jain.com — data centers, connectivity and security, analyzed daily

Category: Power Infrastructure

  • Port Washington’s $1.3B–$1.7B Line Reset Shows Data Centers Can Outrun Their Wires

    Port Washington’s $1.3B–$1.7B Line Reset Shows Data Centers Can Outrun Their Wires

    TL;DR · 30-second read

    The Short Version

    A huge data center campus is being built in Port Washington, Wisconsin. To plug it into the electric grid, it needs new high-voltage power lines and substations costing $1.3 billion to $1.7 billion.

    Wisconsin’s utility regulators just sent that power-line plan back to square one. The company behind it changed its paperwork so often, filing or refiling 564 documents, that officials and the public could not keep up.

    The takeaway: a building can go up faster than the wires that power it.

    Wisconsin’s Public Service Commission (PSC) voted unanimously on Thursday to revoke its “completeness” determination for American Transmission Co.’s application to build the Ozaukee County Distribution project, Wisconsin Public Radio reported. The project is a package of new substations, new high-voltage transmission lines and upgrades to existing infrastructure. ATC told regulators it is needed to serve the hyperscale data center campus under construction in Port Washington. A revised application filed in July put the cost at $1.3 billion to $1.7 billion, and the work would have spanned six counties.

    The vote closes the current case and eliminates the December 2026 deadline for regulators to rule. ATC must now file a new application in a new proceeding. The commission did not deny the project. But the reset undercuts ATC’s plan to begin construction in December and finish by the end of 2027.

    Executive Summary

    The PSC withdrew its finding that ATC’s application was complete enough to review. Commission chair Summer Strand said ATC filed or refiled 564 application documents after the December 2025 completeness determination. She called the result a “moving-target application” that left staff unable to prepare evidence and kept intervening parties and the public from participating meaningfully. ATC and a ratepayer watchdog both said they could not recall the commission taking this step in recent decades, if ever.

    The decision matters beyond the six counties the line would cross. It separates two things developers often treat as one schedule: building a data center and energizing it. The Port Washington campus is under construction. The $1.3 billion to $1.7 billion of grid work that ATC says the campus needs is now back at the start of state review, with no ruling deadline in place.

    Vantage Data Centers, one of the campus developers, said it respects the commission’s role but is disappointed. ATC said it is “considering its options.” Neither company has said when a new application will be filed or how the reset affects the campus’s power-on dates.

    The Campus Is Rising; Its Power Line Just Went Back to Start

    The Port Washington case shows a data center moving faster than the infrastructure it depends on. ATC stated in PSC filings that the Ozaukee County Distribution project is needed to provide electric service to a data center that is already under construction. Under ATC’s plan, regulators would rule by December 2026, construction would begin in December, and the buildout would be complete by the end of 2027. Thursday’s vote removed the first step of that sequence, and the others depend on it. A new application means a new proceeding, a fresh completeness review, and a new statutory clock that starts only once regulators again find the filing complete.

    Chair Strand was direct about the cost of that reset: “I recognize the impacts this decision will have on construction timelines and in-service dates for the project.” In-service date is utility shorthand for the day a line is energized and able to carry power. For a hyperscale campus, the kind of facility being built to meet cloud and AI computing demand, that date matters more than any other. Until it arrives, a finished data hall cannot run the servers it was built for.

    The mechanism is two approval tracks moving at different speeds. The building advances on local approvals and private capital. The wires require a state certificate, reviewed in a contested proceeding in which staff, intervenors and the public all have a role. The size of the dependency is set by the $1.3 billion to $1.7 billion estimate: substations, new high-voltage lines and upgrades across Ozaukee, Washington, Sheboygan, Calumet, Fond du Lac and Manitowoc counties. When the grid track slips, the delay falls on the developers, on ATC’s capital plan, and on whichever tenants eventually expect to occupy the campus.

    What 564 Filings Did to a Legal Clock

    In Wisconsin, a major transmission project needs a certificate of public convenience and necessity (CPCN), the state’s permission to build a large utility facility. A completeness determination is the gate into that process. It confirms the application contains what regulators need, and it starts the deadline for a decision. Commissioner Marcus Hawkins described the logic: “We have strict timelines that are feasible only when we have a complete application.” If the application keeps changing after that gate, the deadline stays fixed while the thing being reviewed does not.

    That was the commission’s core finding. According to Strand, ATC filed or refiled 564 documents after being found complete in December 2025. The commission’s administrative law judge had raised concerns last month about missing and changing information. All three commissioners criticized the volume of changes. The reasoning is procedural, not a verdict on whether the line is needed. Staff cannot build an evidentiary record, and parties cannot respond, when the proposal keeps moving.

    ATC’s counterargument deserves a fair hearing. Its attorneys wrote that “in its entire history, the Commission has never revoked a determination that a CPCN application is complete,” and argued against doing so here. Large grid projects serving new, very large loads can change as the load itself is refined, and a restart is a costly remedy. The commission weighed that against the integrity of the review and chose reviewability. Both positions protect something real. The open question is which of them ATC’s revisions were actually driven by.

    A Precedent That Will Shape the Next Filing

    A first-ever revocation signals a lot to every utility preparing a large application in Wisconsin. The practical lesson for transmission owners and data center developers is to settle project scope before filing, not during review, because a regulator has now shown it will reset the clock rather than review a shifting target. That raises the value of early coordination between the developer’s load plans and the utility’s design. It also raises the cost of filing early to secure a place in the schedule.

    The decision also landed amid visible public opposition. Residents and anti-data center activists pushed back on the project, and comedian Charlie Berens submitted comments to the PSC arguing it was “no longer clear to the public or public officials what their actual plans are.” Opponents framed the issue as transparency. The commissioners framed it as process integrity, grounding their vote in the volume of changes rather than in objections to the data center. The outcome addresses the transparency concern procedurally, by requiring a stable application the public can review. It says nothing yet about whether the project should ultimately be built.

    For Vantage, the statement that it will pursue “responsible development” of the needed transmission suggests it expects to see the project through. How quickly that can happen now depends on how fast ATC can refile a fixed application and how long a restarted proceeding takes.

    Background

    American Transmission Co. is a transmission-only utility that builds and operates high-voltage power lines across much of Wisconsin. Major new lines require a certificate from the Public Service Commission of Wisconsin, the three-member state body that regulates utilities. The commission reviews applications in formal proceedings in which staff, intervening parties and the public can weigh in, under deadlines that begin once an application is found complete.

    Port Washington, in Ozaukee County north of Milwaukee, is the site of a hyperscale data center campus. Vantage Data Centers is one of its developers. Campuses of this scale need far more electricity than local distribution networks were built to deliver. That is why ATC proposed the Ozaukee County Distribution project, which the PSC found complete in December 2025 before the application’s many subsequent revisions led to Thursday’s revocation.

    Sources

    Source: PSC deals major blow to transmission project supporting Port Washington data center (Wisconsin Public Radio). Report on the Wisconsin PSC’s vote to revoke the completeness determination for ATC’s $1.3 billion to $1.7 billion Ozaukee County Distribution project.

  • Texas’s 474 GW Pause Shows Why AI Data Centers Can’t Count on Speed-to-Power

    Texas’s 474 GW Pause Shows Why AI Data Centers Can’t Count on Speed-to-Power

    TL;DR · 30-second read

    The Short Version

    Companies want to plug so many new data centers into the Texas power grid that their combined requests add up to several times more electricity than the whole state has ever used at one moment. Data centers are the giant computer warehouses that run artificial intelligence.

    The governor has ordered a check of every data center waiting in line. The organization that runs the state’s grid has put its review on hold while that happens.

    Texas sold itself as the fastest place to get power. For now, it is a waiting line.

    Texas Gov. Greg Abbott has called for an audit of all data centers in the Electric Reliability Council of Texas (ERCOT) interconnection queue, the list of projects waiting for permission and studies to connect to the state’s main power grid. Utility Dive reported on August 5, 2026 that the audit led ERCOT to delay its Batch Zero review process, and that the queue now holds an estimated 474 gigawatts (GW) of interconnection requests.

    Executive Summary

    The state that built its data center pitch on fast access to power has stopped processing the largest group of new requests it has received. The governor’s audit covers every data center in ERCOT’s queue, and ERCOT’s Batch Zero review, the process that would move those large loads toward connection, has been pushed back while the audit proceeds.

    The figure that frames the decision is 474 GW. That is far more than ERCOT has ever served at peak demand, which means the queue cannot describe what will actually be built. It describes what developers hope to build, often with overlapping requests for the same eventual capacity. An audit is the state’s way of forcing that list to reflect reality before engineers spend time studying it.

    For companies planning AI campuses, the practical consequence is timing. A Texas site that looked like a fast route to energized capacity now sits behind an audit whose outcome will determine who moves forward, and in what order.

    A Queue Larger Than the Grid It Wants to Join

    An interconnection request is an application to connect a large new user of electricity, or a new power plant, to the transmission grid. Filing one is relatively inexpensive compared with building the project, so developers often file early and in several places at once, keeping options open on land, tenants and financing. The result is a queue that measures ambition rather than construction.

