Bowling Green told to phase in multi‑year electric rate increases and borrow to smooth 2026 spike

Bowling Green’s utilities staff and consultant Trey Shepard laid out a multi‑year electric rate plan they said is designed to align customer charges with rising power‑supply, capital and operating costs while avoiding a sudden rate shock.

Trey Shepard, a consultant with Solvent Associates, told the Bowling Green Utilities Board the city faces multiple cost pressures—higher power‑supply capacity and transmission charges, greater capital needs and rising local O&M costs—that together create the need for new revenues. “You’re required to maintain a 1.1 ratio of coverage. We plan for 1.3,” Shepard said as he described the study’s financial targets.

Why it matters: The study estimates the 2026 revenue requirement at about $74 million while current revenues at existing rates generate roughly $61 million. Shepard and staff said the gap cannot reasonably be closed in a single year without an outsized bill impact. To blunt a projected spike in power‑supply costs in 2026, the presentation proposed using AMP’s rate‑stabilization financing to borrow funds in 2026–27 and repay them from 2028–2031.

What was proposed: Shepard said the plan would borrow about $6.9 million in 2026 and roughly $500,000 in 2027 and pay the funds back over the 2028–2031 period; AMP requires rate‑stabilization borrowing to be repaid within five years and the forecast assumes interest near 4.6 percent. Shepard described the effect on customer rates: “It avoids a 20% immediate rate increase,” reducing first‑year pressure so the system‑average impact is closer to about 7 percent for most customers rather than a one‑time 15–20 percent jump.

Rate design and timing: The board was shown a multi‑year schedule that would target a 7 percent increase in year one for most customers and about 5.5 percent for medium general‑service, large general‑service and large‑power classes, followed by roughly 4 percent annual adjustments in years three through five so classes move together. Shepard said most of the revenue adjustments would be applied to fixed components—customer and demand charges—because cost‑of‑service analysis shows a larger share of the utility’s increasing costs are fixed in nature.

Power supply and sales assumptions: The presentation included a 2027 supply mix that Shepard said is about 44 percent renewable and noted that capacity charges in the PJM market are the single largest upward pressure in the forecast. Staff and Shepard also described a forecast that assumes confirmed growth from a few large general‑service customers—staff cited an Apadan data‑center project as under construction—that would increase sales through 2030 and help close the revenue gap if the projects proceed as expected.

Capital and other borrowing: Staff said the capital plan targets roughly $7 million in annual capital spending after catching up on deferred projects. To spread that cost they proposed financing about $15 million total as three $5 million borrowings in 2027–2029, supplemented by cash reserves.

Tariff changes and solar customers: Shepard reviewed draft tariff edits including lowering the large‑power minimum threshold from 6,500 kVA to 5,000 kVA, consolidating security‑light options, and updating the economic development rider. For customer‑owned generation, the presentation recommended raising the net‑export credit from $0.075/kWh to $0.095/kWh and reducing the facilities charge by 50 percent in the first phase, with the facilities charge phased out in 2027 as fixed charges are increased.

Next steps: Staff and the consultant advised continued monitoring through the budget process and said a final decision on the exact amount to borrow for rate stabilization can be made late in 2026 when fiscal‑year revenues and power‑supply results are clearer.

Board business: At the meeting the board approved the prior meeting’s minutes and later moved to adjourn; there were brief operational reports from division managers on electric rebuilds, tank maintenance and pollution‑control projects.

The consultant and staff emphasized the plan is meant to be monitored and adjusted. Shepard told the board the multi‑year approach aims to spread the burden and give the utility time to match rates to the way costs are incurred.