Utility Capacity Answers That Survive Site Selector Screening

A substation visible from the property line is not available megawatts.

That gap between nearby infrastructure and deliverable capacity eliminates more tier-3 cities from site selection long lists than any incentive shortfall, workforce constraint, or transportation limitation. The 2026 Site Selectors Guild/DCI Pulse Check reported utility and infrastructure capacity as both the top factor affecting location decisions and the top site-elimination factor. It ranked first in both categories outright.

The grid basis for this is specific. NERC's 2025 Long-Term Reliability Assessment documented demand growth outpacing planned supply additions across multiple planning regions. Reserve margins are narrowing in areas that carried comfortable headroom a decade ago. Capacity that utilities once treated as available for the next industrial customer is now contested by data centers, electrification load, and generation retirements outrunning replacements. The supply side has tightened faster than most service territories' public-facing materials acknowledge.

For ED directors in tier-3 markets, the operational problem is narrow. When a site selector calls and asks about power at your industrial site, the quality of your answer determines whether you survive the first screen. Guild data and two decades of site selection practice show the same pattern: most cities eliminated on power are eliminated because they describe what they have in terms no site selector can use.

The framework below structures the answer at whatever level of certainty you actually have. But the framework is only as good as the preparation meeting that populates it. One working session with your utility's economic development or large-load interconnection team, held before any site selector calls. That meeting is the foundational move. Everything else follows from it.

What the Wrong Answer Sounds Like

"We have a substation adjacent to the site."

Zero usable information. That sentence tells a site selector nothing about available megawatts at the delivery point, nothing about voltage and service class, nothing about whether the existing configuration can handle the requested load, nothing about what happens when it can't.

The Site Selectors Guild has stated that communities should prepare line sizes, rate structures, system maps, and site-specific infrastructure data ahead of RFIs. The Guild noted that consultants ask targeted questions based on a client's exact power needs.

The follow-up questions come fast:

• What is the available capacity at the delivery point?
• Has a load study been completed for this site?
• What is the distance for a primary service-line extension, and who pays?
• Is the market regulated or deregulated?
• What is the timeline to energize a 5 MW load? A 20 MW load?

If the ED director goes quiet after the first question, the call is over. The site selector does not conclude the city lacks power. The site selector concludes the city lacks the infrastructure literacy to be a credible partner on a project with an eight-figure power dependency. The next city on the list gets the call.

Four Tiers of Utility Commitment

No ED director answers every power question on the first call. The expectation is not omniscience. The expectation is structure. Each claim bounded by what you actually know. The path from current knowledge to full engineering commitment mapped with realistic steps.

Four tiers. Each represents a different level of utility commitment. Wherever you sit in this progression, you can state it precisely, name the documentation behind it, and describe what triggers the next level.

Tier 1: Screening-Level Capacity Statement

The minimum viable answer. It addresses one question: can the requested load be served at this site within the requested timeframe?

Portland General Electric's large-load study process provides a useful reference. PGE begins with a pre-feasibility review for loads of 1 MW or greater that determines whether a customer load request is possible within the requested timeframe and load amount. No deposit. No engineering study. A screening-level determination.

What you need from your utility to operate at Tier 1:

• Available capacity at the delivery point serving your target site, stated in MW under existing configuration.
• Voltage and service class available (e.g., three-phase 480V wye four-wire).
• The load threshold at which the utility's answer shifts from "yes, under existing configuration" to "requires study."
• A validity period for this information. PGE's load studies expire 60 to 90 days after completion.

The Tier 1 answer to a site selector:

That answer keeps you in the screen.

Tier 2: Study Commitment and Timeline

This tier answers a harder question: given a specific load request at a specific site, what is the technical path to service?

The utility needs project-specific inputs. AEP Ohio's large-load process shows the minimum intake fields: the customer must control the property, provide a specific location, provide a load ramp, and provide final load. Unitil's service requirements add that applicants should provide the largest electrical units, equipment characteristics, total connected load, and estimated peak demand.

You will not have these inputs before a prospect appears. What you can have is the utility's commitment to a study timeline once the inputs arrive.

AEP Ohio states it will make reasonable efforts to complete a load study within 45 days when regional transmission upgrades are not needed, and within 60 days when they are. The Pennsylvania PUC adopted a six-month maximum timeframe for interconnection studies unless exigent circumstances exist. Your utility's timeline will differ. The preparation move is knowing what it is before anyone asks.

The Tier 2 answer:

Tier 3: Upgrade Path, Cost Allocation, and Equipment Reality

Many industrial loads at tier-3 sites will trigger upgrades. That fact alone is not disqualifying. Not knowing the upgrade path is.

PGE's system impact study evaluates the effect of a proposed interconnection on transmission and distribution safety and reliability and identifies preliminary costs for upgrades or modifications. The Pennsylvania PUC model tariff defines "Interconnection Facilities" as those solely benefiting the customer and "Network Improvements" as incremental facilities needed to maintain reliable service to the rest of the grid.

Cost allocation is the critical detail at this tier. Regulators and utilities are converging on a principle: the large-load customer pays for what the large-load customer causes. PGE's framework scales with load size:

• Line extension cost agreement: 1 MW to 30 MW, no substation upgrades, costs under $1 million.
• Minimum load agreement: 1 MW to 30 MW, substation upgrades required or costs over $1 million.
• Large-load customer agreement: Above 30 MW.