    At an estimated 474 GW, ERCOT’s queue is several times the most electricity the Texas grid has ever delivered at a single moment. No grid could add that much load on any planning horizon that matters to a data center developer, so most of those requests will not be built as filed. Some are duplicates of the same project at different sites. Some are placeholders for customers who have not signed. Some are real and ready. From the grid operator’s side, those categories look identical until someone checks.

    That is the problem an audit addresses. Studying every request at face value would tie up transmission planners on projects that will never exist, and it would distort the models that decide what new lines and substations Texas needs.

    Why Speed-to-Power Has Become a Waiting Line

    Speed-to-power, meaning how quickly a site can actually receive electricity from the grid, has become the deciding factor in where AI data centers go. Chips, buildings and cooling can be bought on predictable schedules. Grid capacity cannot. Texas won a large share of recent projects partly because its market structure and its largely self-contained grid were seen as moving faster than regulated utility territories elsewhere.

    Batch Zero was ERCOT’s first grouped review of large-load requests. A batch process is efficient because it studies many projects together, but that design also means a delay to the batch is a delay for every project inside it. When the governor’s audit prompted ERCOT to hold the review, each developer in that group lost its place on the calendar, regardless of how far advanced its own project was.

    The people who feel that first are developers holding land, equipment orders and tenant negotiations timed to a Texas energization date; the AI companies and cloud providers who planned to lease that capacity; and the lenders whose construction financing assumes power arrives on schedule. None of them can hedge a grid review. A site that is otherwise ready produces no revenue until it is connected.

    What an Audit Can and Cannot Fix

    An audit can shrink the queue to projects with real backing, which would make the eventual studies faster and more accurate. Done well, it rewards developers who have secured land, financing and customers, and it clears space that speculative requests were occupying. That would be a better outcome for serious projects than the status quo, even if it costs them time now.

    An audit cannot produce generation or transmission. Even a heavily trimmed queue may still exceed what the grid can add quickly, so the underlying constraint remains physical. It also carries execution risk: if the criteria are unclear or change during the process, credible projects could be delayed alongside speculative ones, and developers may respond by pursuing on-site generation or by filing in other markets instead.

    A Test Case Beyond Texas

    Grid operators across the United States face the same pattern: large-load requests arriving faster than they can be studied, with no reliable way to tell firm demand from optionality. Texas is the first to make the screening step this visible, with a state-level audit sitting ahead of the grid operator’s review.

    How it goes will be watched closely. If the audit produces a credible, smaller queue and Batch Zero resumes on a clear schedule, other regions may copy the approach. If it drags on, the lesson for AI infrastructure planners will be that fast-power markets can slow abruptly, and that grid access needs to be treated as a risk on every site plan, not a given.

    Background

    ERCOT manages the grid that serves most of Texas and operates under the oversight of the Public Utility Commission of Texas. Because its network is largely isolated from the rest of the country’s grids, ERCOT has limited ability to import power and must plan new generation and transmission largely within the state.

    Over the past several years Texas attracted a large share of new data center development, including AI-focused campuses, on the strength of available land, a competitive power market and a reputation for connecting large users quickly. The state legislature responded in 2025 with Senate Bill 6, which set new rules for large electricity users, including disclosure of duplicate interconnection requests and provisions for curtailing large loads during grid emergencies. ERCOT’s Batch Zero process was designed to handle the resulting wave of large-load requests in a coordinated group.

    Sources

    Source: Facing an estimated 474 GW of interconnection requests, Texas hits pause on data centers (Utility Dive), on Gov. Greg Abbott’s audit of data centers in ERCOT’s interconnection queue and the resulting delay to Batch Zero.

  • Texas Audit’s Up-to-$15B Hit Shows AI Racks Make Grid Delay a Financing Risk

    Texas Audit’s Up-to-$15B Hit Shows AI Racks Make Grid Delay a Financing Risk

    TL;DR · 30-second read

    The Short Version

    On August 3, Texas Governor Greg Abbott paused new data center connections to the state’s main power grid while officials check every project waiting in line.

    Research firm BloombergNEF says the pause could hold back data centers that want more than half as much electricity as Texas has ever used at its busiest moment.

    Artificial intelligence drives the expensive part. Buildings filled with artificial intelligence chips earn roughly ten times the rent of ordinary computer warehouses. That means even a few months of waiting could cost projects up to about $15 billion in lost income.

    Texas Gov. Greg Abbott’s August 3 order pausing all new data center connections to the Electric Reliability Council of Texas (ERCOT) grid until a comprehensive audit is complete could delay 49.8 GW of data center demand. That is nearly 20% of the 253-GW U.S. data center development pipeline. POWER Magazine reported the figure from an August 5 BloombergNEF (BNEF) report, which also estimates that a three-month slip in near-term Texas capacity additions could cost projects just over $8 billion by the first quarter of 2027 if 60% of the delayed capacity is AI-related, and roughly $15 billion if all of it is.

    Abbott directed the Public Utility Commission of Texas (PUCT) and ERCOT to verify and audit every data center project in a large-load interconnection queue of roughly 474 GW before any more advance. Within hours, ERCOT issued Market Notice M-A080326-01, which suspended the first deliverable of its new Batch Zero interconnection process. That deliverable had been due August 7.

    Executive Summary

    The governor presents the audit as a reliability measure. ERCOT’s queue of pending large-load requests is more than five times the grid’s 91.3-GW peak demand, and some data centers failed to comply with a state survey of water and power use. BNEF’s report reads the timing differently. It notes that Abbott faces reelection in November and says the pause is likely meant to take the data center issue off the table until after the vote.

    The more durable finding is economic. BNEF’s cost range depends almost entirely on how much of the delayed capacity is AI compute. The firm estimates that AI capacity earns about $1.76 billion per gigawatt per month, while a colocation-powered cloud shell in Dallas earns up to $175 million. As a result, a regulatory pause of a few months is no longer a scheduling inconvenience for AI campuses. It is a revenue and financing event. BNEF also warns that the audit could run into the 2027 legislative session, which would give lawmakers a chance to rewrite the rules that govern how Texas connects large loads.

    Why AI Load Sets the Price of a Grid Delay

    BNEF’s scenario is deliberately narrow. It takes the ERCOT data center capacity forecast for the third quarter of 2026 through the first quarter of 2027, assumes it all slips to the second quarter of 2027, and measures the rental revenue that disappears in the meantime. The result swings widely. At a 10% AI mix, cumulative revenue at risk is about $2 billion. At a 60% AI supermajority, it is just over $8 billion. At 100% AI compute, it reaches roughly $15 billion. The megawatts are the same in every case. Only the tenant changes.

    The mechanism lies in the two rental benchmarks behind the model. Citing CBRE data, BNEF says a colocation-powered shell for traditional cloud racks in Dallas can earn up to $175 million per gigawatt per month. Using GPU rental prices from Silicon Data, it estimates AI compute capacity at around $1.76 billion per gigawatt per month, roughly ten times as much. (A GPU, or graphics processing unit, is the chip that trains and runs AI models.) So each month an AI hall waits for power forgoes about ten times the revenue of a conventional cloud hall of the same size.

    This is what turns interconnection timing into a financing question. AI campuses are usually underwritten on the assumption that expensive compute starts earning soon after the building is energized. A pause set by a state audit rather than by construction progress is hard for a developer to mitigate and hard for a lender to model. The people most exposed are those financing AI-heavy Texas projects near energization: developers, their GPU-cloud tenants, and their lenders. Conventional colocation projects face the same delay but carry a far smaller revenue gap.

    The 49.8 GW Headline Versus the Capacity Actually Being Built

    The 49.8-GW figure measures the demand whose progress could stall. It does not measure what would have been switched on this year. BNEF forecasts only 1.2 GW of ERCOT data center additions between the second quarter of 2026 and the first quarter of 2027. Its tracked Texas pipeline of 50 GW breaks down into 36 GW at an early stage, 9 GW committed with land, power and approvals, and 5 GW under construction. By 2030, BNEF expects Texas data center capacity in ERCOT to reach 17.2 GW, far below the roughly 204 GW eligible for Batch Zero study.

    This gap cuts both ways in the political argument. It supports Abbott’s premise that a queue five times peak demand needs scrutiny: BNEF itself calls it speculative and says it lacks project transparency. It also shows that the near-term dollar exposure sits in a small, real slice of capacity, the projects close enough to completion to lose revenue in 2026 and early 2027. A verification process that is fast for committed projects and slow for speculative ones would target the problem the governor describes. A blanket pause does not make that distinction.

    Batch Zero Stalls, and the Calendar Becomes the Risk

    Batch Zero, approved in June, lets ERCOT study large loads in groups rather than one at a time, so that grid capacity is allocated more efficiently and connections move faster. The governor’s order halted it at its first step. ERCOT said it will not tell transmission and distribution providers how each large load is classified by August 7. It also plans to seek a good-cause exception from its Planning Guide timelines before the PUCT’s August 20 open meeting.

    The audit also overlaps with rules already underway. Senate Bill 6 already requires site-control documentation, $50,000 per MW in financial security, disclosure of duplicate interconnection requests at other sites, and reporting of on-site backup generation. The PUCT is still writing these requirements into 16 TAC § 25.194, with adoption expected in September and a statutory deadline of December 31, 2026. BNEF warns that an onerous audit could extend into the 2027 legislative session, potentially as late as April, and open the SB 6 framework to further restrictions.

