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Ask your electric utility to show, in writing, how much data-center load it expects, how likely each project is to arrive, what generation and grid upgrades would serve it, and which customers would pay if the project is delayed or canceled. Then verify the assumptions in your state regulator’s docket and, where applicable, the regional transmission organization or independent system operator.
The most useful conversation is not “Will a data center come here?” It is a documented review of forecasts, reliability studies, cost responsibility, customer protections, flexibility options, and public participation. The examples below draw on questions raised by the Federal Energy Regulatory Commission (FERC), U.S. Department of Energy (DOE), California Energy Commission, Minnesota Public Utilities Commission, Oregon Public Utility Commission, and Illinois Commerce Commission. Their procedures are jurisdiction-specific, not universal rules.
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Start by identifying who can answer each part
Data-center service decisions can involve several entities. Your distribution utility may control the customer agreement and local substations. A state public utility commission or equivalent regulator may approve tariffs, minimum bills, or service agreements. A regional transmission organization (RTO) or independent system operator (ISO) may study bulk-system reliability, capacity, and transmission. FERC regulates interstate transmission and wholesale-market matters, but it does not replace your state commission for every local decision.
Before contacting anyone, record your utility, state regulator, and RTO or ISO. Ask each organization for the docket number, filing schedule, and public document repository. A utility forecast can differ from the regional operator’s forecast because they may use different project lists, timing assumptions, or definitions of “committed” load.
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1. Test the data-center load forecast
A forecast is only as credible as its project list and assumptions. Request figures for both peak demand (usually measured in megawatts) and annual energy (megawatt-hours or gigawatt-hours). A project can have a high peak but a different annual-use profile, and both affect planning.
Ask for multiple time horizons
- What load is expected in the next three years, seven years, and ten years?
- What is the farther-out planning horizon, and how does uncertainty grow over it?
- When will the forecast be updated, and which public filing will contain revisions?
The Minnesota PUC has specifically asked utilities to estimate data-center load growth over three, seven, and ten years. Use those horizons as a starting point, then request the utility’s own planning intervals.
Separate projects by stage and probability
Ask for every proposed facility to be classified by development or contractual stage: inquiry, land or site-control phase, executed service agreement, interconnection application, construction, or another defined milestone. Request the probability assigned to each stage and the method used to calculate it. California’s Energy Commission says its 2024 demand forecast began incorporating data-center projections from utility applications, with utilities helping assess completion likelihood by application stage.
Do not accept a single “pipeline” number without a stage breakdown. A pipeline may contain duplicate applications, projects competing for the same site, or speculative requests that never obtain financing or permits.
Require downside scenarios
Ask the utility to model at least these cases:
- Projects arrive on schedule and at their requested size.
- Projects arrive late or in phases.
- Projects are downsized, consolidated, or canceled.
- Several projects reach operation at the same time, creating a concentrated peak.
- A project takes service but uses less power than its contract allows.
DOE integrated-resource-planning guidance recommends testing whether proposed large loads will materialize and using multiple scenarios. Ask what probability or adoption rate is attached to each case and whether the regional operator uses the same assumptions.
Check for double counting
Ask how the utility reconciles its customer applications with the RTO or ISO forecast and the state energy forecast. A project should not be counted twice because it appears in both a utility queue and a regional planning list. Request a reconciliation table showing the project name or anonymized identifier, expected location, megawatts, in-service date, and which forecast includes it.
2. Examine supply, reserves, and reliability
Large new loads can affect resource adequacy: whether enough dependable capacity is available during stressed conditions. FERC has identified large commercial and industrial loads, slower-than-expected resource interconnection, and transmission development as resource-adequacy concerns.
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Ask what resources will serve the load
- Which existing generators, new generators, storage resources, purchases, or demand-response programs are counted?
- When will each resource be available, and what permits, fuel arrangements, or interconnection milestones remain?
- How much accredited capacity and operating reserve is available after serving the projected data-center load?
- What happens if a planned generator, storage project, or transmission line is delayed?
Request the study’s peak-demand, reserve-margin, and seasonal assumptions. A plan that works in an annual energy balance may still fail during a winter or summer peak if dependable capacity is unavailable.
Review outage and contingency cases
Ask which contingencies were tested: loss of a major generator, transmission line, transformer, fuel supply, or other critical facility. Illinois Commerce Commission questions for large-load proposals emphasize system stress, contingency analysis, local impacts, infrastructure upgrades, load shape, and generation sufficiency.
Request results for the normal case and the most severe studied case. Ask whether the analysis assumes a planned facility is fully operating, partially operating, or able to reduce load during an emergency. If the utility relies on curtailment, ask how quickly it can be activated, who controls it, how long it may last, and what reliability limit applies.
