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Foxtail Flats solar: staff shows daytime surplus, nightly shortfall and three response paths — sell, store, or add dispatchable capacity
Summary
Staff told the Board of Public Utilities that the Foxtail Flats solar plus battery resource will produce more daytime energy than the county needs and create a nighttime shortfall; staff proposed three high‑level response paths — sell the surplus and buy night power, add long‑duration storage, or add dispatchable peaking capacity — and provided annual cost ranges for each approach.
Los Alamos County staff presented an analysis of how the Foxtail Flats solar and storage project is likely to change the county’s supply‑and‑demand profile and outlined three broad options to manage the change: sell excess daytime energy and buy night energy in the market; add long‑duration storage to shift daytime solar to night; or add dispatchable, on‑site peaking units.
Ben Ulbrich and staff showed modeling that combines the county’s current resource pool and projected Foxtail Flats output. Staff said the combined pool’s annual generation (including Foxtail Flats) would be roughly 570,000 MWh versus an average annual load (excluding certain major cyclical loads) of about 490,000 MWh. The presenters summarized the net effect as approximately 160,000 MWh of excess daytime energy and an 83,000 MWh annual shortfall at night.
Options analyzed and high‑level cost ranges
- Market sales/purchases (do nothing else): staff estimated a net annual cost in the range of $44 million to $55 million to buy needed night energy and sell daytime excess under current market dynamics. This approach leaves the county exposed to market price volatility. - Add long‑duration storage (conceptual 200 MWh example): staff estimated net annual cost in a similar band but said long‑duration storage could materially reduce night purchases and better align supply and demand; the county is actively investigating emerging long‑duration technologies but said costs and commercial readiness remain uncertain. - Add dispatchable peaking units (internal combustion reciprocating engines or similar): staff said adding dispatchable capacity would raise annual net costs (presented range $54 million–$65 million) but would increase on‑site resilience and lower reliance on volatile market purchases.
Operational notes and risks
- Curtailment and tax‑credit risk: staff cautioned that if the county curtails solar generation it may still incur costs (for example, lost production tax credits and other contract implications). The presenters noted a market estimate that curtailment exposure could be in the tens of dollars per MWh and used an illustrative figure near $68/MWh for curtailed solar plus foregone tax credits when discussing tradeoffs. - Timing and market complexity: presenters said day‑ahead and hour‑ahead prices vary significantly and that the county’s current modeling stops short of full hourly dispatch fidelity; staff said they are working toward higher resolution models but that immediate contract and market choices would be high level and require close due diligence.
Resilience and strategic partners
Staff noted potential partnerships with Kirtland Air Force Base and Sandia National Laboratories (both pool participants) and said those parties are considering changes in their own supply portfolios that might absorb some daytime volume. The county also is tracking other regional projects, including a hydrogen demonstration project pursued by a neighboring cooperative, and is evaluating whether market or bilateral sales with local large customers could be structured to use daytime energy.
Public comment and board direction
A member of the public and local stakeholders urged the board to press the Department of Energy and National Nuclear Security Administration to account for the Foxtail Flats project as a feasible alternative in federal reviews of transmission projects tied to Los Alamos National Laboratory. Board members and staff discussed monitoring DOE procurement and EDAM/energy‑market developments in 2026–2027 and asked staff to continue seeking longer‑duration storage options and short‑term sales agreements that could bridge the pool while storage technologies mature.
Ending
Staff recommended negotiating flexible short‑term daytime sales agreements (roughly 3–5 years) while aggressively pursuing viable longer‑duration storage technologies; the board asked staff to continue outreach with federal partners and local large customers and to return with more granular hourly modeling and procurement options.
