1. The Moment

On April 13, 2026, Idaho Department of Water Resources Director Mathew Weaver signed an emergency drought declaration covering all 44 Idaho counties, approved the same day by Governor Brad Little.¹ The declaration followed the state’s second-warmest winter since 1896 and a record-low April 1 snowpack,¹ and an IDWR methodology order that placed the predicted shortfall for senior surface-water users on the Snake River Plain at 181,600 acre-feet heading into the 2026 irrigation season.²

Weaver described unprecedented early-season snow loss starting March 17, including at elevations above 10,000 feet where snow usually persists well into spring.¹ Three weeks earlier, on March 20, 2026, IDWR had imposed a five-year moratorium on new groundwater permits in southern Canyon County — adjacent to the Ada County parcel where Meta’s Kuna data center sits — citing public concern over pending development and future groundwater availability.³

The drought declaration and the groundwater moratorium arrived in the same weeks that Meta’s 200 megawatt Kuna facility was coming up to full operational ramp. Pleasant Valley Solar 1, the 200 MW solar power-purchase agreement Idaho Power procured for the data center, began commercial operation on March 2, 2025;⁴ Pleasant Valley Solar 2, an additional 125 MW, had a targeted commercial operation date of May 31, 2026.⁴ The North American Electric Reliability Corporation’s 2025 Long-Term Reliability Assessment, released January 29, 2026, had already placed the WECC-Northwest region at high risk for resource adequacy through 2030, and attributed approximately 224 gigawatts of new national peak-demand growth to data centers and artificial intelligence.⁵

None of this is coincidence, but it is also not causation. The drought is a climate event; the hyperscale ramp is a commercial one; the rate case is an institutional one. The three do not collide by design. They collide because the institutions that could have anticipated the collision were not built for it.

2. What Meta Signed

The entity on the contract is Brisbie, LLC. In a February 2022 investigation, BoiseDev traced Brisbie to a Delaware company called Foxtrot Acquisition Corp, which in turn shared an address with Meta’s Menlo Park headquarters.⁶ The confirming document is not journalism but the utility’s own filings: Idaho Power’s November 2022 application to the Idaho Public Utilities Commission for Pleasant Valley Solar 1 identifies “Brisbie, and its parent company Meta Platforms, Inc.,” by name.⁷ Industry analysts at Dgtl Infra and Data Center Knowledge reached the same conclusion at the time of the announcement,⁸⁹ but the point worth holding is that the corporate relationship is not inference; it is in the Commission record.

The Kuna project itself is an $800 million investment, approximately 960,000 square feet, across a 325-acre site, with a full build-out power requirement of 200 megawatts.⁹⁸ Construction created approximately 1,200 jobs at peak; operational staffing is about 100 permanent positions.⁶⁹ Meta built a water and wastewater treatment facility, worth roughly $50 million, and donated it to the City of Kuna; the plant was sized beyond Meta’s own needs, explicitly to anchor additional industrial development on the surrounding parcels.⁹⁸ Meta was the first project to make use of a 2020 Idaho statute, HB 562 (codified at Idaho Code § 63-3622VV), which exempts data-center server equipment and facility construction from sales tax, conditioned on a minimum $250 million capital investment over five years and at least 30 permanent jobs at or above the county average wage within two.¹⁰⁶

The utility agreement is the more consequential instrument. On December 22, 2021, Idaho Power filed Case No. IPC-E-21-42, seeking approval of a “Special Contract” with Brisbie for an energy-services arrangement covering loads above 20 megawatts — the threshold at which Idaho Power’s tariff requires an individually-negotiated contract rather than a standard class rate.¹¹⁶ The contract’s rates and charges appear in the public Idaho Power tariff as Schedule 33, sheets 33-1 through 33-5 — one of only two named special-contract customers in Idaho Power’s tariff; the other is Lamb Weston, the potato processor, in Schedule 34.¹² The Commission approved the contract by Order No. 35777 on May 11, 2023.⁴