    For projects already in the queue, there is no quick fix. BNEF says a delay until April or May 2027 is too short for data centers to buy and build behind-the-meter generation, meaning on-site power plants, as a hedge. The 294 GW of requests that were not eligible for Batch Zero face a different outcome. If new legislation arrives, those later projects may lean toward on-site generation and storage from the start.

    A Reliability Case, a Political Read, and a Pattern Across States

    Both explanations for the audit deserve scrutiny. The governor’s reliability case rests on documented facts: a queue five times record peak and a recorded failure by some data centers to answer the PUC’s water and power survey. Still, BNEF notes that most of the information the audit might gather is already required under SB 6 or other rules, which raises the question of what the audit adds. BNEF’s electoral reading is an inference from timing and context: a 15-hour public hearing, and the lieutenant governor’s call to pause $33 billion in planned transmission spending toward western Texas. It is plausible, but it is interpretation, not documentation.

    Texas is also not acting alone. New York’s Executive Order 62, signed July 14, imposed a statewide moratorium on new hyperscale data centers of 50 MW or more. Illinois paused Data Center Investment Program agreements from July 1. Florida’s SB 484, effective July 1, bars utilities from shifting large-load costs to residential and small-business customers. BNEF concludes that community opposition is becoming a material constraint even in markets that have courted the industry. Abbott himself had recently called Texas “the epicenter of AI development.” Unlike New York’s measure, the Texas action is a verification precondition rather than a moratorium. Some of the industry has welcomed it: QTS Data Centers’ co-CEOs endorsed the governor’s leadership and called for clear guardrails.

    Background

    Texas has been one of the fastest-growing U.S. data center markets. It offers abundant land, a competitive power market, and a state government that has actively courted the industry, including after Google’s $40 billion investment announcement. That growth has flooded ERCOT’s interconnection queue, the waiting list of large electricity users seeking grid connections, with requests far exceeding what the grid serves today. In 2025 the legislature passed Senate Bill 6 to impose financial and disclosure requirements on large loads, and ERCOT designed Batch Zero to process those requests in groups.

    In 2026, pushback has grown across several states. New York imposed a moratorium on large new data centers, Illinois paused its data center incentive agreements, and Florida restricted how utilities can allocate data center costs to other customers. In Texas, a 15-hour public hearing and the lieutenant governor’s call to pause $33 billion in transmission spending came shortly before the governor’s audit order.

    Sources

    Source: Texas Audit Could Delay 49.8 GW of Data Center Load, Cost Projects Up to $15 Billion, BNEF Warns (POWER Magazine), coverage of BloombergNEF’s August 5, 2026 report on the ERCOT data center audit.

  • Texas’s 260 MW Wind Ruling Shows AI Co-Location Is a Grid Deal, Not an Exit

    Texas’s 260 MW Wind Ruling Shows AI Co-Location Is a Grid Deal, Not an Exit

    TL;DR · 30-second read

    The Short Version

    Texas regulators approved a giant artificial intelligence computing center, essentially a warehouse full of computers, built right beside a wind farm. The catch: whenever the state’s power grid is in trouble, the center must shut off completely within 30 minutes, even if that means flipping its main breakers.

    The center uses roughly as much electricity as the wind farm produces, about what a small city draws. Its builders called the rule excessive. Regulators disagreed, because in an emergency the grid needs that wind power. The message to everyone else: building next to a power plant does not free you from the grid’s rules.

    The Public Utility Commission of Texas has approved a net metering arrangement for a 260 MW AI data center co-located with a wind farm of 265.5 MW, Utility Dive reported. Net metering here means the data center draws power directly from the adjacent generator, with only the difference between the two settled against the grid. The project is developed by Crusoe and will be operated by Ensign, the large-load customer. It is the second data center planned at the site, bringing combined load to about 525 MW.

    In an order dated July 23, 2026, the commission required the new facility to be able to curtail its full load within 30 minutes during grid emergencies, by physical breaker disconnection if necessary. It also barred the project from paid demand response programs tied to the arrangement. The commission rejected the developer’s argument that the second facility should be exempt from the curtailment conditions applied to the first.

    Executive Summary

    Texas has approved one of the first behind-the-meter AI data centers under SB 6, the 2025 state law that set new rules for large electricity users on the ERCOT grid and gave the grid operator authority to disconnect data centers during emergencies. Behind-the-meter means the load sits on the generator’s side of the grid connection and consumes its output directly. The approval lets the project proceed, but on terms that commissioners largely adopted from ERCOT’s proposed reliability conditions rather than writing a project-specific exception.

    Those terms matter well beyond one site. Because the commission chose a general framework over a bespoke deal, the order is likely to serve as a reference point for other co-located loads in Texas. They include a pending application from Amazon and Vistra for a data center campus beside the Comanche Peak nuclear plant southwest of Fort Worth.

    The practical takeaway for developers is that sitting next to a generator secures a power supply in normal conditions. It does not remove the load from the grid’s emergency claims. In a grid emergency, the wind farm’s output is treated as a grid resource, and the data center must be able to step aside quickly and without payment.

    Why the Commission Counted Both Buildings

    The heart of the dispute is simple arithmetic. The wind farm is rated at 265.5 MW. The first data center at the site accounts for roughly 265 MW, and the new one adds 260 MW, for a combined load of about 525 MW. Crusoe and Ensign argued that the first facility was already subject to curtailment and that the earlier reliability condition on the co-located wind project made further curtailment unnecessary. In their view, forcing the entire site offline was disproportionate.

    The commission saw the mechanism differently. If the first facility were curtailed during an emergency while the second stayed online, the second facility’s 260 MW could absorb nearly all of the wind farm’s 265.5 MW nameplate output on-site. Almost nothing would reach the grid at the moment the grid most needed it. Commissioners, adopting the administrative law judge’s recommendation with revisions from Chairman Thomas Gleeson, concluded that this would undermine the goal of keeping generation available to the grid during emergencies. That reasoning is what turns co-location from a private supply arrangement into a conditional deal with the grid: the load gets the generator’s output in ordinary hours, and the grid gets it back when reliability is at stake.

    This is the substance behind the headline. The order does not treat an adjacent wind farm as a private power plant that exits the data center from ERCOT’s reliability regime. The generator remains, in the commission’s framing, capacity the grid can call on. Any co-located load large enough to consume that capacity must be able to get out of the way.

    The 30-Minute Clock and the Backup-Power Question

    The operating requirements are specific. The data center must be able to shed its full load within 30 minutes, including by physically opening breakers. ERCOT should give 60 minutes’ advance notice when practicable, and the operator may voluntarily commit to a faster 10-minute response. This is more flexibility than traditional industrial loads have been asked to provide, and it reframes the ability to shut down rapidly as a condition of operating behind generation rather than an optional grid service.

    For an AI operator, disconnection means lost compute time unless something else carries the load. Chris Talley, co-founder of GridTracker, wrote after the decision that the order is not a “death blow” to co-location in ERCOT but that “this architecture now essentially requires full backup capacity.” He later clarified that he meant resources able to carry the load off-grid for a meaningful period, not just ride through a brief interruption, and he called this an “untested assumption.” That caveat is worth keeping. The order sets a curtailment obligation; it does not mandate backup generation. Whether operators respond by building on-site capacity, by accepting downtime, or by designing workloads that tolerate interruption is a commercial choice the ruling leaves open.

    What the ruling does settle is that the cost of staying online through an emergency now sits with the developer. For any co-location pitch built on the idea that an adjacent generator guarantees uninterrupted power, that is a material change in the assumptions.

    Emergency Duty Is Not a Paid Service

    The ban on paid demand response programs tied to the arrangement is the order’s quieter economic lever. Demand response programs typically pay large users to reduce consumption when the grid is stressed, and flexible loads can earn meaningful revenue from them. By prohibiting compensation here, the commission drew a line between mandatory emergency curtailment, which is a condition of the co-location arrangement, and voluntary grid services, which can be sold.

    The effect is to remove an offsetting revenue stream from the project’s economics. A developer cannot count the same flexibility twice: once as the price of permission to co-locate and again as a product sold back to the grid. For project finance models that assumed curtailment could be partly monetised, that assumption no longer holds under this framework.

    A Template Under SB 6, With Comanche Peak as the Next Test

    Because commissioners largely adopted ERCOT’s proposed conditions rather than negotiating a one-off exception, the order reads as a template for future behind-the-meter projects in Texas. Utility Dive has reported that Texas faces a large-load interconnection queue of 438 GW, so the rules governing how big loads connect, and how they behave in emergencies, affect a very large pipeline of proposed projects.

    Not every stakeholder agrees the template is sound. The Texas Competitive Power Advocates and natural gas producer BKV filed arguments that the framework could discourage future co-location. PUCT staff contended those parties lacked standing under the governing statute, and the final order did not address their arguments on the merits. Their concern therefore remains an open policy question rather than a resolved one. The next data point will likely be the Amazon and Vistra application at Comanche Peak, a co-location next to nuclear generation rather than wind. Talley said that how ERCOT and the commission treat that arrangement “will be very telling.”

