How Arizona’s Chip Boom Is Rewiring the Southwest Power Grid

A semiconductor complex rising in north Phoenix is prompting one of Arizona’s most extensive electricity expansions in decades. Taiwan Semiconductor Manufacturing Co.’s Fab 21 campus and its power requirements are reshaping how the state plans, finances and dispatches generation resources.

Early site work showed that the local transmission network did not have enough capacity or redundancy for the planned fabrication plants. Planners at Arizona Public Service, or APS, proposed new transmission routes, substation sites and resource agreements before construction on the factory floor could move ahead.

The project’s scale is unusually concentrated. Unlike dispersed residential growth, one industrial customer will draw hundreds of megawatts at start-up and potentially more as the campus expands. That timing compresses decisions on siting, financing and regional coordination that utilities usually make over much longer periods.

Fab-Level Power Appetite

APS classifies the first fabrication plant as an extra-high-load customer that will require roughly 200 megawatts, or about the consumption of thirty thousand Arizona homes, during steady operation, according to the Arizona Technology Council report.

Utility planners treat that figure as a starting point for potential campus growth. APS describes the 200-megawatt estimate as a planning projection rather than a fixed order, because each additional fabrication plant depends on future market conditions and the availability of a skilled workforce.

Modern chip plants consume more energy than earlier generations of facilities. Extreme-ultraviolet lithography tools require continuous high-intensity lasers and vacuum systems, and they run for long periods with limited flexibility. Around-the-clock climate control and water purification systems add further steady demand that is closer to baseload than to short peaks.

Power quality is as important as total power. Semiconductor equipment tolerates only brief voltage deviations, so the utility must design redundant feeders and install voltage-control devices to hold frequency and voltage within tight ranges even when faults occur elsewhere on the grid.

These technical requirements raise costs beyond simple dollar-per-kilowatt calculations. APS has told regulators that dedicated infrastructure for large industrial customers will follow a growth-pays-for-growth principle, in which connection fees cover most site-specific assets while broader network upgrades remain in general rates.

Transmission Overhaul in North Phoenix

To clear the Fab 21 site, APS is relocating 69-, 230- and 500-kilovolt lines that cross the property. The work changes the geometry of major transmission corridors serving north Phoenix and requires close coordination with TSMC’s construction schedule.

The centerpiece of the local grid redesign is the 230-kilovolt Avery Substation, which will step down power for delivery to facility-level transformers. The substation is being configured for high reliability, with multiple feeds and transformer capacity sized for future load growth at the campus and in nearby industrial zones.

It’s a huge project, it’s a huge scale from a customer perspective for the infrastructure that we need to do … we’ve been working with them the last two and half years to make sure we can meet our initial in-service date.

APS has indicated that construction is being sequenced so that no single outage window endangers factory commissioning. The utility has also spent 25 million dollars on additional land north of Phoenix for a second high-load substation that will support TSMC and other customers with large power needs, according to coverage by Williams Luxury Homes.

Transmission relocation has regional implications because moving a 500-kilovolt corridor can change how power flows to fast-growing load pockets in and around Phoenix. Engineers use power-flow models to test whether the new alignments would increase congestion costs or raise the risk of voltage collapse during summer peaks, then adjust designs to keep reliability margins within planning standards.

Record Peaks Reshape Reliability Math

Arizona experienced record peak electricity demand in the summer of 2025. On August 6 and 7, APS reached a peak of 8.631 gigawatts and Salt River Project, or SRP, reached 8.542 gigawatts of instantaneous demand, breaking 2024 records and exceeding their own 2025 forecasts, according to the Arizona Corporation Commission release.

Combined, the state’s three largest utilities reported 24 gigawatts of available capacity as of August 2025. That level covered the record peak but left a narrower margin for contingencies such as plant outages or transmission constraints during extended heat waves.

Prolonged high temperatures also affect gas-turbine performance, because hotter inlet air reduces output and efficiency. In 2025, Arizona’s heat events extended into the night, which limited cooling periods for both the grid and the generating fleet.

Growing peak load changes capital planning in several ways. Higher utilization shortens equipment life and can accelerate depreciation schedules for existing assets. It also increases operating-reserve requirements, which means utilities must contract or build additional resources that can ramp quickly when demand spikes.

Arizona’s rising peak energy demand underscores the critical need for proactive planning.

These conditions sharpen long-running debates about how to pay for new capacity. Regulators and stakeholders weigh whether industrial-specific tariffs can limit the impact of new investments on residential customers, while still giving manufacturers enough rate certainty to support long-term investment decisions.

Generation Plans and Cost Allocation

APS intends to add 7.3 gigawatts of new generation by 2028. The flagship project is the 2-gigawatt Desert Sun natural-gas plant near Gila Bend, described in company filings summarized by Williams Luxury Homes. The first block is targeted for 2030, with later blocks dependent on how much industrial load actually materializes.

Developers chose the Gila Bend area because of available land and existing transmission connections. Long-term drought in the region, however, affects cooling options for large thermal plants and pushes planners to compare water use, efficiency and cost across different technologies.

Financing follows a growth-pays-for-growth model that assigns dedicated equipment to specific customers. Large users sign individual service agreements that include contributions toward feeders, breakers and protective relays that serve their sites. Network-wide reinforcements remain part of the broader rate base, subject to cost-recovery rules set by the Arizona Corporation Commission.

Industrial and data-center connection requests now exceed 19 gigawatts in APS territory, more than double the utility’s 2025 summer peak demand, according to the same reporting by Williams Luxury Homes. Many of these projects may not proceed at full stated capacity, but planners treat the queue as an indicator that load growth could outpace traditional procurement cycles.