What the public record does not contain is the contract’s actual pricing, load forecast, or the present-value revenue-requirement analysis that supposedly demonstrated the contract would “hold other Idaho Power customers harmless.” Those documents — the Energy Services Agreement itself, the Construction Agreement, and the confidential Exhibit No. 3 attached to the Goralski Direct Testimony containing the present-value revenue-requirement analysis — were filed under protective order and remain sealed.¹¹ The methodology framework is public; the numbers inside it are not. Harvard’s Electricity Law Initiative, in a March 2025 paper reviewing approximately 50 regulatory proceedings between utilities and data centers, identified secret special contracts as one of three principal mechanisms by which costs are shifted from hyperscalers to ordinary ratepayers.¹³ The Idaho case fits the template.

The gatekeeping worked the way the architecture allows it to work: the Commission’s docket for IPC-E-21-42 shows no intervening parties filing on behalf of residential customers, industrial customers not covered by the contract, or the environmental organizations that might otherwise have sought access to the sealed record. The special contract was approved without adversarial review.¹⁴

The two solar power-purchase agreements tied to the Kuna load followed the same pattern. Idaho Power filed the Pleasant Valley Solar 1 PPA in November 2022 (IPC-E-22-29); the Commission approved it as Order No. 35739 on April 12, 2023.⁷ The PV1 application, which is public, states that Meta seeks to support 100% of new data center operations with new renewable resources, and that Idaho Power would accordingly add new renewables to its system.⁷ Pleasant Valley Solar 2, a separate 125 MW PPA, was filed in January 2024 as IPC-E-24-01.⁴

The mechanical detail that matters most for understanding the 100% renewable claim is the word annual. The PV1 application states plainly that the renewable resources for Brisbie must be sized such that total renewable generation over the course of a year matches or slightly exceeds Brisbie’s annual energy consumption.⁷ The mechanism lives on the public side of Idaho Power’s Clean Energy Your Way tariff suite — specifically Schedule 62, the Clean Energy Your Way — Construction offering, under which any annual shortfall is reconciled through a separate renewable-energy-credit purchase contract.¹² On a hot summer afternoon in Kuna, the solar panels are producing more than the data center needs and the surplus offsets grid consumption at other hours. At two in the morning in January, with snow on the arrays and no wind, the data center is drawing from the grid that other Idaho Power customers share.

The public framework Idaho Power put on the record in IPC-E-21-42 is that the contract “holds other Idaho Power customers harmless.”¹¹ The numbers that supposedly demonstrate that claim are sealed. No outside party was present at the proceeding to test them. On May 11, 2023, the Commission approved the contract.

3. The Bill Comes Due

On May 30, 2025, Idaho Power filed Case No. IPC-E-25-16, its first full general rate case in the Meta era, requesting a $199.1 million annual revenue increase — a 13.09% increase to adjusted base revenue.¹⁵¹⁶ The Idaho Press noted that this request was significantly above the 7-to-8% range that had characterized recent rate-case filings.¹⁷

The utility broke out the request in its press release into five components: $73 million for new energy production and storage resources, $53 million for grid investments, $25 million for wildfire resilience, $20 million for labor, and $28 million for other operational expenses including technology, fleet, and facilities.¹⁶¹⁸ The KTVB summary of the as-filed impact on the average residential customer using 900 kilowatt-hours a month: about $21.66 a month, or roughly $260 a year.¹⁸¹⁹

The more revealing number is the as-filed class allocation. Capital Press reported Idaho Power’s proposed distribution: residential customers at 17.35%, irrigation at 17.32%, small general service at 17.31%, large power at 8.22%, and large general service at 7.26%.²⁰¹⁸ The two smallest customer classes and the agricultural class were proposed to shoulder the steepest percentage increases; the largest industrial class was proposed to receive the smallest.

A settlement stipulation filed by Idaho Power in October 2025 reduced the headline figure; on December 30, 2025, the Idaho Public Utilities Commission approved the settlement, producing an average 7.48% rate increase that took effect January 1, 2026.²¹ The approved settlement still moved residential and agricultural irrigation up, and still moved the largest industrial class up by substantially less: approximately 9.74% residential, 8.49% agricultural irrigation, and 4.72% large power.²¹ The residential-to-large-power ratio of approximately two-to-one in the as-filed percentages carried through the settlement.

