Screening Question Teardown — "What Is the Available Power Capacity at This Site?"

Cluster Context and City Fit

Any industrial project running a thermal process, a refrigeration load, or an electrification-intensive production line triggers this question. That covers more sectors than most directors assume. EIA's 2022 MECS puts average purchased-electricity loads per establishment at levels that cross formal study thresholds across multiple manufacturing categories. These are continuous-operation averages: annual purchased electricity divided by reporting establishments and 8,760 hours. They are not peak demand. Actual service requirements run higher because peak demand, power factor, and motor-start loads all push the number up.

Sources: MECS Tables 7.6 and 7.8, 2022 data released 2025–2026; Area Development, Q3 2024.

The question becomes a formal screening gate at roughly 1 MW. Portland General Electric triggers its large-load study process at that threshold. More complex cluster-study requirements kick in at 4 MW in PGE's Enhanced Planning Areas. AEP Ohio's data-center tariff process begins at 25 MW. A director targeting light machining or small-footprint assembly may never encounter this as a screening gate. A director targeting food processing, foundry work, primary metals, semiconductor-related manufacturing, or EV supply chain will encounter it on every deal.

Three things define the city that belongs in this conversation: documented substation headroom, a utility willing to state that headroom in writing, and target sectors whose load crosses the threshold. A 70,000-person city with a municipal electric utility, 12 MW of available substation capacity, and a food-processing cluster within 40 miles has a real position. A 150,000-person city served by an IOU that has never produced a public capacity statement for its industrial corridor does not, regardless of what the substation can actually deliver. If nobody has authorized a document that says so, the headroom does not exist in the site selector's evaluation.

The Question

The Typical Answer

This sounds reasonable. It is exactly what a competent director says when they know their city has power but nobody has told them what format the proof must take. The question, though, was never addressed to them.

Why It Fails

The site selector is populating a comparison matrix. Four cities, same columns: available MW at the delivery point, voltage, service configuration, timeline, cost. "Ample capacity" does not fill a cell. "Very responsive" is not a timeline. The city that provided numbers stays in. The city that provided assurances does not.

Site Selectors Guild 2025–2026 survey data ranks utility and infrastructure capacity as the No. 1 site-elimination factor at 61% of responding consultants. A site selector who forwards "ample capacity nearby" to a client's engineering team has forwarded nothing. The engineering team needs a document from the utility, signed by someone at the utility, with numbers the utility will defend. The EDO's verbal assurance has never been that document. The power-constrained environment since 2023 has made the gap less forgivable.

The Passing Answer

The passing answer is the utility's document. Not the EDO's. This is the counterparty problem in its clearest form: the director is answering a question only the utility can answer, in a format only the utility can authorize, on a timeline the utility controls. In issue #1, I organized utility readiness into four tiers from screening-level capacity statement through contract terms. This piece narrows to one question and one document.

Available capacity. MW or kW at the specific delivery point. Substation capacity is a system-level number. Site-level service requires specifying the delivery point, the feeder or circuit, and what load that circuit can accept before triggering upgrades. A substation with 20 MW of headroom may serve a site whose feeder can accept 4 MW without reconductoring. The distinction matters.

Voltage and service configuration. Three-phase service at what voltage. Dual-feed or redundant service availability, and from which sources. For loads at or above 1 MW, PGE requires a large-load study before it will answer construction and design questions, including arc flash studies, metering, conduit and vault requirements, and design timelines. Voltage and configuration are study outputs. They are not assumptions the EDO can state.

Study path completed or required. PGE's process runs four stages: pre-feasibility, feasibility, system impact, facilities study. The size, location, and complexity of the load determine which stages apply. In PGE's Enhanced Planning Areas, all requests of 4 MW and greater require a cluster study rather than serial review. AEP Ohio's data-center tariff process requires property control (ownership, lease, or option), a specific location, a load-ramp schedule, and a final load figure before it will initiate a study. AEP's interconnection requirements form names manufacturing load types explicitly: manufacturing general, car manufacturing, semiconductor plant, food processing, steel mill, aluminum smelter, and others. Every utility has a process. The EDO needs to know where each priority site stands in it.

Deposits and fees. AEP Ohio's load-study fees are payable within 45 days. Miss the window and the request is considered withdrawn.

PGE requires a study agreement and payment before any stage beyond pre-feasibility. Withdrawal from a cluster study after initiation of the system impact phase can trigger a financial penalty. A site selector comparing two cities needs these terms stated up front, not surfaced after the shortlist is set.

Cost responsibility. AEP Ohio's Letter of Agreement requires 100% buildout-cost reimbursement if the project is cancelled or delayed more than 12 months before energization. AEP Ohio's November 7, 2025 load-study letter, sent to 36 applicants who had submitted formal requests totaling 13,023 MW, stated that regional transmission upgrades were required for all 36 projects and that those upgrades became the gating factor for estimated in-service dates. PGE's large-load customer agreements for loads above 30 MW include reservation deposits at signing and exit penalties for distribution.

Load-ramp assumptions. AEP Ohio caps ramp periods at four years with minimum contract-capacity thresholds: 50% in year one, 65% in year two, 80% in year three, 90% in year four. The ramp schedule determines the contract structure.

Energization timeline with contingencies. A good-faith estimate of when power will be available at the requested load, with stated conditions. AEP Ohio's load-study letter emphasized that estimated in-service dates are subject to contingencies, assumptions, system developments, customer decisions, and PJM processes. Every capacity commitment carries conditions. A document that omits them is incomplete. A site selector will treat it accordingly.

Named signer and validity period. PGE's study results expire 60–90 days after completion unless PGE approves an extension. A capacity statement without a validity period is one the site selector cannot rely on. A statement without a named signer is one nobody at the utility has agreed to defend.

Regulatory context. On June 18, 2026, FERC issued show-cause orders to all six regional grid operators directing them to justify or reform rules governing how "data centers, manufacturing facilities, and other large energy users" connect to the grid. The PJM-specific order defines a large load, for purposes of that proceeding, as a new commercial or industrial customer with peak load of 50 MW or greater interconnected at above 69 kV. RTOs have 60 days to respond.

The Tier-3 Translation

The structural advantage is access. In a city of 80,000 served by a municipal utility, the ED director can sit across the table from the utility general manager and negotiate the terms of a capacity letter before any prospect exists. Municipal utilities can treat capital plans as public recruitment tools and pre-authorize capacity statements for priority sites. IOUs file capital plans with state PUCs, not on city project pages. The asymmetry is structural. A director served by a muni who has a signed capacity letter with all fields populated before the RFI arrives has converted access into a documented advantage that a larger city served by an IOU cannot replicate without formal partnership. That partnership, establishing what the utility will state publicly, what requires an NDA, and what is project-specific, should be negotiated annually. Not when the RFI lands.

Who Else Needs This

Send this to your utility director or general manager. The ask is specific: produce a site-specific capacity statement for each priority industrial parcel covering available MW, voltage, service configuration, study path, cost responsibility, energization timeline, and validity period. In IOU territory, ask them to convene the IOU's economic development representative to establish which fields can be stated publicly and which require a project-specific NDA. FERC's June 2026 large-load action means study paths and cost-allocation rules are being actively rewritten. RTOs have 60 days to respond. A capacity statement produced now may need revision within months. That makes getting the first version done now more urgent, not less. The document you need does not exist until someone asks for it.