Your city was eliminated from a manufacturing prospect. The feedback, relayed through your state partnership, was three words: "insufficient electric capacity."
Your instinct is to call the utility about substation upgrades. Before you do, figure out which of the following actually happened.
The serving utility cannot physically deliver the requested load. The substation is at capacity, the feeder is undersized, and the power does not exist.
Or the utility can deliver the load, but your site profile listed "3,000 kW available, expansion possible" with no service letter, no voltage specification, no study date. The selector read an unsupported claim and moved on.
Or the utility completed an area system study last year that would have answered the question, and your office didn't know it existed. The RFI response window closed while the request sat in a general inbox.
Or the utility can deliver the load, the study exists, and the line extension requires a $1.8M customer contribution with a 10-year take-or-pay commitment and a 16-month energization timeline on a project that needs power in nine.
The first of those requires a capital project measured in years and millions of dollars. The second requires a utility study measured in weeks and thousands. The third is a phone call and a standing protocol. The fourth is a negotiation, and possibly a state co-investment program.
If you treat all four as "insufficient electric capacity" and respond by lobbying for substation funding, you have misdiagnosed three of the four — potentially pursuing infrastructure for 18 to 36 months when the actual fix was documentation you could have had in hand before the RFI arrived.
Scope
This piece classifies a known screening failure into one of four root causes — asset gap, evidence gap, coordination gap, transaction gap — and specifies the remediation path for each. It applies after you have been eliminated and have feedback about why.
It does not cover how to record and aggregate failures over time. It does not evaluate whether your site matches a sector's requirements before you pursue a project; that is the demand envelope's job. It does not grade the quality of a screening answer you have already assembled, which the commitment-rung framework in Issue 3 covers. This piece sits between those tools. You failed a screen, and you need to know what kind of failure it was before you spend money fixing it.
What the data shows and where it stops
The Guild/DCI 2026 survey reports utility and infrastructure capacity as the top elimination factor, cited by 61% of responding selectors. Missouri Partnership's analysis of 192 lost projects over seven years found real estate and site issues as the leading known reason for elimination.
Neither source distinguishes between a city that lacked the physical infrastructure and a city that lacked the documentation of infrastructure it possessed.
No public source I have reviewed measures that split. In Issue 3, I wrote that the cause is almost never a missing asset but a missing rubric. That was editorial inference from two decades of reading RFI responses, and I stand behind the structural logic. Tier-3 cities that receive RFIs have usually passed a geographic and demographic screen, which means the selector already believed the underlying infrastructure could plausibly exist. That belief should shift your diagnosis. If a selector thought you might have the asset, the failure is more likely evidence, coordination, or transaction than physical absence. I cannot give you a percentage. No public data set codes the distinction.
The Guild's own RFI Exchange guidance warns that "missing information on key items may result in elimination." That warning only makes sense if elimination for missing information happens often enough to warn about.
The four-cause taxonomy below is my synthesis of documented practitioner mechanisms. Each mechanism has published support. Naming all four together as a diagnostic sequence is original to this publication.
Asset gap
What it looks like. The physical capability does not exist at the site, and no defined project can create it on the prospect's timeline. The substation has no remaining capacity. The water main terminates two miles from the property. The treatment plant has no industrial pretreatment headroom.
Confirmation test. A dated determination from the serving utility or authority stating the requested capacity cannot be delivered, specifying the constraint (transformer capacity, feeder rating, treatment headroom, pipe diameter), and either declining to provide a delivery path or providing one whose timeline and cost exceed the prospect's parameters.
That test requires the utility's determination, not your staff's assumption. If your team compared the site sheet's "3 MW available" to the prospect's 10 MW requirement and concluded the gap was physical without asking the utility whether 10 MW was deliverable with an upgrade, you have not confirmed an asset gap. You may have an evidence gap.
Remediation. Capital project: substation expansion, main extension, treatment plant upgrade. This is the only cause category that requires building something.
Timeline. 18 to 36 months for most utility capital projects. Longer if transmission-level work or regulatory approvals are involved.
Cost. Six to eight figures. Public co-investment is common through state infrastructure programs, though many carry their own structural constraints. North Carolina's IDF-Utility Account requires private-sector job creation within 24 months, which means you need a prospect pipeline to get the infrastructure that would attract prospects.
Owner. Serving utility, with public co-investment negotiated by the EDO and potentially the state.
Forwardable summary for the utility director: The site cannot meet industrial load requirements at the capacity level specified. We need a formal determination of what upgrade is required, its cost, its timeline, and whether phased delivery is possible. This is a capital planning conversation.
