Logan Council hears options to replace retiring baseload power; solar-plus-storage and natural gas compared

Logan City leaders heard detailed modeling and three policy options March 4 as advisory board members outlined how the city could replace retiring baseload generation and meet upcoming capacity requirements tied to the Western day‑ahead market.

The presentation, led by Tyson Godfrey and Nathaniel Weidler of the city’s power advisory groups, delivered technical background on a new “day‑ahead” market and on the capacity obligations participants must bring to that market. Godfrey said the market “doesn’t want anyone showing up to the potluck without bringing their own dish,” meaning utilities must reserve resources or face penalties or forced purchases.

The presenters sketched three principal approaches: (1) invest in a locally controlled solar array plus battery storage (a 20–30 megawatt solar plant paired with about 4 hours of battery storage was modeled); (2) acquire additional firm generation via a combined‑cycle natural gas subscription (roughly 15 megawatts in the scenarios shown); or (3) rely on market purchases and third‑party capacity contracts while seeking future low‑carbon firm resources such as geothermal or small modular reactors.

Why it matters: Sunnyside and Hunter plants together represent about one‑third of Logan’s current baseload. Both plants have scheduled retirements in the late 2020s and early 2030s; advisers said that loss, combined with the new day‑ahead capacity rules, will create a shortfall unless the city secures replacement capacity.

Key numbers and tradeoffs presented - Modeled local project: 30 MW solar plus a 4‑hour battery (scale used for analysis). Rough upfront cost examples shown: roughly $33 million for the solar array and $25 million for the battery, plus allowances of $6 million for a substation and $2 million for land (presenters cautioned the land cost is a variable). - Modeled levelized cost: a combined solar+storage cost in the analysis averaged about $92 per MWh (the presenters noted this excludes some site‑specific costs and that tax credit treatment could lower costs); the recently negotiated natural‑gas “peaker” cost cited in the presentation ranged roughly $93–$167 per MWh depending on the plant and hours. - Capacity credit differences: combined‑cycle natural gas and other firm thermal generators typically receive very high capacity credit (presenters used ~96% as an example); solar counts for far less under current capacity accounting (roughly ~30% of nameplate in the slides), meaning more solar nameplate is needed to equal the same capacity credit as firm gas. - Short‑term revenue estimate for meeting capacity obligations from third parties: presenters estimated covering the shortfall with third‑party capacity could cost “$3 to $8 million per year,” depending on contract terms.

Presenters’ recommendations and council context Godfrey and Weidler both told the council they favor a proactive strategy that reduces exposure to volatile market purchases. Godfrey argued a local solar‑plus‑storage project places “the biggest challenges within the control of the city” (land, permitting and construction) rather than leaving the city to compete in wider western markets. Weidler emphasized the importance of providing “known rates” to customers and said the council must weigh differing risk tolerances.

They showed scenario modeling that compared: solar+storage only; natural gas only; solar+storage plus a smaller natural gas purchase; and no new capacity (relying on market purchases). The models produced tradeoffs in both total cost and cumulative CO2 emissions over multi‑decade horizons. One example cited: if geothermal or advanced nuclear become widely available within roughly 10–15 years, the long‑term emissions picture would be better for scenarios that delay gas purchases; if they do not materialize, the city faces higher market purchases and greater emissions under a “wait” approach.

Council questions and next steps Councilmembers asked about timing, transmission constraints and whether UAMPS (the university‑municipal purchasing consortium referenced in the presentation) or PacifiCorp transmission rules limit options. Presenters said the day‑ahead market requirement is effectively binding for Logan (PacifiCorp’s transmission area will participate) and that participation deadlines and transmission queue timing create urgency: some transmission studies and queue slots are being finalized in the coming months.

Presenters asked the council for direction on pursuing a local, city‑led solar and battery project into the transmission queue and on whether to pursue a partial gas subscription as an interim hedge; they said a local solar+storage project could come online faster than a large remote plant because it avoids some external transmission dependencies. They also noted energy‑conservation and demand‑response options would still be valuable and should be advanced in parallel.

What the presentation did not decide Council received the briefing and asked questions. No formal council action or contract award on any of the energy options took place at this meeting; presenters said staff will return with more detailed cost estimates, potential financing options, and recommended next steps for council consideration.