The Pennsylvania PUC model tariff requires collateral that fully covers network improvement and interconnection facility costs, reduced and refunded as construction and load-ramp milestones reduce risk to other ratepayers. Utah's large-load statute states plainly that a large-load customer must pay all just and reasonable incremental costs necessary to receive electric service.

Any upgrade-path timeline that ignores equipment procurement is fiction.

The Guild warned communities that very few companies will invest in a location requiring four to five years to get electricity operational. When your upgrade path includes a large power transformer, you are potentially in that window.

Tier 4: Contract Terms and Energization Schedule

The binding tier. PGE describes its study reports as providing "growing levels of commitment to capacity allotment, costs and schedule." Tier 4 is where commitment becomes contractual.

The Pennsylvania PUC model tariff requires a minimum initial contract term of at least five years, set long enough to recover the utility's investment. It sets minimum monthly demand charges at 80% of contracted demand. AEP Ohio's process requires reimbursement of 100% of buildout costs if the customer cancels or delays the project by more than 12 months before the target energization date.

No ED director produces a Tier 4 answer before a prospect exists. Knowing what Tier 4 requires lets you describe the endpoint credibly. The preparation move is understanding your utility's minimum contract term, minimum demand charge structure, and cancellation or delay penalty framework in advance. When a site selector asks what commitment the client needs to make, you should be able to describe the structure without waiting for a contract draft.

Queue Pressure and What It Means for Your Utility Meeting

The tightening of power availability has a specific cause in many service territories. It should inform the conversation you have with your utility before any prospect calls.

By February 2026, AEP Ohio reported that data-center customers had signed binding contracts for 5,642 MW under its new data-center tariff, on top of 12,219 MW in pre-tariff contracts. Total: 17,861 MW of contracted data-center load. AEP Ohio's total peak demand across all customers had historically ranged from about 8,000 MW to 10,500 MW. The contracted data-center load alone exceeded the system's historical peak by a factor of nearly two. AEP Ohio paused new data-center development because of the magnitude of energy and infrastructure requested.

In Virginia, the State Corporation Commission placed large-load customers such as hyperscale data centers into a separate rate class so Dominion Energy could set rates to recover the unique costs of serving them. Minimum contract terms of 14 years for new contracts beginning January 1, 2027. Requirements that large-load customers pay at least 85% of transmission and distribution costs incurred to serve them each month regardless of actual usage.

This matters for tier-3 cities outside these specific territories because the dynamic is not confined to Ohio or Virginia. Data-center load consumes utility engineering bandwidth, substation capacity, and transformer inventory regardless of where you sit. FERC's June 2026 action ordered RTOs and transmission owners to address efficient study processes, cost shifting, and transmission-cost transparency for large loads broadly.

The Meeting That Populates the Framework

Three items on the agenda, one meeting, held before any site selector contacts you.

The utility becomes a deal partner here, not a phone number on a fact sheet. The meeting builds a pre-negotiated information-release protocol. When the call comes, you execute a prepared response at the appropriate tier instead of improvising one.

First: what can be stated publicly in an RFI response. Available capacity at the delivery point, voltage and service class, general study timelines, cost-allocation framework, equipment procurement status for likely load ranges. This is your Tier 1 answer. It needs to be cleared by the utility for public use, with a confirmed-as-of date and a validity period.

Second: what requires an NDA with the prospect. System-specific load data, substation configuration details, queued loads from other customers, grid-security-sensitive information. PGE's process includes explicit limitations: completion of studies does not guarantee the requested load on the requested timeline, because available transmission, project timelines, long-lead items, and other constraints may affect allotment or timing. AEP Ohio notes that its final plan of service is subject to RTO review and approval. Your utility will have similar caveats. Knowing which details require NDA protection lets you tell a site selector "we can provide that under NDA within 48 hours" instead of going quiet while you figure out what you are allowed to share.

Third: what can only come from a project-specific engineering study. Anything at Tier 3 or Tier 4. Identifying this boundary is not an apology. It is a description of the study process, timeline, deposit requirements, and deliverables stated with enough precision that the site selector sees a defined path rather than a black box.

The utility contact receiving this piece should see the meeting as an investment that reduces their own inbound volume of poorly framed requests. When the ED director answers first-screen questions accurately, the utility's engineering team only gets pulled in when a prospect is real and the inputs are ready. Better use of everyone's bandwidth.

Two Starting Points, Same Foundational Move

The framework applies differently depending on your infrastructure position.

Cities with documented substation headroom. Your target sites are served by substations with confirmed available capacity above the load range your target sectors require. Your preparation work is Tier 1 documentation: get the capacity number, voltage, validity period, and study-trigger threshold in writing from the utility. Your competitive advantage is speed. You answer the first-screen question on the call.

Cities whose power situation requires new construction or major upgrades. Your target sites need substation expansion, new feeders, or transmission coordination to serve industrial loads. Your preparation work is Tier 3 mapping: understand the upgrade path, cost-allocation structure, study timeline, and equipment procurement status well enough to describe a credible energization schedule. Your competitive position is weaker on speed but not necessarily disqualifying. PGE's tiered agreement structure shows that utilities have standard frameworks for loads that require investment. The question is whether you can describe yours.

Both positions require the same foundational move: the pre-negotiation meeting with the utility. One city gets a Tier 1 fact sheet. The other gets a Tier 3 process map. Both are answers a site selector can work with.

The answer that eliminates you is the one with no tier at all. "We have a substation adjacent to the site" is a geography claim. Geography without engineering commitment is not a power answer.