La Osa Data Center: Where Does the Power Come From?

LA OSA DATA SERIES — PART 2

This series examines the proposed La Osa Data Center rezoning on the Pinal County Board of Supervisors’ May 27, 2026 agenda. Article 1 examined the project’s $100 million in property taxes. This article examines the power supply questions. Article 3 examines water.

The Palo Verde Nuclear Generating Station, in Arizona, is the largest nuclear generating facility in the western United States, described by Power Magazine as a “nearly 4-GW” facility. The Vermaland La Osa Data Center press release proposes a campus that would support up to 3 gigawatts of power, a scale approaching three-quarters of Palo Verde’s rated generating capacity.

But having a power line nearby is not the same as having power.

Quick Look

• The decision: On May 27, the Pinal County Board of Supervisors votes on a rezoning that would let a $33 billion data center campus be built on 3,374 acres. At full buildout, it would consume electricity up to three-quarters of what the largest nuclear plant in the western United States generates.
• A rezoning is hard to undo. Once granted, the land-use designation stays whether the project is built or not.
• No utility has actually said yes. APS confirmed in April it has zero commitments to any Pinal County data center. The local district (ED4) said it could serve, but ED4 doesn’t generate its own power; it resells what it buys from utilities like APS that have made no commitments.
• No one knows yet if the grid can handle this. Interconnection studies are happening, but no preliminary results are public.
• Phase 1 depends entirely on existing power lines. The application doesn’t say if those lines have enough capacity.
• The project’s gas supply isn’t confirmed. The application doesn’t address pipeline capacity or whether the project would have firm or interruptible service. On interruptible service, the campus would switch to grid power during peak demand, exactly when the grid is most stressed.
• The project depends on grid power even at full buildout. On-site gas plants would generate up to 2,000 megawatts; the campus would support up to 3 gigawatts. The 1,000-megawatt difference would have to come from the grid, but no utility has committed to deliver it.
• The developer’s commitments aren’t legally binding. Promises about cost, gas plant design, and cooling sit in the project narrative, not in the 33 zoning conditions the Board approves.
• The equipment itself takes years to arrive. Transformers and large gas turbines now have 2-7 year industry-wide wait times.
• Residents could absorb costs. Recent reporting shows Arizona residential electric rates rose nearly double the rate of business rates as data center demand grew. Regulators are examining whether existing protections are enough.

What the Project Proposes: Power by Phase

The three-phase structure of the campus is central to the power story. According to the La Osa application:

• Phase 1 (Northwest): First data center buildings and a land donation for a future fire station. No on-site gas generation. Entirely dependent on grid interconnection.
• Phase 2 (Central): Additional buildings plus the first gas-fired power generation facility and a 500-kilovolt (500kV) substation and switchyard.
• Phase 3 (Southeast): Remaining buildings, a second gas-fired power plant, and a second 500kV substation and switchyard, reaching a maximum of 59 buildings.

Many of the details that would allow the county to evaluate whether this project can deliver what it proposes are still outstanding, ranging from basic technical specifications to binding utility commitments. This article examines what is missing, what has since emerged, and why it matters for the upcoming vote.

Getting Power to the Site

Who Provides the Power

According to the application, several entities could be involved in the project’s power supply: the Western Area Power Administration (WAPA) owns the 115kV transmission lines crossing the central portion of the property, APS owns the 230kV transmission line crossing the southern parcels, and Electrical District No. 4 (ED4) is the local utility district that could deliver power to the site. The central question for Phase 1 is whether those lines, as they exist today, can deliver the power Phase 1 buildings will need. Every megawatt Phase 1 consumes must come from the grid. Just because a major highway runs past your property doesn’t mean the state will let you build a private off-ramp, and it doesn’t mean the highway isn’t already gridlocked. Transmission lines work the same way: physical presence and usable capacity are different questions. The available capacity of those lines, and the cost or timeline of any required upgrades, are not stated in the application.