    Background

    Texas runs most of its electricity through ERCOT, a grid largely separate from the rest of the US, and it has become a leading destination for large AI data centers because of available land and generation. That demand has pushed lawmakers and regulators to write rules specifically for very large loads. SB 6, enacted in 2025, set requirements for such loads and gave ERCOT authority to disconnect data centers during grid emergencies.

    Co-location, placing a data center directly beside a power plant, has attracted developers as a way to secure supply faster than a conventional grid connection allows. Regulators, however, have had to decide whether generation consumed on-site should still count toward the grid’s reliability during emergencies. The Crusoe and Ensign case is among the first to answer that question under SB 6.

    Sources

    Source: Texas approves AI data center co-location next to wind farm, with curtailment caveats. Utility Dive on the Public Utility Commission of Texas order approving a 260 MW co-located AI data center with emergency curtailment conditions.

  • A 2% Premium Shows the Inverter Switch for AI-Era Power Hinges on Time, Not Price

    A 2% Premium Shows the Inverter Switch for AI-Era Power Hinges on Time, Not Price

    TL;DR · 30-second read

    The Short Version

    Every solar panel and battery farm needs a box called an inverter, which turns its power into the kind your sockets use. Many are connected to the internet, so a hacker could in theory take control of them.

    China has the factories to make about four in every five of the world’s inverters. Europe plans to stop funding big solar and battery farms that use inverters from countries it considers risky, including China.

    The International Energy Agency found switching adds only about 2% to a large solar farm’s cost. The harder part is time, as factories retool while artificial intelligence data centers need ever more power.

    In a commentary published July 29, 2026, the International Energy Agency (IEA) reported that China accounted for around 80% of global manufacturing capacity for the inverters used in solar and battery installations in 2025, and assessed the cost of moving away from suppliers that governments now classify as security risks. The analysis follows a European Commission decision to restrict EU funding, including through the European Investment Bank and European Investment Fund, for solar, wind and storage projects that use inverters from “high-risk” countries: China, Russia, Iran and North Korea.

    The IEA estimates that buying a utility-scale inverter from a manufacturer headquartered in the EU or another non-high-risk country costs about USD 13/kW more, roughly 75% above Chinese pricing, but adds just under 2% to total project cost. Europe’s inverter factories, at around 95 GW a year, already exceed its roughly 90 GW of annual shipments, though the IEA warns the models built locally may not match the models in demand.

    Executive Summary

    Inverters are the control layer of modern renewable power: the electronics that convert direct current from solar panels, batteries and many wind turbines into grid-ready alternating current, and that manage power flow, monitoring and grid safety. Because most are networked and remotely controllable, governments increasingly treat them as a cybersecurity exposure, with risks ranging from compromised passwords to back doors planted during manufacturing or malicious software updates.

    The policy response is spreading. Beyond the new EU funding restrictions, the US National Defense Authorization Act passed in December 2025 bars its funds from buying inverters from designated Foreign Countries of Concern, including China; Lithuania restricts remote control of inverters and now applies those rules to existing installations; and India requires inverters in a subsidised rooftop scheme to send data only to servers in India.

    The IEA’s central finding is that the price of de-risking is modest at the project level. That matters for anyone financing or buying power from new solar and storage, including the large electricity buyers behind AI data center growth: the binding constraint looks less like cost and more like whether the right inverter models can be produced in time.

    The Premium Is Real, but It Shrinks at Project Scale

    On a per-unit basis, the gap between Chinese and non-Chinese inverters is large. The IEA puts the average global inverter shipment price at around USD 28/kW, with high-power three-phase units near USD 25/kW and microinverters near USD 180/kW. For the systems typically used in utility-scale projects, shipments in key EU markets carried a premium of about USD 13/kW (EUR 12/kW) over Chinese prices, roughly 75% higher. The IEA attributes China’s lower prices to economies of scale, higher automation and intense price competition.

    Measured against the whole project, though, that premium is small. Utility-scale solar in the EU cost around USD 760/kW in 2024, so a USD 13/kW inverter premium works out to just under 2%. Small residential and commercial systems are more exposed: at around USD 1,000/kW installed, the IEA estimates a 3-4% premium for string inverters and about 20% for hybrid inverters and microinverters. In other words, the cost burden of the security push falls most heavily on rooftop segments the EU rules are not expected to cover, and least heavily on the utility-scale projects they are.

    Why the Constraint for AI-Era Power Is Timing, Not Price

    The headline aggregate looks comfortable: Europe could make around 95 GW of inverters a year in 2025, against total shipments of about 90 GW. Inverters are the one step of Europe’s solar supply chain where capacity exceeds demand, compared with just 33 GW of module capacity, 10 GW of cells and 1.5 GW of wafers against roughly 70 GW of module demand. Even adding around 17 GW of stationary battery deployment, which needs bidirectional power conversion, the IEA judges domestic capacity to be in excess of demand.

    The catch is fit. The IEA expects a likely mismatch between the models Europe produces and the models its market wants, noting that string and microinverters are often imported from China, and that retooling production lines to close those gaps is possible but would take some time. It says the mismatch could lead to project delays and cost increases. For utility-scale solar and storage developers, that is the operational risk: a sub-2% cost line is easy to absorb in a financial model, but a procurement delay on a power-conversion package can push back energisation dates.

    That sequencing matters to the buyers of that power. Data center operators expanding capacity for AI workloads are among the largest contracted buyers of new utility-scale solar and battery output, and utility-scale projects are expected to make up around half of global capacity additions over the coming decade in the IEA’s exploratory scenario projections. Where those projects rely on EU financing, the practical question for a data center’s power team is not whether compliant inverters cost more, but whether suppliers can deliver the specific models on schedule. The IEA points to partial relief: redistributing European output between exports and domestic demand, and higher imports from non-high-risk producers, notably in Southeast Asia.

    Security Rules Are Landing Where Controls Are Already Strongest

    The IEA describes how an attacker who gains access to an inverter could control and alter the equipment connected to it, with consequences ranging from localised disruption to lengthy blackouts. The threat can come through weak online connections and passwords, through back doors built in at the factory, or through malicious software updates from the manufacturer.

    The anticipated scope of the EU rules raises a fair question about fit between risk and remedy. Based on currently available information, the restrictions are widely expected to apply directly only to EU-funded utility-scale projects, which the IEA notes are professionally operated under stringent cybersecurity protocols. Most smaller rooftop installations in homes and businesses are not expected to be covered. Existing EU instruments, including the NIS2 directive, the Cyber Resilience Act and the Network Code on Cybersecurity, already address equipment security; how the new funding rule adds to them will depend on details the Commission has yet to publish.

    A Trade Dispute Layered on an Engineering Problem

    China is the only major inverter supplier among the four countries the EU designates as high-risk, and on May 8, 2026, China’s Ministry of Commerce criticised the restrictions, warning they could damage trade relations, supply chain security and Europe’s energy transition. Other markets face sharper exposure than Europe: Korean inverter manufacturers have raised concerns about the country’s more than 90% dependence on Chinese suppliers.

    The policy tools differ. The US approach restricts federally funded procurement, the EU’s restricts funding eligibility, Lithuania’s governs remote control and requires retrofits of some existing installations, and India’s targets where data is stored. For developers and equipment buyers operating across several markets, the likely outcome is not one standard but a patchwork of compliance regimes, each with its own implications for vendor selection and project timelines.

    Background

    Solar power has become one of the largest sources of new electricity worldwide: the IEA counts almost 3 TW of installed solar capacity supplying nearly 9% of global electricity, none of which could function without inverters. Battery storage and many modern wind turbines depend on the same power-conversion electronics, and inverters increasingly coordinate with connected loads such as electric car chargers, heat pumps and air conditioners.

    Chinese manufacturers have come to dominate inverter production through scale, automation and price competition, offering what the IEA describes as typically the lowest-cost option in most major markets with high performance and reliability. Europe is the second-largest producer, with about 8% of global capacity, and inverters are the one stage of its solar supply chain where domestic manufacturing exceeds demand.

    Sources

    Source: Inverter supply chains and cybersecurity – Analysis (International Energy Agency), an IEA commentary on inverter supply concentration, new EU sourcing restrictions and the cost of switching suppliers.

  • NV Energy’s 22 GW Queue Shows Why Data Center Power Priority Is Worth Suing Over

    NV Energy’s 22 GW Queue Shows Why Data Center Power Priority Is Worth Suing Over

    TL;DR · 30-second read

    The Short Version

    Nevada’s main electric company, NV Energy, is suing Tract, a company that builds huge campuses for data centers. Data centers are the warehouse-sized buildings full of computers that run websites, apps and artificial intelligence.

    The fight is over who gets electricity first, how much, and who pays for new power plants and lines. Requests for new power, driven largely by data centers, already add up to more than twice what the utility’s whole system uses on its busiest day.

    The utility says households could get stuck with the bill. Tract says it has promised nearly $1 billion toward the utility’s equipment and is paying its fair share.

