Hastings Utilities reviews SPP market shifts and budgets studies to shape next-generation plan

Hastings Utilities staff told the board on Oct. 9 that changes in the Southwest Power Pool (SPP) market are reshaping how local public utilities must plan for generation and capacity.

"SPP is a regional transmission organization, an RTO. They're non profit, mandated by FERC, Federal Energy Regulatory Commission to ensure that power is supplied reliably and as affordably as possible on behalf of the ratepayers," said Shane Stone, plant coordinator at Hastings Utilities, describing the market footprint and SPP's role.

Stone outlined several market trends that he said are directly relevant to Hastings: large increases in wind and solar nameplate capacity across the SPP footprint, wide swings in actual wind output, frequent five‑minute intervals with negative prices, and the difference between nameplate and accredited capacity that SPP uses to determine reliability requirements. He said accredited capacity for variable resources is calculated with an expected load‑carrying metric that reduces the firm capacity assigned to wind and solar.

Board members and staff discussed how those dynamics affect conventional generators. Derek (Staff member) said bringing WEC Units 4 and 5 back into service was partly a capacity play: "By having assets like that that are sitting there waiting, now we're getting paid for that," he said, noting Hastings currently has more capacity than it needs but that the fleet is aging.

Staff said SPP has introduced new seasonal capacity accreditation rules — including higher winter requirements tied to fuel assurance and performance‑based accreditation — and that the interconnection queue has shown recent shifts: Stone reported that roughly 10,000 megawatts of proposed wind and 5,000 megawatts of solar previously listed in the SPP queue were removed since August, while thermal proposals have increased.

The board discussed likely local options. Staff listed actions already budgeted for study: evaluating sites for new generation, updating an older natural‑gas conversion study for WEC Unit 1, reviewing potential conversion of Unit 2 (funded by the PPGA budget), and further engineering work on dual‑fuel capability for quick‑start units such as Don Henry. Carl (Finance staff) and Derek said funds are in the current budget to evaluate candidate sites and conversions but did not specify dollar amounts.

Alternatives presented included adding quick‑start natural gas simple‑cycle units or reciprocating engines, solar plus battery storage, continuing to market excess capacity, or participating in longer‑lead options such as small modular reactors if state proposals progress. Staff cautioned that constructing new gas capacity is a multi‑year process; one staff estimate cited in the presentation said a new gas unit could be seven years from decision to operation.

Stone and Derek described increased staff participation in SPP working groups over the past 6–8 months so Hastings can raise questions and comment on capacity and transmission planning even though the utility is not a voting transmission owner within SPP.

The board did not take formal action on a specific procurement or conversion at the Oct. 9 meeting; staff said they will return with study results and recommendations. Derek said the board has flexibility but must make decisions within a multi‑year planning window: "We're within that window to where within the next 2, 3 years, we need to be making a decision on how we want to transition to our next form of generation if we want to continue to be a generating utility," he said.