The applicant’s Water Memo Addendum, a supplemental technical document prepared by EPS Group, assumes 2,000 MW of on-site generation; the Vermaland press release states the campus would support up to 3 GW of power capacity. That leaves a potential gap of roughly 1,000 MW between the on-site generation assumption and the press release’s stated figure.

At the April 15, 2026 Pinal County Board of Supervisors work session, APS Director of Data Center Strategy Patrick Bogle told the Board that APS has committed to serve approximately 4.5 gigawatts of data center load through 2030-2032 across its service territory, while another 20+ gigawatts of data center customers have requested service but do not have APS commitments. Asked specifically about Pinal County, Bogle confirmed that none of APS’s 4.5 GW commitment covers any Pinal County data center project. APS service territory in Pinal County, per Bogle’s testimony, includes Eloy, Coolidge, and Casa Grande and is among APS’s fastest-growing areas, but as of the work session date no APS data center commitments existed for the county. While ED4 is the local utility district that could deliver power to the La Osa site, ED4 does not generate its own electricity; it purchases power at wholesale rates from other companies and resells to end users. The bulk power must come from regional generation accessed through the broader transmission grid that APS and WAPA operate.

On April 7, 2026, ED4 General Manager Derek McEachern wrote that the District “is prepared to serve” subject to “significant infrastructure improvements” and “appropriate financial commitments from the applicant.” Neither condition is defined in the letter.

At the November 19, 2025 Comprehensive Plan hearing, Vice Chairman Jeff McClure noted that statute restricts a project from directly selling its own power, and asked applicant attorney Court Rich how the arrangement would work. Rich confirmed: “we anticipate we’ll have ED4 taking possession of that energy and selling it to us… It’s not fully worked out yet.” Even the project’s on-site generation would route through ED4.

The 500kV Substations: Built for What?

The site plans show a proposed 500-kilovolt substation and switchyard at each of the two gas plant sites, one in Phase 2 and one in Phase 3. The 500kV class is bulk transmission, not on-site distribution, which means the project is engineered for connection to bulk transmission lines outside the site. The application does not describe how that off-site connection would be established. The La Osa site is near TEP’s existing 500 kV transmission corridor that runs from the Pinal Central substation east of Casa Grande to the Tortolita Substation southeast of Red Rock. The application’s depiction of two 500 kV substations does not by itself establish that La Osa has secured an interconnection, available transmission capacity, or approval to connect to that line.

Who Pays

A project of this size would likely require transmission upgrades, a point the applicant itself acknowledges in the project narrative. In recent Arizona large-load agreements involving utilities regulated by the Arizona Corporation Commission (ACC), the ACC has approved arrangements in which the data center customer pays for upgrades attributable to its load. The clearest documented example is the December 2025 Energy Supply Agreement between Tucson Electric Power (TEP) and Beale Infrastructure Group for Project Blue, where ACC Vice Chair Myers stated he was “pleased to hear TEP confirm that the data center will fully cover the construction costs for the necessary line extensions and new switchyard, ensuring that no expenses are shifted onto other customers.” The ACC itself has opened a docket to evaluate whether existing protections are sufficient, citing the case-by-case nature of current Energy Supply Agreements, the limits of ACC authority over non-ACC-regulated utilities, the lack of transparency in confidential contracts, and the scale of pending data center development. According to the ACC, approximately 1,300 MW of data center capacity is under construction in Arizona and more than 4,000 MW is in planning stages.

Even where the ACC framework directly applies, the existing protections have not entirely prevented cost-shift patterns. According to Arizona Capitol Times reporting, residential rates in APS territory rose approximately 11.2% between 2023 and 2025, nearly double the increase faced by business customers. Over the same period, 12News reported that data centers were projected to account for 94% of growth in APS’s energy demand, based on APS’s own planning documents. Separate 12News reporting found residential customers used 5% less electricity while paying 23% more. Multiple factors influence retail electric rates, including fuel costs, transmission investment, and utility capital expenditures. Whether data centers alone caused these increases is not the point. Arizona regulators are now examining whether current frameworks protect ratepayers as large-load growth accelerates.