    NV Energy, Nevada’s primary electric utility, has sued data center developer Tract in Washoe County’s Second Judicial District Court, The Nevada Independent reported on July 28, 2026. The complaint was filed Friday, July 24, and much of it is redacted because it was filed under seal. It alleges that Tract started private arbitration over when and how much power the utility must provide to its Peru Shelf and South Valley projects at the Tahoe Reno Industrial Center, and that this bypasses the Public Utilities Commission of Nevada (PUCN).

    NV Energy says Tract’s demands would shift infrastructure and energy costs onto existing customers. Tract says the complaint “seriously misstates the issues, the facts, and the contracts NV Energy signed.” It also says it has never sought subsidies, that it has committed nearly $1 billion to support NV Energy’s infrastructure, and that those contracts commit the dispute to arbitration.

    Executive Summary

    The suit pits Nevada’s dominant utility against one of the largest landholders in the state’s data center market. It turns on a question every fast-growing power market will eventually face: when a developer’s contract and a utility’s regulated resource plan collide, who decides the order in which new loads get electricity? NV Energy says only the PUCN can. Tract says the parties agreed to arbitrate.

    The backdrop explains the stakes. NV Energy’s latest integrated resource plan says it would need about 22 gigawatts (GW) just to serve existing requests for service, more than twice its current system peak, and it attributes that demand largely to data centers. When the grid is oversubscribed by that margin, a place in the queue has real economic value. Tract is already planning 362 megawatts (MW) of temporary gas and diesel generation because the grid cannot serve its projects right away.

    For ratepayers, the dispute is about who pays for growth. For developers and their financiers, it tests whether a large-load contract signed with a utility can be enforced on its own terms, or whether it stays subordinate to the regulator’s planning process.

    Twice the Peak: Why Queue Position Is Now the Prize

    NV Energy’s most recent integrated resource plan (IRP) says the utility would need roughly 22 GW of capacity just to meet requests for service already on file. That is more than twice the current system’s peak demand, and the utility says data centers are the main driver. A gigawatt is a thousand megawatts, and a single megawatt is a large industrial load on its own. When requests exceed what the grid can deliver by that much, the utility cannot connect everyone at once. The order of service then decides whether a campus opens on schedule, and it matters as much as the price of power.

    That order is exactly what this dispute concerns. According to the complaint, Tract’s arbitration seeks to settle when and how much power NV Energy should provide, how the utility generates and buys that power, and the priority of service among customers in its queue. Tract’s own contingency plan shows what a later place in line costs. NV Energy cannot serve the projects immediately, so Tract has proposed temporary natural gas and diesel plants: 144 MW for South Valley and 218 MW at Peru Ridge. These would be “behind-the-meter,” meaning on-site generation that feeds the campus directly rather than power drawn from the utility’s regulated grid.

    Three groups are affected. Other large customers in the queue are affected because capacity promised to one developer is capacity another does not get on that date. Existing ratepayers are affected if accelerated grid upgrades end up in general rates. Developers and their lenders are affected because a campus’s value depends heavily on when it can be energised. With that much at stake, both sides have escalated. Tract has gone to arbitration, and NV Energy has gone to court to stop the arbitration from deciding matters it says belong to the regulator.

    Contract Forum Versus Regulatory Forum

    NV Energy’s legal theory rests on jurisdiction. Generation, power purchasing and service priority are set through IRPs, which the utility must file with the PUCN and have approved at least every three years. The utility argues that an arbitrator cannot decide those questions outside that framework, especially while the Commission is weighing the same issues. That includes NV Energy’s proposal for a uniform large-load service agreement meant to standardise terms across data center customers. “Defendants cannot now short-circuit that regulatory process,” the filing says.

    Tract’s position rests on contract. It says the agreements NV Energy negotiated commit disputes to arbitration, and that it simply wants the utility “to live up to the commitments it made.” The agreements were executed under Rule 9, which governs how construction costs and responsibility are split between the utility and a new customer, weighing the project’s size, duration and risk. NV Energy says Rule 9 does not address the supply of electricity. The unresolved question is therefore whether the utility made supply or timing commitments in those contracts, and if it did, whether they can be enforced privately. With the agreements sealed, neither side’s reading can yet be checked publicly.

    The implications reach beyond Nevada. If construction-cost agreements can carry enforceable supply priority through arbitration, large-load contracts become a channel that runs parallel to resource planning. If they cannot, developers get less contractual certainty at the moment they are raising capital for multi-hundred-megawatt campuses. Either outcome carries costs for someone.

    Same Principle, Different Math

    Both parties invoke the same principle. “Customers that create new costs should cover new costs, and those costs should not be shifted,” said a person familiar with the matter. Tract says it “has committed to paying our fair share for infrastructure and generation needs” and never asked to be subsidised. The disagreement is not about whether growth should pay for itself. It is about what a fair share amounts to, and what the nearly $1 billion Tract cites actually buys in capacity, timing and priority.

    The growth figures explain why that math is contested now. NV Energy estimates it needs 52 percent more energy statewide than it forecast only two years ago. Data centers account for about 5 percent of its sales today, and the utility projects that share will reach 64 percent by 2046. On that trajectory, cost-allocation rules written now will govern who pays for most of the system’s future expansion. Questions that are traditionally settled in rate cases and resource plans are here being argued in court over the terms of a contract. That is one case, not yet a pattern, but it is a sign of how much weight these contracts now carry. The lawsuit also places the utility’s stated position near local concerns about data center electricity and water use, a shift in public posture for a utility that is simultaneously planning to serve that load.

    Land Is Not Power

    Tract has assembled more than 12,000 acres in Northern Nevada, including 1,060 acres in Lyon County that it says can support 1.6 GW of data center capacity. Land has not been the constraint, and grid access keeps proving to be one. Last year, Switch sued Tract to block certain developments on the same Peru Shelf parcels, arguing they would affect Switch’s ability to connect future projects to utilities. The court ruled in Tract’s favour. Two separate lawsuits over the same ground have now turned on access to power.

    For site selectors, investors and tenants, the practical lesson is that acreage, zoning and even signed construction agreements do not establish an energisation date. On-site gas and diesel generation is becoming part of the plan rather than an emergency fallback. That brings its own permitting, fuel and emissions questions, and it does not settle when the grid will take over.

    Background

    NV Energy is Nevada’s primary electric utility and a subsidiary of Berkshire Hathaway Energy. Like other regulated utilities, it plans new generation and power purchases through integrated resource plans filed with and approved by the PUCN at least every three years. It already has large-load agreements with multiple data centers. In its current plan it is asking regulators to approve a uniform service agreement for large-load customers, consistent with those existing contracts.

    Tract develops master-planned data center parks and has bought more than 12,000 acres across Northern Nevada. In 2024 it acquired 8,600 acres in Storey County between the Tahoe Reno Industrial Center (TRIC) and the Virginia City Highlands, bringing its holdings to 11,000 acres. It later added 1,060 acres in Lyon County just south of TRIC, which it says can support 1.6 GW of capacity. Last year Tract prevailed in a lawsuit brought by Switch, a longtime TRIC operator, over development of Tract’s Peru Shelf parcels.

    Sources

    Source: Nevada’s electric utility is suing a major data center company. Here’s why. (The Nevada Independent), on NV Energy’s lawsuit challenging Tract’s arbitration over power-supply agreements for two Storey County data center projects.

  • Israel Eased Data Center Planning. Its 27GW Grid Queue Shows Where the Bottleneck Moved

    Israel Eased Data Center Planning. Its 27GW Grid Queue Shows Where the Bottleneck Moved

    TL;DR · 30-second read

    The Short Version

    Israel has stopped accepting new requests from large data centers to connect to the power grid for about four and a half months. Data centers are the warehouse-sized buildings full of computers that run cloud services and artificial intelligence.

    The reason: builders have asked for nearly three times as much electricity as the whole country normally uses. Officials want time to separate real projects from ones that may never be built.

    At least one developer has already dropped its plans. How Israel sorts this out will decide who gets power, and when.

    Israel’s Electricity Authority has frozen the processing of new applications to connect data centers of 8 megawatts (MW) or more to the power grid for 140 days, DatacenterDynamics reported on July 28, 2026. The authority described the pause as an “emergency brake” to prevent the system from making connection commitments it may not be able to fulfill. The freeze is expected to run until early December.

    The country’s transmission operator, Israel Independent System Operator (NOGA), received 19 gigawatts (GW) of new data center connection requests within two months, bringing the pending total to roughly 27GW, nearly triple Israel’s average baseline electricity consumption. During the pause, the Electricity Authority, the Ministry of Energy and NOGA will jointly develop a new policy for allocating electricity between data centers and the rest of the economy.

    Executive Summary

    Israel has imposed a national pause on new grid connection processing for data centers of 8MW and above, one of the clearest cases yet of a grid operator stopping the queue rather than working through it. The trigger is scale: roughly 27GW of pending requests against a grid whose average baseline consumption is about a third of that.

    The surge followed the National Cyber Defense Bill, passed by the Knesset in February, which designated data centers as national infrastructure to remove planning and construction constraints. With those hurdles lowered, the grid connection became the constraint that still binds, and it absorbed the full weight of demand, speculative filings included.