The utility’s public explanation for the rate case framed the drivers in terms of system-wide growth and reliability, rather than any specific customer class. Idaho Power’s own language: the case was driven by rapid growth across its service area, new energy production and storage needs, added grid investments, wildfire resilience, and labor.²¹ The original residential service-charge proposal in the filing — raising the flat monthly charge from $15 to $25 — did not survive settlement.¹⁷

At the November 2025 public hearings, just over a dozen Idaho Power customers testified; BoiseDev reported that the testimony was overwhelmingly opposed to the proposed increases, with hundreds of written comments repeating a common theme about large corporate customers and new data centers driving the request.²² The Idaho Public Utilities Commission’s own scheduling order (Order No. 36731, issued August 22, 2025) laid out the public-comment calendar for the proceeding.²³ The Idaho Irrigation Pumpers Association intervened, ultimately claiming a reduction of roughly 7% in overall revenue collection from the irrigation class relative to the as-filed request.²⁴

4. The Capital Plan Behind the Rate Case

Rate cases are downstream. The upstream question is why Idaho Power needs the money, and that answer lives in the 2025 Integrated Resource Plan and in IDACORP’s investor disclosures.

Idaho Power’s 2025 IRP — the utility’s 20-year resource planning document — projects 8.3% annual retail-sales growth over the next five years and 2.7% over twenty.²⁵ For comparison, the 2021 IRP projected 1.4% growth — meaning the central forecast has roughly sextupled in four years.²⁵²⁶ The forecast translates into roughly 1,000 megawatts of additional peak load within five years and roughly 1,700 MW over twenty — against a 2024 recorded peak firm load of 3,793 MW.²⁵ Adding roughly 45% to peak load in twenty years is not load growth of the sort a utility forecasts for a gradually-increasing residential base.

The capital response tracks the forecast. Idaho Power invested $943 million in its system in 2024, and more than $1 billion in 2025.²¹ The 2024–2028 capital expenditure plan is approximately $4 billion — an average of $796 million a year, approximately double the prior five-year period’s run-rate.²⁷ The North American Electric Reliability Corporation’s 2025 Long-Term Reliability Assessment, issued January 29, 2026, attributes the +224 GW national peak-demand forecast overwhelmingly to data centers and artificial intelligence, and it places WECC-Northwest at high risk for resource adequacy through 2030.⁵

On the investor side, IDACORP reported 2025 earnings per share of $5.90, up from $5.50 in 2024; its 2026 guidance is $6.25 to $6.45, an 8% midpoint growth rate.²⁷ The allowed return on equity is 9.6%, calculated on an Idaho-jurisdictional rate base of approximately $4.9 billion.¹⁴ These are the numbers the regulated-utility business model runs on: the utility builds infrastructure, the Commission sets a rate base, and shareholders earn a regulated return on the prudent investment. When the rate base doubles, the allowed earnings on that rate base roughly double as well, before any growth in sales volume. That is not a bug in the model; it is the model.

IDACORP’s own 10-K, filed February 20, 2025 for fiscal year 2024, discloses the Brisbie Special Contract and notes that the contract anticipates a significant increase in load that will ramp over a number of years beginning in 2026.²⁸

The Chief Executive’s framing on the February 2026 earnings call emphasized affordability and reliability alongside capital investment: IDACORP CEO Lisa Grow described 2026 as another year of substantial capital investment, with a focus on affordability and reliability.²⁷ The earnings mathematics and the affordability framing are both accurate statements about the same business; whether they can be reconciled is a question the Commission is structurally responsible for answering.

5. The Farmers

Idaho has roughly 6,200 irrigation accounts served by Idaho Power on approximately 500,000 irrigated acres; in historical context, the irrigation class has been about 12.6% of the utility’s base revenue.²⁴ The class’s core rate structure has two components: a per-kilowatt-hour energy charge and a per-kilowatt demand charge. The demand charge is the number an irrigator cannot control by pumping less water on any particular day, because it is billed against the peak load during the billing month.