Two of the entities involved in La Osa’s power supply are not regulated by the ACC. ED4 is an Arizona political subdivision under its own elected board (Arizona Constitution Article 13, Section 7). WAPA is a federal agency that sets its own rules under its Open Access Transmission Service Tariff. Neither answers to the state regulator that sets APS and TEP rates. Which utility or combination of utilities will ultimately serve the project, and under which regulatory framework, has not been publicly clarified. How any of these entities would address the cost-shift patterns the ACC is now examining has not been publicly addressed. Pinal County residents are utility customers in this system, directly served by ED4, APS, and other Arizona utilities, and indirectly affected by statewide rate patterns. The Board’s decision on rezoning is one of the few formal points where the county can consider these patterns before they apply locally.

ED4 serves a defined geographic area in Pinal County, while APS and other ACC-regulated utilities serve customer bases in the millions. If ED4 funds significant infrastructure for La Osa and the project is later canceled or scaled down, the customer base available to absorb any unrecovered costs is substantially smaller than at a larger utility. ED4’s internal protections against this exposure, and what cost-recovery commitments it would require from La Osa, are not in the public record.

Gas Supply

The El Paso Natural Gas (EPNG) pipeline system, owned by Kinder Morgan, runs approximately 2.5 miles west of the site according to the application documents, and is the nearest gas supply source for the proposed on-site power plants. Proximity is a starting point, not a guarantee. The available capacity in the segment closest to La Osa, and whether Kinder Morgan would commit to serving a new industrial load of this size, are separate questions the application is silent on.

At the April 16, 2026 Planning and Zoning Commission hearing, Commissioner Hartman asked whether the project would need the Transwestern pipeline. Rich indicated that some initial EPNG gas availability may exist for the early phases of the project, but that as the project grows it will need additional pipelines currently under construction or proposed, including Transwestern, to bring gas into Arizona from Texas and New Mexico.

Energy Transfer’s Desert Southwest expansion of the Transwestern system, set to be in service in Q4 2029, will add capacity along the Phoenix Lateral and a new Desert Basin compressor station in Pinal County. Delivery points are described broadly as new and existing locations in Arizona and New Mexico. Any service to the La Osa site would require lateral infrastructure beyond what is publicly disclosed, and La Osa has not been publicly identified as a shipper.

In August 2021, a pipeline rupture in the El Paso Natural Gas system near Coolidge killed two people and seriously injured one. According to the National Transportation Safety Board (NTSB) investigation report, the probable cause was stress corrosion cracking. The capacity of the specific EPNG segment near the La Osa site does not appear in publicly available materials reviewed for this article. Any preliminary capacity and integrity information from Kinder Morgan would help the Board evaluate the project’s gas supply plan.

A separate question concerns the service tier under which gas would be delivered. Pipeline service can be contracted as firm (guaranteed delivery) or interruptible (subject to curtailment during peak demand events). A data center campus on interruptible service would have to switch to grid power during curtailment, which typically occurs during cold snaps and heat waves, when the surrounding electric grid is also at peak demand. The application does not specify the service tier the project would seek.

The Interconnection Studies: What’s Known So Far

The applicant confirmed at the April 16, 2026 hearing that interconnection studies with ED4 are underway. Those studies will eventually reveal the cost of grid upgrades required to connect the project to the grid. That cost is the most common reason interconnection applications are withdrawn. According to the Lawrence Berkeley National Laboratory Queued Up 2025 report, of the capacity that submitted interconnection requests between 2000 and 2019, 77% had been withdrawn by the end of 2024. Only 13% reached commercial operation. The median time from application to commercial operation now exceeds four years.

The status of those studies is not the only question. Whether preliminary indications of capacity availability exist, what constraints have been identified, and when the studies are expected to be complete remain unclear.