    The 140-day review is meant to map the requests, set eligibility criteria and build a mechanism to tell legitimate projects from speculative ones. The outcome will shape which developers can build in Israel, how quickly, and on what terms. VisionWave has already abandoned a hyperscale project, citing the pause.

    Easing Planning Moved the Bottleneck to the Grid

    In February, Israel’s parliament passed the National Cyber Defense Bill. The law classified data centers as national infrastructure specifically to remove planning and construction constraints, with the aim of speeding up an industry the government considers strategic. What followed was a flood of grid applications. NOGA received 19GW of new data center connection requests within two months, and the pending total now stands at roughly 27GW, nearly triple the country’s average baseline consumption. For scale, a gigawatt is roughly the output of a large power station.

    The mechanism is straightforward. A data center project passes through several filters: land, zoning, construction permits, financing, customers and power. Lower the planning filters and it becomes cheaper to put a project into the pipeline, while a place in line for scarce electricity stays just as valuable. The grid connection becomes the one gate that still binds, so it absorbs all of the demand, including requests from projects that may never be built. A planning rule can be rewritten in a single legislative session. New transmission lines and generation take years.

    That is the logic behind the authority’s “emergency brake” framing. A connection offer is a promise to deliver power years from now. Issued against a queue that far exceeds national demand, such promises would either go unkept or crowd out other users. The review’s stated purpose, allocating electricity between data centers and the economy at large, puts that trade-off in plain terms: every megawatt reserved for a server hall is a megawatt not available to homes, factories or transport.

    A 27GW Queue Is a Signal, Not a Forecast

    No grid adds three times its existing load in a few years, and nothing in the announcement suggests Israel expects to. A queue of this size says more about the incentives facing developers than about the power that will eventually be consumed. Developers often file for several sites at once to keep their options open, and an early filer can hold capacity that a better-financed project later needs. The government’s plan to map requests, set eligibility criteria and separate legitimate projects from speculative ones amounts to an acknowledgment that the queue, in its current form, cannot guide grid planning.

    The hard part is that genuine demand is buried inside the inflated number. The pause comes as AI training and inference reshape data center demand worldwide. These workloads concentrate large, steady power draws on single campuses, which is exactly the profile that stresses transmission planning. Last month Crusoe, a developer focused on AI infrastructure, said it would invest around $10bn in Israeli data centers over ten to 15 years through leases. Commitments of that kind compete for the same limited grid capacity as filings with little behind them, and that is the problem the sorting exercise is meant to solve.

    Who Wins and Who Waits

    The 8MW threshold matters. Enterprise server rooms and smaller edge facilities fall below it. Hyperscale and AI campuses sit well above it. The freeze therefore lands on the segment the February law was designed to encourage. For those developers, 140 days carries a real cost. Land options, equipment reservations and tenant negotiations all lose value over time, and a project without a connection date is hard to finance or lease.

    VisionWave has already dropped plans for a hyperscale data center in Israel and cited the pause as a key factor. Other developers may choose to wait rather than leave. Rules built to separate legitimate from speculative projects would favor applicants that can show land, financing and customers. That would benefit mature developers and well-capitalized tenants over applicants holding queue positions on the chance that one becomes valuable.

    The broader lesson is not that Israel is closing to data centers. It is that easing one constraint without adding grid capacity moves the queue somewhere else. Israel’s experience suggests that any market courting AI infrastructure needs a clear, enforceable rule for allocating power alongside its permitting reforms.

    Background

    Israel’s Electricity Authority is the power sector’s regulator and sets the rules for how customers connect to and pay for the grid. NOGA, the Israel Independent System Operator, runs the transmission network and processes connection requests for large loads. Israel’s grid is largely isolated from its neighbors’, so electricity demand has to be met mainly by generation inside the country. That makes a sudden surge in requested load especially hard to accommodate.

    Israel has been positioning itself as a regional data center hub. In February the Knesset passed the National Cyber Defense Bill, which designated data centers as national infrastructure to ease planning and construction. Developers followed: Crusoe announced in June a roughly $10bn lease-based investment plan over ten to 15 years. The grid freeze is the first major check on that expansion.

    Sources

    Source: Israeli Electrical Authority freezes grid processing of new data centers for 140 days (DatacenterDynamics): Israel pauses grid connection processing for data centers of 8MW or more after 27GW of requests.

  • Georgia’s 1,000-Mile AI Grid Build Shows the Cost the Rate Math Misses: Easements

    Georgia’s 1,000-Mile AI Grid Build Shows the Cost the Rate Math Misses: Easements

    TL;DR · 30-second read

    The Short Version

    Georgia’s biggest power company is building more than 1,000 miles of new power lines, longer than the drive from Atlanta to New York City. About 80 percent of the new electricity it plans to add is expected to go to data centers, the giant warehouses of computers that run artificial intelligence.

    The lines must cross private land: more than 330 properties, including nearly 30 homes that will be torn down. The company starts its offers a quarter above a property’s appraised value and says it rarely forces a sale. But the right to run lines across land usually lasts forever, even after the owner sells.

    Fortune reported on July 26, 2026 that Georgia Power is contacting property owners along a 35-mile route through Fayette, Heard, Fulton and Coweta counties for the Ashley Park-Wansley Transmission Project, a new line between its Ashley Park Substation and its plant at Wansley. It is one of five projects that together make up more than 1,000 miles of new transmission in the utility’s plan. That plan spans more than 330 parcels of land and requires nearly 30 residential properties to be leveled.

    Georgia Power says land acquisition and easement negotiations are close to complete, with construction as early as 2027. It opens offers at 125% of appraised value and says eminent domain is used in fewer than 1% of its land transactions: five times in the past year, none on homes. The utility disputes describing the line as a data center project. The generation plan it agreed with the Georgia Public Service Commission in December 2025 says about 80% of nearly 10,000 new megawatts is expected to power data centers.

    Executive Summary

    Georgia Power is acquiring land and easements for one of five transmission projects that together add more than 1,000 miles of high-voltage lines to Georgia’s grid. Transmission lines are the long-distance wires that move bulk electricity from power plants to local substations. The buildout accompanies roughly 10 gigawatts of new generation that state regulators certified in December 2025, and about 80% of that generation is expected to power data centers.

    The story matters because it moves the cost of AI-era grid expansion out of abstract rate cases and onto specific parcels of land. Georgia Power argues that large data center customers will pay more, which it projects will cut residential bills by about $102 a year from 2029. That argument does not address the right-of-way. Nearly 30 homes are to be leveled, and permanent easements will cover hundreds of parcels.

    How utilities conduct those negotiations shapes how fast AI infrastructure can be powered and on what terms. So does how often they fall back on eminent domain, and how publicly they justify it.

    The Rate Math Counts Bills, Not Easements

    Georgia Power frames its public case for the buildout around electricity bills. The utility projects that the five transmission projects will save residential customers about $102 a year each starting in 2029. The mechanism is that large-load customers, meaning very big single users such as data centers, are required to pay more. Media Relations Manager Meredith Stone said those funds put “downward pressure on the rates for our residential customers.” That is a claim about tariffs, the prices customers pay, and it is the number the utility leads with.

    The land side of the same projects works differently. Delivering power over more than 1,000 miles of new line means securing rights across more than 330 parcels and leveling nearly 30 homes. Georgia Power says it opens negotiations at 125% of appraised value. Where owners grant an easement rather than sell outright, the utility gains a permanent right to use a strip of their land. David Needham, a Georgia attorney who has represented landowners in eminent domain cases for more than a decade, said those rights stay attached to the property after it is sold. They can prohibit permanent structures beneath the lines and can reserve broad rights for the utility to install additional infrastructure.

    The per-customer savings figure does not capture that cost. A bill saving is spread across the whole residential customer base and recurs every year. An easement is priced once, at the negotiating table, and its restrictions are carried indefinitely by whoever owns that particular piece of ground. For utilities and data center developers, the consequence is that AI-driven grid expansion depends on hundreds of individual land deals, not only on the generation plan regulators certified. Those deals determine how fast the expansion proceeds and how much public acceptance it wins.

    Condemnation Is Rare; the Room to Say No Is Narrow

    On the record, condemnation is uncommon. Georgia Power says eminent domain is a last resort that occurs in fewer than 1% of its land transactions. It says the power was used five times in the past year, none involving residential homes. Nothing disclosed contradicts those figures. The case that drew the most public attention also ended in a deal. It became widely known through social media posts by Ansley Brown and involved the office of U.S. Rep. Brian Jack, and Georgia Power said it reached an agreement with the family, without disclosing the terms.

    Residents’ description of the process is also consistent with how it works. “We don’t have a choice in this,” Brown said in one video. Once a route is chosen, a landowner’s options are a full sale or an easement, and keeping the line off the property is not one of them. Condemnation stands behind the negotiation as the alternative if talks fail. Needham called the resulting easement agreements “very much tilted in favor of the power company,” while noting that “there is compensation offered.” Both accounts can be accurate: forced takings are rare, and the bargaining position is uneven.

