Board reviews electric rate proposal: staff recommends 9% FY26 increase and opt‑out time‑of‑use rollout with demand charge

At the Feb. 5 Board of Public Utilities work session, county staff presented a draft electric rate path that would include a budgeted 9% increase in FY26 and a plan to implement residential time‑of‑use (TOU) rates with an opt‑out feature and a residential demand charge.

Erin (staff) and Karen (utilities administration) led the electric rate design briefing, emphasizing that the county plans to implement TOU and demand components as part of a wider billing‑system upgrade. Erin said the goal was to align billing capability and rate structure, noting the earlier target to have a TOU/demand design ready by March 1, 2026.

Why it matters: electric distribution showed a net operating loss in 2024. Staff reported an unrestricted cash shortfall of about $5.1 million absent a $10 million settlement infusion used to meet reserve targets; the presentation said staff included $250,000 in the FY26 budget for meter and billing software upgrades and also recommended a 9% rate increase to begin July 1, 2025 to restore cash balance and enable electrification planning.

Main features presented

- FY26 increase: staff reiterated the FY26 budget included a roughly 9% overall rate increase that would take effect July 1; staff will bring a final ordinance through the board and council schedule tied to budget hearings. - TOU rollout: the county intends to pursue time‑of‑use billing by coordinating its existing meter vendor (Ferguson) and billing system (Tyler Munis) and using newly released TOU functionality in the existing billing vendor’s product. Staff proposed an opt‑out approach for residential customers (default to TOU, customers may opt out) and suggested raising the monthly service charge to offset opt‑outs and non‑hourly meters. - Demand charge consideration: the rate consultant recommended a residential demand charge (based on a household’s monthly peak kW). Staff and the consultant proposed examples such as an $18 monthly service charge and a demand charge component (illustrative) tied to an average residential peak around 6 kW. Presenters showed sample bills: a 500 kWh residential bill under the proposed increases would rise from about $83.25 to approximately $90.75 (with the proposed 9% increase).

Board questions and policy tradeoffs

Board members probed equity and opt‑in/opt‑out design, roof‑top solar treatment and potential impacts on low‑income households. Erin reported a small informal comparison of LIHEAP‑qualified households with neighbors that found roughly even distribution of higher and lower usage patterns; staff recommended an opt‑out TOU to encourage participation, but board members noted customer communications and optics would be critical.

Karen summarized the financial imperative: the presentation showed the FY24 electric distribution loss (~$1.4 million) and that staff recommended the 9% increase to help restore cash ahead of electrification work and capital needs. She also highlighted equipment cost escalation: sample invoices showed significant price increases for transformers and switchgear compared with 2015–2018 levels.

Process and next steps

Staff intends to present a draft ordinance and the FY26 budget in the board’s Feb. 19 meeting and bring adoption recommendations in March to coordinate council hearings so any new rates could take effect July 1. Staff requested guidance on whether the board wants a demand charge included in the initial implementation or staged later; they noted adding demand will increase implementation complexity and software testing time.

Ending

Board members asked staff to refine customer impact examples, clarify the equity and outreach plan for low‑income customers, and consider phased implementation options (e.g., TOU first, demand later). No board vote on rates or the billing plan was taken at the Feb. 5 work session.