Compare peak, seasonal, and hourly load shape
Two facilities with the same maximum megawatts can have different reliability effects. Ask for hourly or representative seasonal load shapes, including ramp rates and expected overnight use. Clarify whether computing demand, cooling systems, backup generation tests, and maintenance outages are included. Ask whether multiple facilities are assumed to peak simultaneously.
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3. Verify that the wires can deliver the power
Generation may exist somewhere in the region while local equipment remains unable to deliver it. Ask for a map or written description of required transmission, substations, transformers, feeders, and protection-system work.
Request an upgrade schedule
- Which upgrades are required before initial service?
- Which are needed for later phases or the customer’s full contracted capacity?
- What is each project’s design, permitting, procurement, and construction status?
- What interim operating limits apply before all upgrades are complete?
Ask whether the utility has studied thermal overloads, voltage, stability, short-circuit duty, and protection coordination. A local substation upgrade may solve one constraint while a transmission bottleneck remains upstream.
Ask how delays change the plan
Request a schedule-risk table identifying the consequence if each major upgrade is six months, one year, or longer late. The answer should state whether service is delayed, capacity is capped, temporary generation is used, or other customers are exposed to a different operating risk.
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Confirm regional agreement
Ask whether the RTO or ISO reviewed the load timing, deliverability, and contingency assumptions. If the utility’s plan depends on regional capacity or transmission rights, request the corresponding regional study or filing reference.
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Data-center projects can require customer-specific facilities and broader network investments. The central question is which costs are assigned directly to the project and which are recovered from other customers or through regional transmission charges.
Separate the cost categories
| Cost category | Questions to ask |
|---|---|
| Customer-specific connection | Which line extensions, transformers, meters, protection equipment, and substation work are paid by the customer? |
| Network upgrades | Which transmission or distribution improvements benefit multiple customers, and what allocation formula applies? |
| Generation and capacity | Who pays for new resources, reserve requirements, fuel arrangements, or market capacity purchases? |
| Regional charges | Could costs flow through RTO or ISO tariffs, and how are benefits measured? |
| Study and administrative costs | Are interconnection studies, deposits, security, and construction-management costs refundable or recoverable? |
FERC’s transmission-planning framework describes cost allocation based on estimated benefits, with regional methods intended to be roughly commensurate with those benefits. The specific tariff and legal standard depend on the jurisdiction and filing.
Ask about minimum bills and security
Request the proposed minimum demand, minimum energy, or other billing commitment; its duration; and how it changes if the facility expands or contracts. Ask whether the customer must post a deposit, letter of credit, or other security before construction begins.
Oregon’s large-customer policy materials identify minimum-load or billing agreements and stranded-asset avoidance as key issues. Ask what happens if the customer takes less power than forecast, delays operation, or exits before the utility recovers its investment.
Test for cross-subsidy
Ask the regulator to show whether existing residential and small-business customers could pay costs caused by the data center. Minnesota PUC questions focus on preventing cross-subsidy. Request a bill-impact analysis under both the successful-project and canceled-project scenarios.
5. Define protections against delay, cancellation, and underuse
A utility may build facilities before a data center reaches full operation. Ask what contractual protections keep those costs from becoming stranded.
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- What milestones must the customer meet before each construction phase?
- Can the utility suspend work if permits, financing, or equipment orders fall behind?
- What termination charge or exit fee applies if the customer cancels?
- How long does the minimum-payment obligation last?
- Can the customer transfer its service agreement to another operator or site?
- Who owns specialized equipment if the project does not proceed?
Ask for the proposed service agreement or tariff language, not only a summary. Request a redline or public version showing formulas for deposits, minimum bills, escalation, default, and termination.
6. Ask whether flexibility options were genuinely evaluated
Flexible service can reduce the amount of infrastructure needed, but it is not automatically available or risk-free. Ask whether the utility evaluated demand response, interruptible or curtailable service, battery storage, on-site generation, phased energization, or transmission arrangements that vary by operating condition.
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- What load can be reduced, for how long, and with what notice?
- Who dispatches the reduction, and how is performance measured?
- How often can curtailment occur, and are there seasonal or annual limits?
- What backup systems support critical computing and cooling loads?
- What happens if the customer cannot curtail during a grid emergency?
- Does the arrangement reduce reliability requirements or merely shift them?
FERC’s 2026 discussion of large-load proceedings identifies flexible transmission service and large-load arrangements as issues under examination. That discussion does not establish that a particular option is approved or offered by your utility. Ask for the local tariff and reliability conditions.