The Gas Plants: What the Record Reveals and What Remains Undefined

At the October 16, 2025 Planning and Zoning Commission hearing, Commissioner Hartman asked how many megawatts the gas generation would be. Rich responded: “The number’s not set… But we’re certainly planning on hundreds of megawatts of gas in that location, if not more.” Even at a generous 500 megawatts, that is one-sixth of the 3 gigawatt figure in the press release. The application separately claims the project “plans to generate reliable energy beyond its own needs, which can be fed back into the grid.” But Phase 1 has no gas generation, and Phase 2’s gas plant must first serve Phase 1 and Phase 2 buildings before any surplus could emerge. The application does not document where that surplus comes from.

At the April 16, 2026 hearing, Rich stated the project “will probably be utilizing a combination of simple cycle and then combined cycle.” After the hearing, the Water Memo Addendum described natural gas combustion turbines with air cooling paired with spray intercooling to reduce air temperature and increase generator output. The addendum does not explicitly state whether the plants will operate as simple cycle, combined cycle, or some combination. The difference matters: simple-cycle operation requires more natural gas per megawatt of output and places greater demand on the EPNG pipeline, while combined-cycle operation typically uses substantially more water for cooling.

The Addendum cites Project Baccara (18 turbines, 700 MW) and the SRP Coolidge expansion (16 turbines, 820 MW) as benchmarks, but the application does not specify the number, manufacturer, model, or cycle configuration of the turbines proposed for La Osa. Conceptual site plan drawings show turbine-generator units across two plants, but the drawings are explicitly conceptual, not engineering specifications.

Modern gas turbines come in a wide range of sizes, from around 40 megawatts per unit to several hundred megawatts for larger utility-scale machines. In combined-cycle plants, additional steam-generation equipment can increase total plant output beyond the gas turbine’s standalone capacity. Without a stated count or class, the project’s actual footprint, stack height, noise profile, water demand, and transmission requirements cannot be evaluated. All of these scale directly with equipment selection.

A binding stipulation specifying turbine count, cycle configuration, maximum stack height, and total nameplate capacity would establish those parameters before zoning entitlements vest. Deferring them to a later site plan review reduces the leverage the Board has now.

The Water Memo Addendum reports water demand per megawatt of nameplate capacity (0.14 to 0.22 acre-feet per year per megawatt). Megawatts measure plant size; megawatt-hours (MWh) measure actual generation, which depends on how many hours the plant runs. A plant running 90% of the year burns three times the gas and uses far more water than one running 30%. Because the Addendum gives no expected capacity factor or operating hours, pipeline capacity, grid backup, and equipment selection cannot be evaluated. Article 3 examines the water implications.

The Water Memo Addendum is a technical analysis submitted with the application, not a condition of approval.

Battery Energy Storage (BESS): Specifications and Safety

Battery energy storage (BESS) is mentioned in the project description but not specified in the application: no count, size, chemistry, setbacks, or phase placement is disclosed. Large-scale BESS installations are governed by NFPA 855, with fire and explosion safety requirements that scale with system size. The standard has been updated to address gaps revealed by incidents like the April 2019 explosion at a 2 MW APS battery facility in Surprise, where a thermal runaway event injured eight firefighters and a police officer. Fire response capacity for large-scale BESS installations has since become a focus in jurisdictions reviewing data center projects.

Bring Your Own Power: Does It Apply?

“Bring your own power,” or BYOP, is becoming a common framing in Arizona data center approvals. The idea is that if a project generates its own electricity on-site, the surrounding utility’s existing customers will not have to absorb the cost of the grid upgrades needed to serve it. In the recent Project Baccara approvals in Maricopa County, on-site gas generation was cited by the Arizona Corporation Commission as the reason ratepayers would not bear the cost of grid upgrades needed to power the facility.

That framing does not apply to Phase 1 of La Osa. Phase 1 has no on-site generation. It depends entirely on grid interconnection through ED4.