Under Idaho Power’s current tariff Schedule 24, the 2026 secondary-service demand charge is $16.50 per kilowatt.²⁹ Writing in Idaho Capital Sun in February 2026, Blackfoot-area farmer Adam Young stated that this represented an increase from a 2021 baseline of $6.94 per kilowatt — a rise of roughly 138% in five years, against roughly 19% inflation in the same period.³⁰ The 2026 figure is independently verifiable in the current tariff; the 2021 baseline, as of this writing, is cited only in Young’s op-ed. What is also in Young’s account is the on-farm arithmetic: in his telling, the combined effect of energy and demand-charge increases has translated into roughly 45% higher irrigation cost for his family’s operation than in 2021.³⁰

The IPC-E-25-16 settlement left irrigation at roughly 8.49%;²¹ the as-filed proposal had been 17.32%.²⁰ The Idaho Irrigation Pumpers Association was among the intervenors that pushed the number down; they did so operating inside the constraints of a $40,000 aggregate statutory cap on intervenor funding, which applies to the entire proceeding and all intervening parties combined.³¹ Whether the class-allocation architecture is the right one is a structural question that the current rate case’s settlement did not, by design, reopen.

6. The Framing

Idaho Power’s customer-facing explanation of the rate case is explicit about what the rate increases are not. In response to the question of whether data centers are causing rate increases for all customers, the utility’s rate-case FAQ answers in the negative, stating that Idaho requires large energy users to fund the infrastructure needed to interconnect their businesses, and that the residential customer sector accounts for the largest share of year-over-year load growth from 2024 to 2025.²¹

The utility’s planning staff describes the same period in different language. Speaking to Idaho Capital Sun in August 2025, Idaho Power Resource Planning Leader Jared Hansen described unprecedented growth in the service area, substantial interest in data centers and other industrial expansion, and said the utility has reached the point where it needs to “expand like crazy.”²⁶

The 2025 Integrated Resource Plan, the utility’s own 20-year forecast, is closer in tone to Hansen’s account than to the FAQ’s. The IRP’s 8.3% five-year growth forecast is a sixfold jump from 2021; the peak load forecast adds 1,000 MW in five years to a 2024 peak of 3,793 MW.²⁵ The two documents are not inconsistent in any strict logical sense — a utility can both say that large users fund their own interconnection and that load growth is unprecedented — but they do different work. The FAQ is audience-facing; the IRP is regulator-facing. The claim that data centers are not driving the rate case is a discrete claim about who pays for what; the claim that the utility needs to build aggressively is a discrete claim about why the overall system is getting bigger. The open question for the present architecture is whether a “no-harm” cost allocation done in a sealed exhibit in 2023 produces the right answer for a system that is forecast to grow 45% in peak load by 2044.

7. The Regulator

The Idaho Public Utilities Commission is a three-member body whose commissioners are appointed by the governor with state-senate consent for six-year staggered terms, with the restriction that no more than two may be of the same party.³²³³ The sitting commission as of April 2026 comprises President Edward Lodge (appointed February 2023), John R. Hammond, Jr. (appointed January 2022), and Dayn Hardie (appointed February 2025).³²

President Lodge’s published biography on the Commission’s own website lists his pre-appointment employment history. From 2004 to 2020 — sixteen years — he served as Director of Government and Regulatory Affairs for Qwest and its successor CenturyLink, a regulated telecommunications utility.³² He was appointed to the Commission that regulates utilities roughly three years after leaving that role. This is not opposition research; it is the Commission’s own bio.

