Rate study shows large capital needs; consultant recommends phased rate changes to rebuild utility reserves

Brigham City's council heard an in‑depth electric utility rate‑study update on March 19 that outlined large planned capital expenditures, reserve shortfalls, and multiple rate‑design options to increase revenue in coming years.

Consultant Dave Berg said staff assumed aggressive sales growth and a mix of new industrial and residential load in the forecast. Major capital projects through 2030 include multiple substation upgrades; the consultant listed three large substations and other capital that together produce a roughly $47 million capital program across the multi‑year forecast. Berg said about $13.9 million of previously issued bond funds remain available for immediate use and that the analysis assumes an additional $15 million of debt issuance in FY 2028 to help fund projects.

Under the study’s baseline (existing rates), the electric fund’s cash reserves would decline from about $8.5 million to roughly $4 million while a 50% of operating‑expenses reserve goal would rise to nearly $17.7 million — creating a projected shortfall of approximately $13.7 million in the planning period. Berg recommended options to close the gap, including an illustrative set of annual increases (4% per year) over a multi‑year period, or a more targeted sequence that raises the residential customer charge toward cost‑based levels (examples shown: raising the monthly customer charge from $10 to levels such as $13.74 or higher while adjusting energy charges to keep overall class increases at a target percentage).

Berg presented four rate scenarios that each produce a roughly 4% increase in residential class revenue but distribute the burden differently (flat across components, doubling the customer charge and lowering energy rates, incremental customer‑charge increases, or leaving energy unchanged and increasing only the customer charge). He noted tradeoffs: raising the customer charge more heavily affects small or low‑use customers on a dollar basis but can better align the monthly fixed cost recovery with cost of service; lowering energy charges in tandem shifts more cost to fixed charges and can produce bill decreases for very large users.

Staff and council discussed which classes would share the revenue increase and how some projects (for example one large substation) may be paid largely by a new major customer or development agreement, while recurring items such as a planned additional line crew would be borne by the whole customer base. Council members asked about low‑income impacts, reserve targets (50% vs lower percentages as the asset base grows), and feasibility of time‑of‑use or residential‑demand billing. Berg said time‑of‑use and residential demand options would require substantial software and meter work and should be considered as a longer‑term transition.

Berg said he would return with a full recommendation showing specific multi‑year rate orders and supporting impacts on operating results and reserves. Council provided preliminary feedback but did not adopt final rate changes at the meeting.