    Who the Line Serves Depends on Which Number You Read

    Georgia Power says it is “not in the data center business.” It says the Ashley Park-Wansley line will serve the broader needs of the communities and customers who rely on reliable service. CBS reported that 70% to 80% of the power from this particular line would go to AI data centers. A Georgia Power representative was unable to confirm that estimate.

    At the portfolio level the question is less open. In December 2025 the Public Service Commission and Georgia Power agreed to certify nearly 10,000 megawatts of new generation, and the agreement said approximately 80% of it is expected to power data centers. Transmission lines are shared assets, and the same wires feed homes, hospitals and server halls. The utility’s framing is therefore defensible for any single line. Still, the regulator-approved document says the new demand justifying this much new capacity comes mostly from data centers.

    The distinction matters because eminent domain rests on public use. The more visibly new corridors are tied to a small number of very large customers, the more utilities and regulators have to show the broader benefit. The $102 savings projection plays exactly that role.

    Georgia’s Welcome for Data Centers Is Getting Conditional

    Georgia hosts more than 200 operational data centers, nearly 170 of them in Atlanta, including facilities owned by Microsoft, Amazon and Google. A sales and use tax exemption dating to 2018 waives 100% of state and local sales and use taxes on equipment purchases for projects that meet a minimum investment of $100 million to $250 million. In 2024 lawmakers voted to suspend new exemptions, and Governor Brian Kemp vetoed the measure. A December 2025 evaluation by the University of Georgia’s Carl Vinson Institute of Government projected the exemption’s net fiscal impact at roughly negative $574 million.

    Georgia is now scrutinizing its tax incentives, charging large loads more, and facing land disputes in public view. The pattern for operators is that the state remains open to data centers but is pricing more of their wider costs explicitly. “The policy direction has clearly shifted,” said J. Thomas Perdue, a policy analyst at the Georgia Public Policy Foundation. For developers weighing sites, power in Georgia increasingly comes with public questions about who bears the cost of delivering it.

    Background

    Georgia Power is the state’s largest electric utility and a subsidiary of Southern Company. It plans its generation and transmission through an Integrated Resource Plan, a long-range forecast of demand and the resources needed to meet it. The plan requires approval from the Georgia Public Service Commission, the elected body that regulates the state’s utilities. The commission approved the 2025 plan, which cited continued power needs driven by AI investment. In December 2025 it certified nearly 10,000 megawatts of new generation. It also approved a formal process to evaluate grid-enhancing technologies that can squeeze more capacity from existing lines.

    Georgia has courted data centers since 2018 through sales and use tax exemptions and now hosts more than 200 operating facilities, most of them around Atlanta. Legislative support has cooled: a 2024 vote to suspend new exemptions was vetoed, and a 2025 state-commissioned evaluation found the incentive to be a net fiscal cost. Eminent domain, the power to take private property for public use with just compensation, is available to utilities building infrastructure. Georgia Power says it treats it as a last resort.

    Sources

    Source: ‘My childhood home is being taken’: Eminent domain for data centers targets properties across a thousand miles of grid expansion in Georgia (Fortune, July 26, 2026). The article reports on Georgia Power’s land acquisition for the Ashley Park-Wansley line and its broader 1,000-mile transmission plan.

  • Fort Bliss’s 1,384 Acres Show Military AI’s Hard Limit Is Power, Not Land

    Fort Bliss’s 1,384 Acres Show Military AI’s Hard Limit Is Power, Not Land

    TL;DR · 30-second read

    The Short Version

    The United States military is letting private companies build giant computer centers for artificial intelligence on its bases. One in Texas will cover more than two square miles of Fort Bliss. Another is planned for a Utah testing range.

    The catch is electricity. A local newsroom estimated the Texas site alone could use more power than all 460,000 homes and businesses on El Paso’s power system combined. Members of Congress from both parties now want the Pentagon to explain where that power and water will come from before building starts.

    Lawmakers from both parties are trying to attach conditions to the Defense Department’s program of leasing military land to private companies for AI data centers, Politico reported on July 25, 2026. The Army has signed two conditional agreements: Carlyle Group will build on 1,384 acres at Fort Bliss in El Paso, Texas, by 2027, and CyrusOne will build on 1,201 acres at Utah’s Dugway Proving Ground by 2029, according to an Army fact sheet. The Air Force has offered unused land on five installations.

    Most of the proposals would require briefings, studies or planning rather than stopping construction. A provision from Rep. Ken Calvert (R-Calif.) requiring DOD to brief Congress on community impacts before construction was adopted in the House Defense spending bill, and a provision from Rep. Cory Mills (R-Fla.) barring land deals for data centers with significant components made by U.S. adversaries is in the House-passed NDAA. Broader Democratic amendments, including one from Rep. John Garamendi (D-Calif.), were rejected.

    Executive Summary

    The Pentagon’s plan to host commercial hyperscale data centers on military bases, set in motion by President Trump’s executive order last year directing the department to identify suitable sites, has moved from policy to signed deals. The Army describes its Fort Bliss and Dugway projects as coming at “no upfront cost to taxpayers” and including “comprehensive behind-the-meter power and water solutions”, meaning the sites would generate or source their own electricity and water rather than draw on the local utility.

    That promise is now the center of the congressional debate. The measures gaining traction do not question whether the military can offer land; they ask the Defense Department to show, before construction, how these facilities will be powered and cooled without straining base infrastructure, local grids, or water supplies. For developers, that turns power and water planning from a project detail into a condition of doing business on federal land.

    The House and Senate still have to reconcile their versions of the defense authorization and spending bills, possibly after the November elections, so the final terms remain open.

    Land Is the Part the Military Can Give Away

    The Army’s pitch to developers is built on land: large, secured, already federally controlled parcels offered without an upfront cost to taxpayers. Fort Bliss alone puts 1,384 acres on the table, and Dugway another 1,201. Even supporters in Congress frame the benefit in land terms. Rep. Derrick Van Orden (R-Wis.) said he favors base siting if it means fewer data centers on farmland that could otherwise grow crops.

    But acreage is not what limits an AI data center. The binding constraint is electricity, and then water for cooling. El Paso Matters has estimated that the Fort Bliss facility could require more power than all of El Paso’s 460,000 electricity customers combined. Whether or not that estimate holds at full build-out, it sets the scale: a single campus of this kind can rival a mid-sized city’s demand. No amount of available land changes that arithmetic.

    That is why the Army’s promise of “behind-the-meter” power carries so much weight. Behind-the-meter means generation on the customer’s side of the utility connection, so the data center would not simply pull from the local grid. If it works, the developer absorbs the cost and risk of building a power plant. If it falls short, the load lands on the regional utility and its ratepayers, which is precisely the outcome lawmakers from both parties say they want the Pentagon to rule out in advance.

    Congress Is Asking for Proof, Not Stopping the Build-Out

    The legislative scorecard shows where the consensus sits. Proposals to halt or ban construction failed: Rep. Rashida Tlaib’s (D-Mich.) amendment to prohibit AI data centers on federal lands was rejected, as was a Senate Democratic amendment to block leasing until DOD finalizes a data center strategy. Garamendi’s pre-deal certification requirement, covering energy, water, noise, light, security and supply chains, was voted down in House Armed Services.

    What advanced is disclosure. Calvert’s provision, written into the House Defense spending bill, acknowledges that data centers “place significant strain on energy and water resources” and requires a pre-construction briefing on community impacts. A bipartisan Energy-Water package asks the Department of Energy to mitigate data centers’ effects on grid reliability and ratepayers. Even critics of Garamendi’s approach, such as Rep. Pat Harrigan (R-N.C.), suggested annual impact reports as an alternative. The live disagreement is not whether the Pentagon must account for power and water, but whether that accounting comes before a deal is signed or after.

    DOD officials argue the department has already accounted for these impacts and warn that added requirements could slow the military in a competitive AI race. That concern is legitimate; so is lawmakers’ complaint, voiced by Rep. Mike Levin (D-Calif.), that they have not received a briefing. Both claims could be tested quickly if the department published the power and water figures behind its agreements.

    The Supply Chain Clause May Bite Harder Than the Studies

    The provision with the most direct commercial consequence may be the one from Mills, now in the House-passed NDAA. It would bar DOD from providing land to data centers containing “significant components” manufactured by U.S. adversaries. An unnamed Army official told the Federal News Network that this would create an “unworkable standard” that could drive commercial partners away from Army land.

    Unlike a briefing requirement, a component rule reaches into the equipment bill of materials: servers, networking gear, power and cooling systems. How much it bites depends on how “significant” is defined and enforced, and on whether it applies to behind-the-meter generation equipment as well as computing hardware. For developers weighing base sites against private land, a sourcing rule that is hard to certify could matter more to the economics than any study requirement.

    Who Carries the Risk

    For Carlyle and CyrusOne, the emerging terms shift risk onto the developer: finance the facility, supply its own power and water, and, if Mills’ language survives conference, document the origin of key components. For base commanders, the question is whether on-site generation and water use interact with installation readiness. For neighboring communities such as El Paso, the stakes are grid reliability and electricity bills, the same concern driving the House Energy and Commerce Committee’s Ratepayer Protection Act, H.R. 9340.

