Nevada's $1B transmission rebuild: Who pays for aging-line replacement when demand surges?

The Review Journal reported that GridLiance West, a subsidiary of NextEra Energy Transmission, held a groundbreaking in September for the Core Upgrades Project, a 155-mile rebuild of 230-kilovolt and 500-kilovolt transmission lines across Clark and Nye counties, expected in service by 2028^[1][8]. The same month, LS Power's Great Basin Transmission began construction on SWIP-North, a 285-mile, 500-kilovolt interregional line from Idaho to Nevada, a $1 billion-plus project two decades in development^[2][3]. Both projects carry a similar claim: they are necessary infrastructure. Both should be tested against that claim with the same skeptical measure.

Start with the Core Upgrades Project. GridLiance West says the rebuild will add 1 gigawatt of transfer capacity to southern Nevada's bulk electric system and replace aging infrastructure nearing the end of its useful life^[7][8]. That dual framing, replacement plus capacity, matters because it conflates two different cost-allocation questions. Replacing worn-out lines is a legitimate reliability function; the cost belongs on ratepayers' bills because all ratepayers benefit from not losing power. Adding capacity to serve new demand is a different problem: it is a growth investment, and under FERC Order 1920's beneficiary-pays principle, the parties whose load creates the need should fund it^[4]. Nevada regulators have not yet resolved which part is which. NV Energy's 2026 Integrated Resource Plan identified interest representing about 22,000 megawatts of potential new electricity demand, compared with Nevada's current system peak of roughly 8,500 megawatts, much of it from data centers^[9]. None of that demand has been approved for service. If the Core Upgrades Project is being right-sized to handle unapproved speculative load, Nevada ratepayers are prepaying for capacity they may never use, and data-center customers, who can afford to wait, are getting a subsidy from the people powering their air conditioning now.

The remedy is a transparent needs assessment, filed in advance and open to challenge. Before GridLiance or any incumbent transmission owner sizes a regional upgrade, Nevada regulators should demand: (1) a detailed thermal and congestion study of the current system under today's load, separated from a forecast study of tomorrow's; (2) a GETs-first screening, dynamic line ratings, advanced reconductoring on existing towers, topology optimization, comparing their cost and deployment time against the capital rebuild; (3) a detailed demand forecast, broken down by customer class and explicit on which new loads are contracted versus speculative; (4) cost-allocation columns showing what the ratepayer-funded replacement bucket looks like and what the data-center-funded growth bucket looks like; and (5) an independent transmission monitor reviewing the company's analysis. GridLiance West, which earns a FERC-regulated return on every dollar of capex, has an incentive to oversize the project. Regulators have to supply the scrutiny the profit motive removes.

SWIP-North operates under a different set of pressures but raises the same question in a different form. The project is an interregional line, designed partly to move Idaho wind south to California and partly to move desert generation north to Idaho Power, with 2,000 megawatts of bidirectional capacity^[2][3]. That two-directional design is elegant and real, the West's grid does benefit from greater interregional flow. But the cost-allocation fight is live, and it will shape whether SWIP-North becomes a model for competitive transmission or another example of how incumbents socialize costs while privatizing returns. FERC Order 1920 requires regions to select benefits (production-cost savings, reliability, resilience, avoided-cost, capacity) when allocating costs for interregional lines, and the definitions matter enormously. If California's ISO counts Idaho wind access as a production-cost benefit to California ratepayers, California pays. If instead the benefit is framed as enabling Idaho Power to shed thermal generation (a resilience benefit to the whole system), the cost spreads across all Western regions, and Idaho ratepayers who see little of the Idaho wind subsidy the line move. This fight is currently being litigated in the Fourth Circuit and resolved in regional compliance filings through 2025 and 2026^[4]. LS Power did not bid SWIP-North competitively; it developed the project over two decades and brought it to construction through incumbent utility coordination. Had Nevada or the West's regional planners run a competitive solicitation, the price comparison would reveal whether LS Power's timeline and cost were market-standard or inflated by the developer's long hold. That comparison will never happen now.

Both projects may be justified on their merits. The West's grid does need interregional capacity, and Nevada's southern infrastructure is aging. But justification and transparency are not the same thing. The mechanism that decides who pays, cost-allocation rule in Nevada's regulatory commission for the Core Upgrades Project, FERC Order 1920 benefits definition for SWIP-North, is where the money actually flows. Regulators have not yet forced either question into the open record with independent analysis. That omission is not accident; it is structural. Incumbent transmission owners profit from building without competition and from cost-allocation definitions that spread the cost across the widest possible pool of payers. The remedy is the same in both cases: transparent, independent, GETs-screened needs assessment; competitive solicitation for the build; and a clear, narrow beneficiary-pays cost allocation that keeps the payer and the beneficiary in the same sentence.