The more contested piece of the institutional record is a whistleblower lawsuit filed on October 7, 2024 in Ada County District Court by former IPUC Executive Director Maria Barratt-Riley and former Policy Strategist Joshua Haver, after their terminations on April 11, 2024.³⁴ The complaint, as reported by East Idaho News, alleges that the Commission “is politicized, is not independent, and is hostile to report, investigation, and complaint from within where controversy implicates favored actors.”³⁴

Two specific allegations are worth recounting in detail. The first is that Commissioner Hammond retained access to a PUC utility information system dating from his prior role as PUC Deputy Attorney General — access that the Commission’s own lead deputy attorney general subsequently confirmed commissioners should not have under the quasi-judicial separation required of their role.³⁴ When Barratt-Riley raised concerns, the complaint alleges, Hammond repeatedly admonished her.³⁴

The second is a February 6, 2025 meeting at a Meridian restaurant, where the three sitting commissioners (including the then-newly-appointed Hardie) met with former IPUC Commissioner Paul Kjellander, who was at the time representing a client — David Johns, General Manager of Veolia, the French-owned water utility serving Boise — that had an active rate increase request of roughly 20% pending before the Commission.³⁴ Veolia’s rate case settled in late May 2025 at near-12%, worth roughly $7 million in additional annual revenue; most Veolia residential customers saw bills rise 12.4% in June 2025.³⁴

These are allegations in active litigation. No finding of liability has been made. What the whistleblower complaint does not allege, though, is the part of the institutional architecture that is not contested. Idaho Code § 61-617A, the state’s intervenor-funding statute, caps the total funding available to outside parties intervening in a Commission proceeding at $40,000 — a ceiling that applies to all intervenors combined, in a single proceeding, and only where the Commission determines after the fact that the intervenor’s participation materially contributed to the decision.³¹ A rate case of the IPC-E-25-16 scale involves tens of thousands of pages of testimony, expert analysis of utility cost-of-service studies, and extensive discovery. Forty thousand dollars divided across a residential group, an agricultural group, an environmental group, and a low-income advocacy group is not, in operational terms, very much.

Idaho is also among the small handful of U.S. states without a formal consumer advocate office empowered to represent residential customers in rate-case proceedings as a permanent institutional counterweight.³⁵ Oregon has the Citizens’ Utility Board, an independent nonprofit established in 1979;³⁵ Ohio has the Office of the Ohio Consumers’ Counsel, a statutory body;³⁶ Virginia’s equivalent is housed in the state Attorney General’s office.³⁷ Idaho has no institutional equivalent. In a rate case, this means that the systematic technical counter-weight to the utility’s testimony is largely absent, except to the extent Commission Staff play that role (which they partially do, and which the lawsuit alleges was itself compromised in at least one adjacent matter).

This is the institutional configuration in which IPC-E-21-42 was approved without intervenors, in which the Brisbie contract’s financial analysis was sealed, and in which IPC-E-25-16 was settled.

8. What Everyone Else Built

In the twelve months between January 2025 and January 2026, five U.S. states approved or enacted specific regulatory structures to address the cost allocation problem that Idaho’s case file records no formal inquiry into. A sixth, Arizona, opened a formal inquiry in April 2025 without yet producing a tariff.

Virginia. The Virginia State Corporation Commission issued its final order in Case PUR-2025-00058 — Dominion Energy’s biennial review — on November 25, 2025. The order creates a new GS-5 rate class for customers with 25 megawatts or more of demand and a monthly load factor above 75%.³⁷ The minimum billing structure is 85% of contracted transmission demand, 85% of contracted distribution demand, and 60% of generation demand — three minimums, not two.³⁷³⁸ Contracts are 14 years with three years of advance notice on demand reduction, collateral requirements, and exit fees. GS-5 takes effect January 1, 2027.³⁷ Most of Virginia’s roughly 450 data centers are expected to fall into GS-5.³⁸ The American Action Forum noted that Virginia’s legislative and regulatory response followed a period in which PJM capacity-auction prices rose approximately 833% for the 2025–2026 delivery year, driven predominantly by AI demand in Virginia.³⁹

Ohio. The Public Utilities Commission of Ohio approved an AEP Ohio data-center tariff on July 9, 2025 in Case No. 24-508-EL-ATA.⁴⁰ The threshold is 25 megawatts of new aggregate load; existing customers expanding by more than 25 MW also trigger the tariff.⁴¹ Minimum billing is 85% of contracted capacity — an increase from the prior 65% baseline — with 12-year contracts (a 4-year ramp plus an 8-year minimum), a 3-year minimum-charges exit fee, and collateral requirements for non-investment-grade customers.⁴¹⁴² AEP Ohio’s data-center load grew from roughly 100 MW in 2020 to 600 MW in 2024 and is forecast to reach 5 gigawatts by 2030; interconnection requests total more than 30 GW.⁴² The Ohio Manufacturers’ Association appealed the tariff to the Ohio Supreme Court in November 2025.⁴³