Evidence gap
What it looks like. The physical capability exists, or could exist with a defined upgrade, but your RFI response did not demonstrate it. Your site sheet cited a capacity number without a utility letter. The letter you submitted was six years old. Voltage and configuration were absent. The study predated a recent load addition that changed available headroom.
The Guild's RFI Exchange guidance is specific about the fields it expects: usable-acreage calculations, a timeframe and cost to reach the required MW, current environmental assessments. It flags a Phase I more than 20 years old as a response defect, not a site defect.
Confirmation test. Contact the serving utility and ask whether the requested capacity is deliverable to the site. If the answer is yes, or yes-with-defined-upgrade, and the utility can produce a determination letter, your screening failure was evidence.
Remediation. Obtain the utility's current capacity determination in a format that answers the selector's question. Published utility processes give you a sense of what this costs:
- Snohomish County PUD: $5,000 feasibility review, one to two months, followed by detailed interconnection studies at $10,000 minimum over three to eight months.
- Pedernales Electric Cooperative: $1,500 application fee for a standard 5–25 MW request; non-standard in the same band carries $36,500 in listed fees.
- Portland General Electric: 30-to-45-day feasibility stage followed by serial system-impact and facilities studies published at 150 days, though PGE cautions that complexity and third-party coordination can extend those estimates.
These are study fees. They buy the evidence, not the infrastructure. A $5,000 feasibility study and a $5M substation upgrade sit on opposite sides of the diagnosis, and the study is usually what tells you which side you are on.
Timeline. One to two months for initial feasibility. Four to ten months for a full study sequence. If a current determination already exists and the work is locating and formatting it, the timeline compresses to days.
Owner. EDO initiates the request. Utility executes the study and signs the determination. The Issue 2 teardown of the power-capacity screening question specifies the fields that determination needs to contain: delivery-point MW, voltage and configuration, study state, cost responsibility, energization calendar, signer, and validity period.
Forwardable summary for the utility contact: We need a current capacity determination for [site address] at [requested MW] to respond to industrial prospect inquiries. This is a study request, not a service application. The determination needs to specify deliverable capacity, voltage, required upgrades and their cost, and an energization timeline. We will need permission to include it in RFI responses.
Coordination gap
What it looks like. The evidence exists, or could be produced quickly, but the organizational relationship between your office and the controlling institution failed to deliver it on the response clock. You didn't know the utility completed an area system study last year. Your contact at the water authority retired and nobody updated the file. The RFI asked for wastewater pretreatment limits and your office has no standing relationship with the POTW that controls discharge permits.
The Guild's 2025 infrastructure discussion frames this directly: a community can put itself out of contention if it cannot deliver infrastructure information quickly and transparently. A slow or incomplete infrastructure answer tells the selector two things. One is that your city might lack capacity. The other, more damaging, is that your institutions do not coordinate well enough to execute a project.
Confirmation test. After the deadline passed, were you able to obtain the evidence within days by contacting the right person at the right institution? If yes, the failure was coordination.
Remediation. Standing protocols with every institution that controls a screening answer. The counterparty map from Issue 2 identifies who these are: the serving electric utility, the water authority, the POTW, the permitting jurisdiction, the workforce institution, the rail operator, the environmental authority, and the incentive-granting body. For each, you need a named contact, an agreed response protocol, and pre-authorization to share non-project-specific capacity data.
An agreed protocol means something written down. At minimum:
- A named primary contact and a named backup
- A turnaround commitment for baseline capacity data (five business days is a reasonable ask for non-project-specific information)
- A refresh schedule so the data doesn't go stale between RFIs — quarterly for fast-changing figures like treatment headroom, semiannually for stable ones like feeder ratings
- A defined scope distinguishing what your office can share without a named prospect from what requires the utility or authority to engage directly
A verbal understanding fails the first time your contact retires, transfers, or is on vacation when the RFI arrives. That is the whole reason to write it down.
Timeline. Weeks to establish. Ongoing maintenance thereafter.
Cost. Staff time. Cheapest remediation category by a wide margin.
Owner. EDO, with cooperation from each counterparty.
Forwardable summary for the counterparty (utility director, POTW superintendent, workforce dean): We receive industrial prospect inquiries that require your institution's data on a response clock of 5 to 10 business days. We need a named contact and backup, a written turnaround commitment for baseline capacity data, and standing permission to share that data in prospect responses. We are not asking you to commit capacity to unnamed prospects. We are asking you to help us answer whether a site can plausibly serve a given load quickly enough to stay in the competition.