At the April 16, 2026 hearing, Rich described the project as “bringing their own power to serve and to be the source of the generation for the project.” The same hearing record confirms an interconnection process with APS and ED4, a need for additional pipelines as the project grows, and 500kV substations in the site plans. The full project may eventually fit the BYOP description. Phase 1, as currently scoped, does not.

Even in later phases, when on-site generation is built, the project would not fully separate from the grid. At the April 15, 2026 Pinal County Board of Supervisors work session on data center development, APS Director of Data Center Strategy Patrick Bogle told the Board that “behind the meter doesn’t provide the level of reliability that a data center would expect,” and that data centers using on-site generation typically have to build out significantly more capacity to account for outages and maintenance. This means even projects with on-site generation typically rely on grid interconnection for backup, voltage support, and reserve margin. If any of the project’s gas turbines trip offline, which is a routine occurrence in gas plant operations, the campus would draw from the surrounding grid to maintain its computing operations. The project’s reliability and reserve requirements continue to depend on existing grid infrastructure even after on-site generation comes online, not only during Phase 1.

Equipment Shortages: The Hidden Bottleneck

Even if interconnection and permitting were resolved, a separate challenge remains. Bloomberg reported in April 2026 that nearly half of announced U.S. data center capacity planned for 2026 may face delays or cancellation because transformers, switchgear, and batteries are in critically short supply. Tom’s Hardware, summarizing Sightline Climate data cited by Bloomberg, reports that only about one-third of capacity planned for 2026 is actually under active construction. According to APS Chief Operating Officer Jacob Tetlow in AZ Big Media reporting, once equipment arrives it takes about two years to build the plant. Industry-wide lead times for the equipment itself are shown below.

Equipment Type	Reported Lead Time	Source
Large power transformers	~128 weeks (~2.5 years)	POWER Magazine, Jan. 2026
Generator step-up units	~144 weeks (~2.8 years)	POWER Magazine, Jan. 2026
Large gas turbines (GE Vernova, Siemens, Mitsubishi)	6-7 years depending on manufacturer and model	CFC Solutions, 2025

Transformers, switchgear, and batteries are a small share of total construction cost, but without them nothing comes online. A campus worth billions can sit complete and dark, waiting on a transformer order placed years earlier. These lead times exist independent of zoning. A rezoning approved in May 2026 does not shorten them.

Approving Before the Answers Exist

It is also, precisely, the county’s dilemma: the applicant is asking for a rezoning in order to unlock the process that would answer the questions the county needs answered before granting a rezoning.

This kind of early rezoning is normal. Utilities and financiers usually wait until zoning is approved before committing resources to detailed studies. What is distinctive about this rezoning is that the county is being asked to make a zoning decision before basic feasibility has been established. No utility has committed to serve the project, preliminary indications of capacity availability are not on the record, and the public record does not yet explain how the project’s own numbers fit together. A yes vote transfers a measure of that risk onto the county’s land-use future, because the rezoning, once granted, cannot easily be undone regardless of whether the project proceeds. The risk is not purely the developer’s: a rezoning of this scale commits regional grid planning resources, affects neighboring land values, and shapes Pinal County’s industrial profile based on a project whose viability is not yet established.