If even a portion of that requested load proceeds, annual fuel expenses will rise with generation output. That exposure encourages utilities to seek ways to diversify supply and lower the cost of balancing the system, including participation in broader regional markets.

Entering the Markets+ Platform

Arizona Public Service, Salt River Project, Tucson Electric Power and UniSource Energy have announced plans to join the Southwest Power Pool’s Markets+ day-ahead market, as described in an APS newsroom article. The utilities are targeting participation in 2027, subject to final implementation steps and regulatory approvals.

Markets+ is designed to expand traditional bilateral trading by co-optimizing energy and transmission across more than fourteen balancing areas in the western United States. Participants submit generation offers and load bids one day in advance, and the market algorithm schedules resources to minimize system-wide production costs while honoring congestion limits and reserve requirements.

The Federal Energy Regulatory Commission approved the Markets+ tariff in 2025, clearing a key legal requirement for implementation, according to the Southwest Power Pool announcement. For Arizona utilities, day-ahead integration could provide access to hydroelectric power during evening ramps and to surplus solar generation from neighboring states on milder days.

Regional access has the potential to influence where generators and large industrial customers choose to invest. If off-peak power becomes cheaper through pooled markets, manufacturers may have incentives to schedule high-energy process steps at night, which would smooth the load profile and reduce the amount of fast-ramping capacity that APS must maintain.

Market participation, however, does not remove the need for in-state capacity. Planners must assume that import transmission could be limited during extreme heat or wildfires, so local reserves remain central to reliability planning. The challenge is to balance market purchases against recovering the fixed costs of new gas plants such as Desert Sun.

Policy Context and Siting Constraints

Arizona regulators weigh several objectives at once: maintaining reliability, limiting customer bills and supporting the economic benefits of advanced manufacturing. As semiconductor and data-center projects receive more attention in Arizona chip news coverage, the links between industrial policy and grid planning have become more visible.

Natural-gas construction faces two main resource constraints in the region. One is fuel supply during regional cold snaps, when pipeline capacity is shared with other states. The other is access to cooling water under long-term drought conditions in the Colorado River basin and related watersheds.

High-voltage line routing also has to account for public land, tribal lands and wildlife habitats. APS has reported the use of power-flow simulations and aerial surveys to narrow potential corridors in ways that avoid protected areas while maintaining electrical clearances, followed by stakeholder workshops and visual-impact assessments before the Arizona Corporation Commission issues a certificate of environmental compatibility.

Cost allocation remains a central policy question. Stakeholders debate how much of the cost of peak-capacity additions should be assigned to high-load industrial customers and how much should stay in the general rate base, given that grid reliability is a shared service that benefits all users.

Decisions in other western states indirectly affect Arizona’s options. If states such as California tighten electricity export rules during emergencies, assumptions about available imports through Markets+ may need to be revised. Conversely, expanded transmission projects in the wider region could lower future delivered energy prices into Arizona.

Outstanding Risks and Timelines

Fuel procurement for Desert Sun is a major planning issue. Firm gas-transport contracts with interstate pipelines typically require long-term commitments and credit support, and they are often negotiated years before a plant enters service. If industrial demand arrived more slowly than expected, those fixed obligations could place additional pressure on utility finances and regulatory reviews.

Water availability is another key variable for large thermal plants. While the use of reclaimed effluent can reduce groundwater withdrawals, municipalities may change allocation priorities during extended drought, which could push generators toward air-cooling options that reduce water use but lower efficiency and raise operating costs.

Additional semiconductor suppliers and equipment manufacturers are likely to influence the overall load profile around Phoenix. As suppliers follow anchor tenants, their own facilities add to local demand and may require further substation and transmission upgrades that build on the initial TSMC-related investments.

Markets+ design details are still under discussion. Settlement timelines, transmission-usage charges and congestion-rent allocation remain in stakeholder processes, and utilities are analyzing how those choices could affect annual market-purchase costs and investment decisions for in-state capacity.

Supply-chain constraints add another layer of uncertainty. Lead times for large power transformers and high-voltage equipment have increased, so any delay in ordering can cascade through construction schedules for both generation projects and transmission lines that serve new industrial loads.

Conclusion

TSMC’s Phoenix campus shows how a single industrial investment can trigger statewide infrastructure changes that reach from local substations to regional market design. New generation projects, transmission realignments and market integration efforts all need to arrive in sequence for the factories to meet their production targets without straining the grid.

Whether Arizona becomes a long-term semiconductor manufacturing hub will depend in part on how accurately utilities translate today’s projections into synchronized assets. Outcomes in the state are likely to shape how other western jurisdictions plan for large industrial projects under similar heat, water and reliability constraints on an increasingly complex power system.

Sources

• Arizona Technology Council. "Utility company makes progress on infrastructure for Taiwan Semiconductor project in North Phoenix." Arizona Technology Council, 2022.


• Arizona Corporation Commission. "Arizona electric utilities set record high demand—again—demand soars above original forecasts for 2025." Arizona Corporation Commission, 2025.


• Williams Luxury Homes. "APS Plans 2,000-MW Desert Sun Power Plant in Gila Bend." Williams Luxury Homes, 2025.


• Arizona Public Service. "Arizona utilities plan to join Markets+ to strengthen grid reliability and resilience." APS Newsroom, 2025.


• Southwest Power Pool. "SPP's Markets+ tariff receives FERC approval." Southwest Power Pool, 2025.