Reliable Grid Affordability Act; and New Orleans is deploying a $30 million solar-plus-battery VPP with installations beginning in 2026. These aren't demonstration projects anymore — they're utility-approved, ratepayer-funded programs operating at scale.

The proven case study for resilience specifically is Puerto Rico after Hurricane Maria: a cooperatively managed community microgrid with 700 solar panels and battery storage kept 14 local businesses and community services running for nearly six months after the wider grid failed — during a period when many neighborhoods had no power at all. That's the actual value proposition a community battery bank provides that no individual home battery system can match: shared capacity means the whole community stays up, not just the houses wealthy enough to have their own storage.

Consumer Ownership of Electric Utilities

Who owns your utility determines whose interests it serves — and the price you pay for power proves it. In Washington State, the gap between investor-owned and consumer-owned utilities is among the most visible anywhere in the country: Puget Sound Energy, an investor-owned utility, charges residential customers roughly 17-18 cents per kilowatt-hour. Snohomish County PUD, a consumer-owned public utility district serving the same state and buying power from the same Bonneville Power Administration hydropower system, charges 10-11 cents. That's not a marginal difference — it's nearly double the rate for structurally identical power, explained almost entirely by whose interests the utility is organized to serve.

An investor-owned utility is accountable to its shareholders. Its rates are set to recover costs and earn a profit return; the state Public Utilities Commission oversees those rates but can't override the fundamental profit obligation built into the structure. A consumer-owned utility — a public utility district, a municipal utility, or an electric cooperative — is accountable to its customers, who are also its owners. There are no shareholders to earn a return for. Governance sits with an elected or community-accountable board. Rates are set to recover costs and invest in reliability, not to grow earnings for outside investors. Surplus goes back into the system or to ratepayers, not out to distant stockholders.

Washington has 28 PUDs — more than any other state — and roughly 60% of Washington residents are served by publicly owned utilities. That public-power culture is a real, working proof of concept for what this platform supports nationally: expanding consumer-owned utility models as the structural answer to the ratepayer-protection problem that keeps showing up across every other infrastructure plank in this section. The ratepayer-benefit test for data center grid connections, the prohibition on utilities cost-shifting to households, the accountability mechanisms for undergrounding decisions — these are all patches on a fundamentally misaligned incentive structure that consumer ownership corrects at the root.

This platform is not proposing to nationalize existing investor-owned utilities, nor does it claim forced municipalization is a simple or cheap process — buying out an IOU's existing infrastructure at market value is expensive, and several communities have tried and concluded the costs outweigh the immediate benefits. The position is narrower and more achievable: federal policy and federal funding should systematically favor the formation of new consumer-owned utilities, cooperatives, and municipal utility districts in areas currently underserved or overcharged by investor-owned utilities, and should provide financing mechanisms (Rural Utilities Service loans, federal green bonds) that give consumer-owned entities access to the same capital markets investor-owned utilities access through private equity — removing one of the key structural disadvantages that makes the IOU model sticky even where consumers would prefer an alternative.

Favorable Federal Funding Access: Consumer-Owned Utilities

Consumer-owned utilities — public utility districts, municipal utilities, and electric cooperatives — get scored preference in federal energy infrastructure grant and loan programs, matching the same carrot-first logic this platform applies to Benefit Corporations in federal contracting and remote-capable contractors in federal procurement.

The infrastructure for this already exists and is already substantial: USDA's Rural Utilities Service Electric Loan Program provides $7 billion in authorized lending for FY2026 — boosted by $500 million in the most recent spending deal precisely because demand already exceeds available funding. The new PART Program (Powering Affordable Reliable Technology, announced August 2026) makes $410 million in partially forgivable loans available for hydropower, geothermal, biomass, and energy storage projects, with individual awards up to $100 million and up to 40% forgiveness — accepting letters of interest through October 9, 2026. DOE's Loan Programs Office provides additional financing pathways.

This platform's position: these programs are extended in scope and made explicitly preferable for consumer-owned entities, not just eligible alongside investor-owned utilities. A consumer-owned utility applying for federal grid modernization funding — solar integration, underground distribution lines, community battery storage — gets a real scoring advantage, same as a Benefit Corporation competing for a federal contract.

One honest structural gap this doesn't fully resolve: RUS programs are predominantly rural by statutory authority under the Rural Electrification Act. Consumer-owned utilities serving suburban and semi-rural areas (like SnoPUD in Snohomish County) typically qualify, but communities in dense urban areas served by investor-owned utilities — often where the rate disparity is most acute and where residents most want an alternative — frequently don't. This platform supports expanding RUS eligibility criteria or creating a parallel DOE grant track that reaches urban and suburban communities, not just rural ones, so the structural advantage isn't geographically limited to the communities that already have the best access to alternative utility models.

Excess Profit Return and Non-Operational Expense Prohibition

Two additional standards apply to investor-owned and privately-owned utilities operating under state PUC oversight.

First, excess profits return to ratepayers as bill credits. A utility's authorized rate of return on equity is already set by the state PUC — that's the existing, approved profit level. Any revenues the utility actually earns above that authorized return must be returned to ratepayers in full, as a clearly labeled credit on their bill, annually. Not retained as shareholder profit. Not rolled into executive compensation. Not used to fund future capital projects that generate another authorized return. The New York State Senate passed exactly this standard in 2025 (S.7693), requiring utilities to return every penny above their PSC-approved return to ratepayers. This platform supports that standard as a national model.

Second, ratepayers do not fund utility lobbying, advertising, or entertainment. These are not operational expenses that serve ratepayers — they are costs incurred for the benefit of shareholders and management. A utility that lobbies against consumer protection legislation, funds trade association dues, or runs image advertising is doing so at ratepayer expense under the current system. Massachusetts and New York have both advanced legislation prohibiting utilities from passing these non-operational costs to ratepayers. This platform supports the same prohibition nationally: non-operational expenses — lobbying, entertainment, political contributions, trade association membership, and brand advertising — come out of shareholder profit, not ratepayer bills.