[{"_1":2,"_111":-5,"_112":-5},"loaderData",{"_3":4,"_26":27},"root",{"_5":6,"_17":10,"_18":19,"_20":21,"_22":10,"_23":-5,"_24":-5,"_25":10},"user",{"_7":8,"_9":10,"_11":10,"_12":-5,"_13":-5,"_14":15,"_16":-5},"roles",[],"isAuthenticated",false,"isPremium","planName","subscriptionStatus","featureFlags",{},"insightsBudget","isDevelopmentHost","userPreferences",{},"recaptchaSiteKey","6LcvOJcUAAAAAHsB-gPGfGktcRlKpH7OTIU_dMTD","isImpersonating","impersonation","affiliateStatus","isFreedomPortal","routes/v2/article/layout",{"_28":29,"_30":31},"notFound",true,"relatedArticles",[32,76,87,99],{"_33":34,"_35":36,"_37":38,"_39":40,"_41":42,"_43":44,"_45":46,"_47":48,"_49":50,"_51":52,"_53":54,"_55":56,"_57":58,"_59":60,"_61":62,"_63":64,"_65":66,"_67":68,"_69":70,"_71":72,"_73":74,"_75":74},"mediaId",6688968,"mediaKeyId","2237704-01d72a459eb1ca0b7921b2d37a1e9b53","parentId",2237704,"title","Board reviews electric rate proposal: staff recommends 9% FY26 increase and opt‑out time‑of‑use rollout with demand charge","audioSeconds",2171,"startMs",4490000,"endMs",6661000,"viewUrl","/Search/View?dp=1&key=2237704-01d72a459eb1ca0b7921b2d37a1e9b53&start=4490&end=6661","thumbnailUrl","https://assets.pipeline.soar.com/2237704-01d72a459eb1ca0b7921b2d37a1e9b53/thumbnail_4490000.jpg","articleUrl","/articles/6688968/New-Mexico/Board-reviews-electric-rate-proposal-staff-recommends-9-FY26-increase-and-optout-timeofuse-rollout-with-demand-charge","mediaUrl","https://secure.pipeline.soar.com/6688968-cd402811474362676f30658d3a13af74/orig.mp4?Expires=1771178767&Signature=BSKV6lm9zmaLfCx2Jp7oBMmrsAfv15DaVOmK0BEGFll82fJwDHcelw5hFAu70cl7-wuGb~hu7JxucGEH8DMmztP1mCjRsqFerY-~G39PKp6JsAMeQsc00wpsKhiCrE5FVNRfgYYdurrgqf1XNH~ahaqA4A4bvVYwyFcU~PJD0XTH1IM~8CWO1ghMjEaizNb~f~vBWoiY9xAr0xjvxgzOv1mj2-E55zsfnXsFnmVZyopqANZI2XjN8wPI4DtUkgBXCSTyebTa289ZiOPhUN-ti~4x5k7K9HxwH5Xuiw66PyMCb5rlEmIOwd8BftjuJ7RBUndR8eUktDP3ZvZM~ZiTzw__&Key-Pair-Id=KUT5TJCACFTXG","author","Los Alamos County","date","2025-02-05T00:00:00Z","article","At the Feb. 5 Board of Public Utilities work session, county staff presented a draft electric rate path that would include a budgeted 9% increase in FY26 and a plan to implement residential time‑of‑use (TOU) rates with an opt‑out feature and a residential demand charge.

Erin (staff) and Karen (utilities administration) led the electric rate design briefing, emphasizing that the county plans to implement TOU and demand components as part of a wider billing‑system upgrade. Erin said the goal was to align billing capability and rate structure, noting the earlier target to have a TOU/demand design ready by March 1, 2026.

Why it matters: electric distribution showed a net operating loss in 2024. Staff reported an unrestricted cash shortfall of about $5.1 million absent a $10 million settlement infusion used to meet reserve targets; the presentation said staff included $250,000 in the FY26 budget for meter and billing software upgrades and also recommended a 9% rate increase to begin July 1, 2025 to restore cash balance and enable electrification planning.