Transaction gap
What it looks like. The physical capability exists. The evidence exists. The commercial terms, approval requirements, or delivery timeline attached to the service make the site noncompetitive. The utility can deliver 10 MW but requires a $1.8M customer-funded line extension with a 10-year take-or-pay commitment and a 16-month energization timeline, and the prospect needs power in nine months and won't sign past five years. That is three gaps — cost, schedule, contract term — inside one transaction failure, and each may resolve differently. Other versions: the incentive package requires city council approval on a calendar that doesn't align with the prospect's decision timeline; the energization date assumes sequential construction when parallel phasing could compress it.
Area Development's 2026 site-readiness coverage captures the practitioner standard: consultants treat a credible, funded plan to deliver infrastructure on the project's schedule as potentially equivalent to infrastructure already in place. Infrastructure without a workable delivery plan is not a passing answer.
Confirmation test. The utility or authority has confirmed capacity and provided a determination, but the terms — cost allocation, contract structure, approval sequence, timeline — exceed what the prospect will accept or what your community can fund within the decision window.
Remediation. Negotiation. Possible paths: public co-investment to offset the customer contribution (state infrastructure programs, local capital budgets, federal EDA grants); restructured utility terms such as phased delivery, shared cost, or modified contract length; pre-authorized incentive commitments that remove council-calendar delays; temporary service during permanent construction. The incentive authority matrix from Issue 1 maps which commitments staff can make, which require board or council action, and which depend on state-level decisions. Those distinctions determine whether the transaction gap can close on the prospect's clock.
Timeline. Weeks to months, depending on the number of approval bodies involved and whether public co-investment requires its own application cycle.
Cost. Variable. The real cost is the gap between what the utility charges and what the prospect will pay, or between the utility's delivery date and the prospect's need date. In the line-extension example, the $1.8M is the stated cost, but the negotiable number is the public share of a co-investment that brings the customer contribution down to something the prospect will accept.
Owner. EDO leads the negotiation. Utility or authority sets the terms. State programs may provide co-investment.
Forwardable summary for the city manager or finance director: We have a prospect that requires [specific infrastructure service] at [site]. The serving utility can deliver it, but the terms include [specific cost, timeline, or contract requirement] that exceeds what the prospect will accept. We need to identify public co-investment options or negotiate modified terms within [prospect's decision window]. This is a funding and authorization question.
The diagnostic sequence
Work the sequence in order:
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Contact the controlling institution. Can it physically deliver the requested capacity? If not, asset gap. If yes, continue.
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Check the evidence. Did a current, formatted, signable determination from that institution exist at the time of the RFI? If not, evidence gap. If yes, continue.
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Check the handoff. Did your office have access to that determination and transmit it within the response window? If not, coordination gap. If yes, continue.
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Check the terms. Review the cost, timeline, contract structure, and approval requirements attached to the service against what the prospect specified or what a competitive site would offer. If the terms were the barrier, transaction gap.
Each test is cheap. The remediation paths they point to are not, and they span four orders of magnitude. A coordination protocol costs staff time. An evidence study runs from a few thousand dollars to the mid five figures. A transaction negotiation costs tens of thousands to millions in public participation. An asset project costs millions to tens of millions. Misdiagnosing a coordination gap as an asset gap delays the actual fix by years when the real problem was solvable in a month.
The sequence applies to every screening dimension — water pressure and fire flow, wastewater pretreatment capacity, workforce pipeline depth, environmental clearance, rail service, permitting timeline — each with its own controlling institution. It does not reach desktop eliminations where your city was cut before anyone made contact. That is a visibility problem, not a diagnostic one.
- Missouri's lost-project analysis: Missouri Partnership's public review of 192 lost projects over FY2016–FY2023 is the strongest U.S. example of CRM-derived loss analysis, though it does not code failures by root cause in the way this framework proposes.
- FERC's large-load proceedings: On June 18, 2026, FERC directed all six regional grid operators to justify or reform their large-load tariffs — active proceedings that will reshape the cost, timeline, and contract structures driving transaction gaps in power delivery.
- South Dakota's no-bid guidance: South Dakota GOED's public RFI guidance explicitly advises communities not to submit when a critical driver has neither a local answer nor a workable alternative, establishing deliberate non-submission as competent response management.
- Utility study cost variation: Published large-load fees range from $1,500 at Pedernales Electric Cooperative for a standard 5–25 MW request to $36,500 for a non-standard request in the same band, a spread that underscores why evidence-gap remediation costs cannot be generalized from a single utility example.