    The broader lesson for anyone siting AI infrastructure is that federal land does not bypass the power question. It relocates it, and adds a layer of public accountability that private sites do not face.

    Background

    AI data centers pack large numbers of power-hungry processors into a single site, and their electricity and cooling needs have become a flashpoint for utilities, regulators and communities across the United States. Hyperscale facilities, the largest class of data center built for cloud and AI workloads, can draw power on the scale of a small city and often use significant volumes of water for cooling.

    The Defense Department entered this market after a presidential executive order last year directed it to identify military sites suitable for AI infrastructure. The Army’s model leases base land to private developers, who build and operate the facilities, and the Air Force has offered unused land at five installations. Carlyle Group is an investment firm; CyrusOne is a data center developer and operator.

    Sources

    Source: The Pentagon wants to build data centers. Congress would like a word. (Politico) — bipartisan congressional scrutiny of Defense Department land leases for AI data centers at Fort Bliss, Dugway and Air Force installations.

  • PJM’s 3.1 GW Data Center Dropout Shows AI’s Other Grid Risk: Load That Leaves

    PJM’s 3.1 GW Data Center Dropout Shows AI’s Other Grid Risk: Load That Leaves

    TL;DR · 30-second read

    The Short Version

    When one power line failed near Washington, DC, a wave of data centers (the warehouse-sized buildings full of computers that run the internet and AI) unplugged from the power grid within seconds and switched to their own backup power.

    Together they had been using about 3% of the electricity on a grid that serves 67 million people. Losing that much demand at once threw the system off balance. Lights flickered from Virginia to Chicago, and it took more than 10 minutes to settle.

    It was twice as big as a similar scare in 2024, and data centers keep multiplying. The proposed fix is to make them stay connected through brief hiccups, often by using giant batteries.

    A single power line failure outside Washington, DC, this past week caused a wave of Northern Virginia data centers to switch to backup power at nearly the same moment, TechCrunch reported. According to PJM data, about 3.1 gigawatts of demand disappeared from the PJM Interconnection grid in roughly 30 seconds. After a partial recovery, more facilities dropped off, and the grid’s surplus peaked at 3.49 gigawatts. Stabilizing took another 11 minutes. A line fault like this one normally takes only a few seconds to recover from.

    According to Reuters, the disconnected load was about 3% of PJM’s demand at the time. Sensor data from the startup Ting Labs showed voltage spiking across the grid from Northern Virginia to Chicago. There was no blackout, but lights flickered across the region. The event was roughly twice the size of a 2024 PJM incident in which 60 data centers disconnected at once and removed 1.5 gigawatts.

    Executive Summary

    Most discussion of data centers and the power grid asks whether there is enough electricity to feed them. This event shows the opposite failure: a cluster of very large customers that all leave the grid at once when they sense trouble. Each facility’s protective logic behaved as designed and switched to on-site backup power when voltage dipped. Together, those individually sensible decisions turned a routine line fault into a regional disturbance that lasted more than ten minutes.

    Two remedies are being proposed. The first is coordination. Ali Zain Banatwala, a senior market models specialist at the Independent Electricity System Operator, argues that neighboring loads need a way to disconnect and reconnect one after another rather than all together. The second is ride-through, which means keeping facilities connected through brief disturbances. Ricardo de Azevedo, CTO of ON.Energy, whose company sells campus-scale battery systems built for that purpose, said ERCOT, the Texas grid operator, will require large loads to ride through disruptions.

    The stakes rise with the load. Synapse Energy Economics put data centers at about 6% of PJM’s load in 2024 and projects 24% by 2040. The potential size of a synchronized dropout grows with that share unless the facilities are built to behave differently.

    AI’s Other Grid Problem Is Load That Leaves

    An electric grid has to keep supply and demand in near-perfect balance from moment to moment. When a line goes down, the grid normally absorbs the loss and rebalances within seconds. This time, the voltage dip from the fault reached many data centers sitting close together. Their protection systems are designed to make split-second decisions to safeguard the computers inside, and they moved the facilities onto backup power within a few seconds of each other. The grid lost about 3.1 gigawatts of demand in roughly 30 seconds. Generators were suddenly producing more electricity than customers were using, and voltage jumped.

    The second wave is the detail grid planners should focus on. PJM’s grid appeared to recover partway before more loads dropped off, pushing the surplus to a peak of 3.49 gigawatts. In that pattern, the disturbance triggers disconnections, and the disconnections deepen the disturbance. That feedback is what stretched a seconds-long event into an 11-minute one. A gigawatt is roughly the output of a large power plant. In effect, the grid had to absorb the sudden departure of several power plants’ worth of customers.

    That is why the grid risk from the data center buildout is not only a question of supply. Operators are used to planning around the sudden loss of a large generator. Clustered data centers create a mirror-image contingency: a large block of customers lost all at once because of a single triggering event. Everyone on the grid is exposed to that. Households saw flickering lights, generators must ramp down fast, and the operator must hold capability in reserve for a contingency that grows as data center load grows.

    Concentration Turns a Local Fault Into a Regional Event

    Northern Virginia has the highest concentration of data centers in the world. That density is what made the disconnection synchronized, because one voltage dip reached many facilities almost at once. The effect traveled well beyond Virginia. Ting Labs runs a sensor network through household electrical outlets, and it recorded the voltage spike as far away as Chicago. PJM covers the territory from New Jersey to Illinois, serves 67 million customers, and is the largest grid operator in the United States.

    The trend line gives the event its weight. In 2024, 60 data centers disconnected together and removed 1.5 gigawatts. This time the figure was about 3.1 gigawatts, roughly double. Data centers were about 6% of PJM’s load then, and Synapse Energy Economics projects 24% by 2040. Two events are not a statistical series, and nothing here shows the next one will double again. The arithmetic still matters: if protective behavior stays the same while the share of load it governs roughly quadruples, the ceiling on a synchronized dropout rises with it.

    De Azevedo called the event “the canary in the coal mine” and said incidents involving large loads are “happening more and more.” That claim comes from a vendor of the remedy. The two PJM incidents, with their measured sizes, are the documented reference points.

    Two Fixes: Choreograph the Exit, or Don’t Leave

    The first approach accepts that data centers will disconnect but asks them to do it in order. “We need to figure a way for these loads that are located next to each other to sequentially either disconnect or reconnect,” Banatwala said. Staggered behavior would let grid operators write procedures in advance instead of reacting to a cliff. The hard part is coordination. The facilities belong to different owners, each has settings tuned to protect its own uptime, and they would need shared thresholds or a shared signal.

    The second approach is ride-through, meaning the facility stays connected through brief disturbances. ON.Energy’s version is an uninterruptible power supply, the battery backup that keeps servers running through outages, sized for an entire campus, including chillers and other equipment as well as servers. Batteries and power-conversion equipment sit between the grid and the facility, so the grid sees one steady, predictable load. The company says the system:

    • charges its batteries when the grid has surplus power;
    • discharges to the servers when supply dips;
    • follows the grid within milliseconds;
    • smooths the swings of AI training workloads that ramp power up and down.

    It says it is installing 3 gigawatts of these systems across four campuses.

    Those claims are specific enough to test. The test is whether a campus behind such a system stays connected and grid-friendly during a real fault like this one. The economics matter too. Sizing batteries and power electronics for a whole campus adds capital cost that the developer bears, while most of the benefit goes to the grid. Mandates may be what shifts that calculation, such as ERCOT’s ride-through requirement, which de Azevedo described.

    What Developers and Buyers Should Expect

    From a tenant’s point of view, the July event worked: the data centers switched to backup, and the computers presumably kept running. The cost of that decision fell on the grid and everyone else connected to it. This asymmetry is what makes the event a policy question rather than just an engineering one. Individual facilities have little reason to change behavior that protects their own uptime unless interconnection rules require it.

    For developers, the likely direction is toward grid connection terms that specify how a facility behaves during a disturbance, not just how much power it draws. ERCOT is moving that way, according to de Azevedo. PJM, where both incidents occurred, is where the question is now most visible. For suppliers of storage, power conversion and switchgear, the grid-facing layer of a campus becomes part of the design requirement. For colocation buyers, it is reasonable to ask providers how their facilities respond to voltage dips and whether ride-through requirements could change facility design or pricing.

    Background

    PJM Interconnection is a regional transmission organization, the independent body that runs the high-voltage grid and wholesale electricity market for an area stretching from New Jersey to Illinois. It serves 67 million customers and is the largest grid operator in the United States. Its territory includes Northern Virginia, which has the highest concentration of data centers in the world.

    Data centers are built never to lose power. When grid voltage wavers, they switch to on-site backup, such as uninterruptible power supplies and generators, in a split second. That design protects the computers inside. When many facilities share the same stretch of grid, however, it also means they can react to the same disturbance at the same moment. PJM saw this in 2024, when 60 data centers disconnected simultaneously, and saw it again at twice the scale this July. ERCOT, the operator of most of Texas’s grid, is among the grid managers moving to require large loads to ride through disturbances.

    Sources

    Source: One fallen power line exposed a growing AI data center problem — here’s how to fix it (TechCrunch): a report on the roughly 3-gigawatt data center disconnection on the PJM grid and proposed ride-through fixes.