At a technical conference before the Utah Public Service Commission, Enbridge described a proposed rural expansion to bring natural gas service to Fairfield, southwest of Eagle Mountain, laying out route options, engineering sizing, customer outreach and cost assumptions.

The company said the project design under its preferred Option A would install about 68,783 feet of intermediate‑high‑pressure (IHP) main and about 21,861 feet of service lines to serve what the presenter identified as 87 potential customers. Company representatives said they received 57 survey responses indicating interest in service, with four uncertain and one opposed, but emphasized that ‘‘potential customers’’ are a count of structures identified by field work and not a guarantee of subscription.

Why it matters: The Fairfield proposal is part of the state’s rural expansion program, which is subject to statutory spending limits tied to the company’s distribution natural gas (DNG) revenue. Company testimony showed the program must stay under a rolling 2% revenue‑requirement cap (applied over three years) and a cumulative 5% cap; the presenter gave approximate dollar equivalents during the hearing. Commissioners pressed company staff to clarify terminology and how the caps translate to the project’s dollar impact.

Project details and schedule: Enbridge said the 8‑inch main was deliberately ‘‘sized for growth’’ to carry roughly 330 MCFH under the project assumptions, rather than the minimal 2‑inch line that would barely serve existing homes. The company said the design intent is to avoid near‑term reinvestment and to accommodate decades of residential and light commercial growth; presenters explicitly said the line was not sized for large industrial loads such as data centers or major power generation.

The company outlined a target schedule with design work and construction drawings continuing through March 2026, subject to approval and contracting. It also identified an alternate routing option (Option B) that would extend a high‑pressure line and add a regulator station; the company said capacity differences between options range in its exhibits and that Option A is typically the least costly.

Costs, subscription rates and program economics: Enbridge presented a project cost example that it said yields an average of about $99,000 per potential customer (an $8,000,006.62 illustrative project cost divided by 87 potential customers in the handout shown). Staff noted that projects already constructed under the program have generally landed in the tens of thousands per customer range in favorable cases (company representatives cited ranges such as $50,000–$80,000 per customer for prior communities), while some communities are ‘‘well north’’ of that. Commissioners repeatedly asked how the company balances dollars‑per‑customer, distance from existing service, and community support when prioritizing projects under the program cap.

Company procurement and cost tracking: The presenter explained the contractor procurement and payment workflow, describing a system referred to as ‘‘the core’’ where field quantities (GPS shots, unit counts) feed invoices and project accounting. Typical bidder pools for jobs of this character were estimated at five to eight contractors. Unit rates are recorded by item (linear foot for mains, tonnage for material, square footage for surface restoration) and used to automatically compute invoice amounts inside the core system.

Soil management and regulatory constraints: Company staff described a Fairfield municipal ordinance requiring soil management and disposal procedures because of lead, arsenic and other contaminants in some areas. The company said it has included estimated costs for soil handling in its cost estimate, will perform soil testing and exposure controls for workers, and will follow the city’s code for disposal; it also said testing was not yet complete.

Program rules and developer questions: Commissioners asked whether a private developer who builds within the company’s two‑year customer sign‑up window (the period after mains are installed when customers can request service without separate line‑extension charges) would be treated differently. Company staff said smaller numbers of homes that sign up during the window are accommodated within the project budget, but a large development (an example of 200 homes was discussed) could require budget review, a request for additional program funds, or a developer contribution. Staff told commissioners that policy questions remain and should be further developed and tied to statute.

Customer conversion costs and low‑income assistance: The company noted that ancillary customer costs to convert from propane to natural gas vary widely: some customers need only a conversion kit, while others face appliance replacement or ductwork and have widely differing out‑of‑pocket amounts. Company testimony said the utility does not perform income verification for low‑income conversion assistance; those determinations are managed by state programs (Department of Workforce Services) or local loan programs, which the company said it considers as part of community evaluations.

No formal action taken and requests for additional data: The technical conference concluded with commissioners requesting additional maps and data requests (detailed service‑line maps, clarifications on cost exhibits and prior project outcomes) and an acknowledgment from company staff that some program selection and transparency questions will be discussed further internally and in other dockets or technical conferences. The session closed with no vote.

What remains unresolved: Commissioners flagged several policy issues for future resolution, including clearer public procedures for project selection under the program cap, formal guidance about how developers are treated when a development appears near a program project, and additional detail tying the company’s analysis to the statutory language commissioners asked about (Utah Code citations were discussed during the session).