7. Check state energy and emissions requirements
Supply choices may be constrained by state law, clean-energy targets, carbon-free requirements, emissions rules, or resource-acquisition standards. Ask the utility to identify every requirement used in its preferred plan and explain how compliance is demonstrated.
- Which resources qualify under the state’s clean-energy or carbon-free rules?
- Are fossil resources, storage, imports, or demand response treated differently?
- Does serving the data center alter the timing of planned retirements?
- Are emissions, water use, fuel availability, or local-air permits part of the reliability analysis?
Minnesota planning questions, for example, include compliance with state carbon-free requirements. That is a state-specific consideration; obtain the equivalent requirements for your jurisdiction.
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Ask the utility and regulator where filings, exhibits, service agreements, reliability studies, and public comments are posted. Request a plain-language index if the docket contains confidential and public versions.
Ask what is being withheld
Minnesota’s PUC explains that some details may be treated as trade secret after review, including load estimates, construction estimates, schedules, and customer-specific rates. Ask which legal basis supports each redaction, who reviews the confidentiality claim, and whether a summary or range can be released.
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- INSTALLS IN CIRCUIT PANEL of most homes with clamp-on sensors. Supports Single phase, Single-split phase, and 2-wire systems. 3-wire systems; 3-phase, 4-wire Wye systems with earthed (TN or TT) neutral (no-Delta) are supported with an additional 200A sensor (sold separately).
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Track the decision calendar
- Find the initial utility application and docket number.
- Record deadlines for intervention, written comments, technical conferences, and hearings.
- Subscribe to docket notices or check the commission’s filing system regularly.
- Download public exhibits and compare later revisions with the original forecast.
- Submit focused comments tied to reliability, cost allocation, customer protections, or transparency.
Minnesota’s described process includes utility filing, public notice and comment, and commission review. Other states use different names and deadlines, so follow the local commission’s participation rules.
Use a side-by-side scorecard for competing proposals
If your utility offers more than one tariff, service agreement, or supply plan, compare each on the same dimensions rather than choosing by headline price.
| Dimension | Evidence to compare |
|---|---|
| Forecast confidence | Project stages, probability assumptions, scenario range, and update schedule |
| Delivery timing | Generation, transmission, substation, and distribution milestones |
| Reliability | Peak and seasonal reserves, contingency results, outage procedures, and delay cases |
| Cost assignment | Direct contributions, network allocation, regional charges, and bill impacts |
| Customer protection | Deposits, minimum bills, exit fees, default remedies, and stranded-cost treatment |
| Transparency | Public filings, confidentiality explanations, comment opportunities, and decision dates |
| Operational flexibility | Curtailment, storage, phased service, notice periods, and performance limits |
| Policy compliance | Consistency with state energy, emissions, and resource-planning requirements |
The official materials establish these as relevant review dimensions, but they do not rank a particular proposal without evidence from the local docket.
A ready-to-send question list
- What is the expected data-center load in peak megawatts and annual energy for three, seven, and ten years, and what assumptions support each figure?
- How many projects are included, what stage is each in, and what probability is assigned to completion?
- How are delay, downsizing, cancellation, simultaneous operation, and underuse modeled?
- When will the forecast be revised, and where will the revision be filed?
- What generation, capacity, reserves, storage, imports, and demand response serve the load?
- Which peak, seasonal, outage, and contingency cases were tested?
- What changes if a generator, transmission line, transformer, or substation is late?
- What transmission, substation, distribution, and protection upgrades are required, and who pays?
- Which costs are customer-specific, which are shared, and which may enter regional charges?
- What minimum bills, deposits, security, exit fees, or other protections apply if the project takes less power or leaves?
- What flexibility options were evaluated, and what are their notice, duration, frequency, and reliability limits?
- How does the plan comply with state energy and emissions requirements?
- What documents are public, what has been withheld, and under what legal basis?
- What are the comment deadlines, hearing dates, and final decision milestones?
How to judge the answers
A strong response identifies projects and probabilities instead of presenting one large pipeline number; shows both peak and energy forecasts; publishes delay and cancellation scenarios; ties every major upgrade to a schedule and contingency result; assigns costs with a stated formula; and provides enforceable protection if expected usage does not occur.
Be cautious when an answer relies on “economic development” without a bill-impact analysis, treats an application as a commitment, omits regional transmission constraints, or promises reliability without describing reserve and outage cases. Also distinguish a public summary from the legally binding tariff or service agreement.
Finally, preserve the source and date of every forecast you use. Forecasts, project status, tariffs, and confidentiality decisions can change during a proceeding. The state commission docket and the relevant RTO or ISO record are the authoritative places to check the latest version.
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