Oregon. Oregon Governor Tina Kotek signed House Bill 3546, the Protecting Oregonians With Energy Responsibility Act, in June 2025, after a bipartisan Oregon House vote of 41–16.⁴⁴⁴⁵ The POWER Act creates a new customer class for facilities at or above 20 megawatts, requires a 10-year minimum contract with a minimum payment commitment, and imposes an obligation to pay for new transmission.⁴⁴ The contextual number Oregon lawmakers cited: in 2024, Oregon’s two largest investor-owned utilities disconnected nearly 58,000 households and 1,930 small businesses for non-payment.⁴⁴

Georgia. Georgia’s Public Service Commission unanimously approved a new rule on January 23, 2025, requiring Georgia Power to bill new 100-megawatt-and-above customers for site-specific and upstream generation, transmission, and distribution costs.⁴⁶ Contracts are 15 years, up from 5; all such contracts require PSC review.⁴⁶ In a second unanimous 5–0 vote on December 19, 2025, the Georgia PSC approved 9,885 megawatts of new energy certification with Georgia Power itself financially backstopping stranded-asset risk through 2031.⁴⁷ If the data-center contracts do not materialize at the levels forecast, Georgia Power itself absorbs the cost; the Georgia PSC’s fact sheet estimates the backstop as creating approximately $8.50 per month of downward pressure on the average 1,000 kWh residential bill from 2029 through 2031.⁴⁸

Texas. Texas Governor Greg Abbott signed SB 6 into law on June 20, 2025, with immediate effect.⁴⁹ The statute establishes mandatory curtailment authority for ERCOT over large loads at or above 75 megawatts interconnecting after December 31, 2025; requires a minimum $100,000 transmission screening fee; mandates equipment that enables remote disconnection during firm load-shed events; and directs the Public Utility Commission of Texas to evaluate the transmission cost allocation methodology by December 31, 2026.⁴⁹

Arizona. The Arizona Corporation Commission opened a formal inquiry into data-center rate allocation in April 2025.⁵⁰ As of April 2026, no tariff has been approved. Arizona does have a Residential Utility Consumer Office in place as a permanent advocate.

Idaho. A search of the Idaho Public Utilities Commission’s public case docket and of the Idaho Legislature’s 2025 and 2026 bill files shows no data-center-specific rate-class filing, no proposal for minimum-billing requirements, no legislative measure addressing large-load cost allocation specifically, and no formal inquiry opened by the Commission into the structural questions that Virginia, Ohio, Oregon, Georgia, and Texas have each, in different ways, taken up.⁵¹ What Idaho has, procedurally, is the sealed Brisbie Special Contract approved in 2023, the Pleasant Valley PPAs approved in parallel, and the individual rate case IPC-E-25-16 now concluded on its class-allocation percentages.

10. The Steelman

The strongest case for Idaho’s current regulatory posture is made most clearly in Virginia, by an independent commission that studied exactly the question Idaho has not formally posed. In December 2024, Virginia’s Joint Legislative Audit and Review Commission released Data Centers in Virginia, a study conducted with the consulting firm Energy + Environmental Economics (E3) and the University of Virginia’s Weldon Cooper Center, with direct interviews of the major Virginia load-serving entities (Dominion, NOVEC, MEC) and of Amazon, Cloud HQ, Compass, Google, Meta, QTS, and Stack.⁵²

JLARC’s headline finding: current rate structures “appropriately apportion costs to classes and customers responsible for incurring them,” including large loads like data centers, with no identified historic cost-shifting in the Virginia record.⁵² Virginia’s data centers produce, by JLARC’s accounting, about 74,000 jobs (largely in construction), $5.5 billion in labor income, and $9.1 billion in annual GDP contribution. Loudoun County derives $733 million in annual data-center tax revenue, or roughly 31% of its county budget; Prince William County derives $110 million, or 7%.⁵²

The Data Center Coalition’s Director of Energy Policy, Lucas Fykes, used JLARC directly in responding to the Harvard paper, telling Utility Dive in March 2025 that the Coalition’s members are committed to paying their full cost of service, and citing JLARC’s finding on Virginia.⁵³ That is the strongest industry position; it is the one a fair article must engage with.

