Electric utility proposes updated line extension rules and a 0.82¢/kWh energy rate rider for very‑large customers

Georgetown Electric Utility staff briefed the council on annual updates to electric line‑extension and meter‑connect policies and proposed a new energy rate rider to manage power‑supply costs from very‑large customers.

Daniel (Georgetown Electric Utility) summarized technical updates to the line‑extension model — including annual labor and material updates, a 5% contingency factor, and a $0 inflation factor for now — and proposed stricter accounts‑receivable controls and larger application fees to recover upfront engineering costs. He said staff will continue to allow adjustments under 5% admin changes without returning to council but will return to the council for any per‑dwelling cost changes greater than 5%.

Why it matters: Georgetown is seeing interest from large commercial and industrial customers whose power use can reach tens of megawatts. That growth affects how the utility procures wholesale power in ERCOT, allocates fixed costs and manages financial risk; the proposed changes aim to assign costs more directly to the customers that drive them.

Daniel described changes to the plant‑investment fee where staff now shows the fee as a separate line item; he said the city’s five‑year projected annual capacity spend rose from roughly $4 million to $12.5 million, which drove a per‑kW plant investment fee increase from $154 to $326 in staff calculations. He said single‑family and multifamily baseline figures remain near those used in 2024 but that the plant investment component per unit rose modestly (staff examples cited increases of roughly $200 for single‑family and about $129 for multifamily, per unit, based on the projected capital spend).

On very‑large loads (those with installed capacity of 10 MW or more), staff presented consultant NewGen Strategies’ recommendation for an energy rate rider to recover the incremental net cost of power‑supply hedges dedicated to serving these customers. Scott Burnham (NewGen) described a proposed formula that would be reviewed quarterly using two months historic plus six months forward projections; using current forward market assumptions the consultants estimated an initial rider of about 0.82¢ per kWh. Revenues from the rider would be deposited into a dedicated over/under account with a proposed cap of roughly $500,000 and a floor of −$500,000; staff would adjust the rider quarterly to maintain the reserve band.

Scott said the rider would sit on top of the city’s existing energy charge (about 5.317¢/kWh) and the PCA and would be structured so hedging costs attributable to these large customers are recovered from those customers rather than allocated across all rate classes. He said the intent is to give customers price certainty, reduce administrative burden from binding long‑term energy forecasts and protect the rest of the rate base from volatile wholesale settlements.

Council members asked technical questions about hedging, demand ratchets and operational controls during scarcity. Staff said the city will monitor materials and tariffs closely, would use the Energy Risk Management program to hedge, and would incorporate minimum‑demand ratchet language with limited first‑year flexibility in the electric‑service agreement so customers can ramp up performance without locking an unnecessarily high ratchet.

What’s next: staff said the utility presented the changes to the Internal Risk Management Committee and the Electric Advisory Board, and would return to council with ordinance language for first reading and implementation; the consultants and staff proposed implementing the rider for bills rendered in June if council approves.

Ending: Council members emphasized the need for strong receivables controls, transparency around fees and the importance of demand‑response options; staff said the proposal aims to balance operational flexibility for large customers with risk protection for other ratepayers.