Before the May 27 Vote: What Would Strengthen the Record

• Grid capacity for Phase 1 and full buildout: Available capacity on the WAPA 115kV and APS 230kV lines, preliminary service availability indications from both utilities, and an explanation of how the grid would serve any load between the addendum’s 2,000 MW generation assumption and the press release’s 3 GW figure.
• Interconnection study substance: Preliminary indications of capacity availability, identified constraints, and expected completion timeline for the interconnection studies with APS and ED4.
• Utility commitment status: Status of utility commitments to serve the project, including the conditions that would need to be met.
• Phase 1 ratepayer protections: A clear statement of what mechanism will prevent Phase 1 grid upgrade costs from being absorbed by existing ratepayers.
• 500kV substations and surplus power claim: The intended purpose of the on-site 500kV substations, any preliminary information about how the off-site bulk transmission connection would be established, and a generation-versus-consumption analysis supporting any claim that the project would feed energy back to the grid.
• Gas turbine and cooling specifications, with binding stipulation: Disclosure of the manufacturer, model, and rated output, and a binding PAD stipulation specifying the cycle configuration (simple, combined, or combination), unit count, and cooling system, enforceable against current and future owners.
• BESS specifications, with binding stipulation: Disclosure of the number, capacity (MW/MWh), and chemistry of BESS installations; setback distances from property lines, fuel sources, and occupied structures; documented fire response coordination with the Avra Valley Fire District; and a binding PAD stipulation specifying which edition of NFPA 855 will govern installation.
• Arizona Line Siting Committee jurisdiction: Confirmation of whether any individual generating unit will have a nameplate rating of 100 megawatts or more, which could trigger the Committee’s jurisdiction under A.R.S. § 40-360, and the projected timeline for any required Certificate of Environmental Compatibility process.
• Realistic gas plant timeline: A timeline to Phase 1 operation that reflects current transformer, switchgear, and turbine lead times.
• Gas pipeline capacity and Transwestern access: Any preliminary capacity indication from Kinder Morgan on whether the EPNG system can support the gas volumes this project would require; whether the project has a subscribed allocation on the Transwestern Desert Southwest expansion; and what lateral infrastructure would be required to connect the site, and how its cost would be allocated.
• Firm versus interruptible gas service and curtailment impact: Whether the gas supply would be contracted as firm or interruptible, the protocol for switching to grid power during curtailment, and an assessment of what happens when the campus draws from the grid during summer peak demand.
• Infrastructure cost commitment: A binding and recorded commitment specifying which infrastructure costs the applicant will cover, enforceable against current and future owners.

Why This Matters

Pinal County is reviewing multiple large-scale industrial rezonings. Each evaluated in isolation may appear to operate within existing frameworks, but the combined effect on the grid, gas system, and queue may exceed what any individual review reveals. Project cancellations in the data center industry more than quadrupled to 25 in 2025, up from six in 2024, representing at least 4.7 gigawatts of canceled electricity demand. A rezoning approved on the assumption that a project will be built commits the county to that land-use designation whether or not the project materializes. According to Zero Emission Grid, when projects drop out, remaining proposals in the same queue must be re-analyzed, and smaller legitimate projects can face years of additional delay. The zoning stage is one of the few points where these cumulative impacts can be considered comprehensively.

Separately, a project at this scale reshapes county infrastructure even if every commitment is met. A campus supporting up to 3 gigawatts of capacity would consume infrastructure capacity at a scale that affects Pinal County’s grid, gas system, and ratepayer base. The pipeline laterals, transmission upgrades, generation procurement, and substation construction required for a project of this scale have community impacts (right-of-way acquisition, construction traffic, ongoing operational footprint, water and fuel logistics) that fall locally. Approving a rezoning of this scale is a decision about the county’s infrastructure trajectory.

The Board votes on May 27. The question is whether enough is on the record to support a rezoning.

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The Pinal County Board of Supervisors public hearing on this case is scheduled for May 27, 2026 at 9:30 a.m., 135 N. Pinal Street, Florence. Agenda packet.

Article 3 examines the water supply questions for a basin Arizona officially closed to new residential subdivisions in 2021: how much water the project would actually use, what Microsoft’s own campus at one-twentieth the scale demonstrates about cooling claims, and whether any water commitments are legally enforceable.

Disclosure
This article is a personal analysis of publicly available information. Figures and interpretations should be independently verified before official use. This article is not financial, technical, or legal advice.

About the Author
Eirini Pajak is a licensed real estate agent and Pinal County resident. She covers local land use and development decisions through her Pinal Unlocked page on Facebook and runs the Pinal Code Watchers community group. Her dog Peso joins her on county rounds.