Two observations, both taken seriously on their own terms.

First, the JLARC finding is backward-looking. The question JLARC answered is whether Virginia’s existing rates have historically shifted costs from data centers onto residential classes. The finding is that they have not. The question this article raises is different: whether the infrastructure now being built across the Western Interconnection, at the pace NERC documents, is being allocated under rules that will continue to apportion costs correctly as the scale of the build-out grows. JLARC’s own forward-looking caveat, in the same report, states the concern directly: the pace and scale of infrastructure development now planned is likely to lead to upward pressure on rates for all ratepayers in the near-to-medium term, even under an allocation framework that has historically done its job.⁵²

Second, the JLARC finding is about Virginia, where the Attorney General’s office has standing to represent ratepayer interests, where the State Corporation Commission has just approved an 85%/85%/60% framework with 14-year contracts precisely because the political branches concluded that additional structure was needed going forward, and where roughly 450 data centers have been operating long enough to generate a record to study. Extending the finding to Idaho involves a jurisdictional leap: Idaho has one hyperscaler operational, no independent consumer advocate, a $40,000 statutory intervenor cap, sealed financial analyses, and as-filed class allocations that proposed a two-to-one disparity between the smallest and largest customer classes. The transitive proof — JLARC found no historic cost-shift in Virginia, therefore Idaho is fine — is not available without additional information about Idaho’s own cost-of-service study, which is behind protective order.

The Harvard paper’s findings are not disproven by JLARC; they live in a different universe. Martin and Peskoe’s review across nearly 50 proceedings identified three specific mechanisms — secret special contracts, federal/state ratemaking disconnects, and colocation arrangements — that allow the pattern Virginia has avoided to operate elsewhere.¹³ Peskoe’s signature framing, repeated in multiple interviews at the time of the paper’s release: under the existing architecture, ordinary ratepayers are paying for the energy costs of the world’s wealthiest corporations.⁵⁴ The steelman answer is that in Virginia the architecture has prevented it; the Harvard answer is that the mechanisms exist where the architecture permits them. Idaho’s architecture, as a matter of public record, permits them.

11. The Water Question

Return to the drought declaration that opens this piece. On April 13, 2026, the statewide drought order covered all 44 Idaho counties; the Snake River Plain predicted shortfall for senior surface-water users was 181,600 acre-feet; the Canyon County groundwater moratorium imposed three weeks earlier had a five-year horizon.¹²³

Meta’s Kuna land purchase included seven separate water rights, totaling approximately three million gallons per day of commercial/industrial capacity.⁶ The Idaho Department of Environmental Quality, in February 2022, confirmed it had not been approached by Meta at that time regarding any water-quality permit; Meta’s spokesperson at announcement said the company would disclose Kuna-specific water use after the facility was operational, citing its annual sustainability-report practice.⁶

Meta’s disclosed comparables elsewhere are useful for calibration. Its Prineville, Oregon data center reported a 2022 withdrawal of 240,302 cubic meters, or about 68.4 million gallons.⁵⁵ Its Los Lunas, New Mexico facility — a 3.8-million-square-foot site — uses approximately 75,000 gallons per day according to local reporting.⁵⁶ Kuna’s scale is closer to Los Lunas than Prineville. What the aquifer impact will be for the Snake River Plain, which already faces a 181,600 acre-foot shortfall for senior surface-water users this year, is not something the present filings disclose.

The Idaho Department of Water Resources has taken the proximate actions its statutory authority permits: the Canyon County moratorium on new groundwater permits, the methodology order on senior surface-water curtailment, the emergency drought declaration itself.³ These are water actions. The electricity actions are at the Commission.

12. The Federal Backdrop

Two federal actions frame the state-level landscape. On July 23, 2025, the White House issued an executive order accelerating federal permitting of data-center infrastructure, streamlining National Environmental Policy Act reviews for facilities exceeding 100 megawatts or $500 million in capital expenditure, and identifying Idaho National Laboratory as a potential federal data-center site.⁵⁷ On March 4, 2026, the White House announced a Ratepayer Protection Pledge signed by Amazon, Google, Meta, Microsoft, OpenAI, Oracle, and xAI, committing the signatory hyperscalers to cover power-delivery infrastructure costs and ensure those expenses do not pass to households.⁵⁸

The March 2026 pledge is voluntary and prospective; Meta is a signatory. The Brisbie Special Contract in Idaho was approved by order in May 2023 — nearly three years before the pledge was made — on terms that remain confidential. A voluntary pledge at the federal level does not retroactively open the sealed exhibits in IPC-E-21-42, and it does not amend Schedule 33 of the Idaho Power tariff. Whether it creates any obligation for prospective contract renewals or amendments is a question the Commission has not publicly addressed.

13. Whose Idaho Is This For?

The structural pieces assembled above do not require bad faith from any individual actor to produce the pattern they produce. A utility operating under a regulated-return model will seek to grow its rate base; that is what the shareholders pay it to do. A commission operating under Idaho’s statutory framework will approve special contracts under the procedures the statute provides; that is what the statute asks it to do. A hyperscale customer will accept contract terms that are favorable and sealed if those terms are on offer; that is how commercial negotiations work. The 2020 sales-tax exemption (HB 562) was passed to attract capital investment; it did attract capital investment. The rate case settlement in IPC-E-25-16 produced percentage increases that were lower than as filed; that is what rate-case settlements are supposed to do.

None of that addresses whose money is paying for the infrastructure, or who is positioned to test the assumptions under which that infrastructure is being planned. Idaho’s in-state electricity generation mix in 2024 was approximately 44% hydroelectric, 31% natural gas, 15% wind, and 9% other sources;⁵⁹ Idaho had the third-lowest average residential electricity price in the country in 2024, after North Dakota and Utah.⁵⁹ That low-price reputation is part of what brought Meta. It is also what is at stake in the architecture that the sealed financial analyses and $40,000 intervenor cap will produce in the next rate cases.

Virginia’s State Corporation Commission spent eleven months reviewing Dominion’s biennial case before issuing a 14-year contract framework with triple-minimum billing. Ohio’s PUCO held a public hearing in Columbus in January 2025 and issued its order in July 2025 after a settlement that included Ohio’s consumer counsel as a signatory. Oregon passed the POWER Act through a bipartisan legislative vote. Georgia’s PSC held unanimous votes in January and December 2025. Texas’s SB 6 moved through two chambers of the Texas Legislature and was signed on June 20, 2025. Each of these processes had, at minimum, a standing institutional party whose job was to test the utility’s numbers.

Idaho does not have that. What Idaho has, procedurally, is the option to ask for it. The sealed exhibits in IPC-E-21-42 can be the subject of a motion to unseal; the $40,000 intervenor cap is a statutory creature, and statutes are amendable; the question of a consumer advocate office has been raised in other states and could be raised here; a formal Commission inquiry into large-load cost allocation would cost very little to open and would produce a record that could inform the next rate case and the next IRP. The political and institutional work of asking those questions is, by structural design, currently unassigned.

The drought declaration is not about the data center. The rate case is not about the data center. The $4 billion capital plan is not about the data center — exactly. Each is about a piece of the architecture Idaho inherited from a smaller, slower-growing moment in its utility history. The architecture is now being asked to carry a load it was not designed for, in a window in which five other state regulators have rewritten their versions of the same architecture to meet the moment. What the Idaho Public Utilities Commission does next, and whose voice is heard when it does, is the question this piece cannot answer. It is the question the structure of the proceeding is, at this writing, structured not to answer automatically.