Main features presented

- FY26 increase: staff reiterated the FY26 budget included a roughly 9% overall rate increase that would take effect July 1; staff will bring a final ordinance through the board and council schedule tied to budget hearings.
- TOU rollout: the county intends to pursue time‑of‑use billing by coordinating its existing meter vendor (Ferguson) and billing system (Tyler Munis) and using newly released TOU functionality in the existing billing vendor’s product. Staff proposed an opt‑out approach for residential customers (default to TOU, customers may opt out) and suggested raising the monthly service charge to offset opt‑outs and non‑hourly meters.
- Demand charge consideration: the rate consultant recommended a residential demand charge (based on a household’s monthly peak kW). Staff and the consultant proposed examples such as an $18 monthly service charge and a demand charge component (illustrative) tied to an average residential peak around 6 kW. Presenters showed sample bills: a 500 kWh residential bill under the proposed increases would rise from about $83.25 to approximately $90.75 (with the proposed 9% increase).

Board questions and policy tradeoffs

Board members probed equity and opt‑in/opt‑out design, roof‑top solar treatment and potential impacts on low‑income households. Erin reported a small informal comparison of LIHEAP‑qualified households with neighbors that found roughly even distribution of higher and lower usage patterns; staff recommended an opt‑out TOU to encourage participation, but board members noted customer communications and optics would be critical.

Karen summarized the financial imperative: the presentation showed the FY24 electric distribution loss (~$1.4 million) and that staff recommended the 9% increase to help restore cash ahead of electrification work and capital needs. She also highlighted equipment cost escalation: sample invoices showed significant price increases for transformers and switchgear compared with 2015–2018 levels.

Process and next steps

Staff intends to present a draft ordinance and the FY26 budget in the board’s Feb. 19 meeting and bring adoption recommendations in March to coordinate council hearings so any new rates could take effect July 1. Staff requested guidance on whether the board wants a demand charge included in the initial implementation or staged later; they noted adding demand will increase implementation complexity and software testing time.

Ending

Board members asked staff to refine customer impact examples, clarify the equity and outreach plan for low‑income customers, and consider phased implementation options (e.g., TOU first, demand later). No board vote on rates or the billing plan was taken at the Feb. 5 work session.","mediaType","Video","parentTitle","Los Alamos County - Board of Public Utilities Work Session on 2025-02-05 5:30 PM - Feb 05, 2025","oneSentenceSummary","County utilities staff briefed the Board of Public Utilities on Feb. 5 about a rate redesign that includes a budgeted 9% FY26 rate increase, a planned rollout of a residential time‑of‑use rate (opt‑out), and a residential demand charge option tied to a billing‑system upgrade.","taxTitle","Los Alamos, New Mexico","taxId",51137,"location","New Mexico","headline","","shortSummary",{"_33":77,"_35":36,"_37":38,"_39":78,"_41":79,"_43":80,"_45":44,"_47":81,"_49":82,"_51":83,"_53":84,"_55":56,"_57":58,"_59":85,"_61":62,"_63":64,"_65":86,"_67":68,"_69":70,"_71":72,"_73":74,"_75":74},6688973,"Board hears NMEA prepaid natural-gas refinancing plan; experts outline discounts and contractual limits",4079,411000,"/Search/View?dp=1&key=2237704-01d72a459eb1ca0b7921b2d37a1e9b53&start=411&end=4490","https://assets.pipeline.soar.com/2237704-01d72a459eb1ca0b7921b2d37a1e9b53/thumbnail_411000.jpg","/articles/6688973/New-Mexico/Board-hears-NMEA-prepaid-natural-gas-refinancing-plan-experts-outline-discounts-and-contractual-limits","https://secure.pipeline.soar.com/6688973-4066e81606945a8df83aab86b61753d2/orig.mp4?Expires=1771178767&Signature=ET~tAnV3t7m8SIwp3M8LpGb~ktz7qS93R5NG-psrvJr8IL6IiomUAPp3FqqjWDnnatPsauJLum9gTbReQi~RDx95-LYHrJ~6CH6pIYu2ZT1EtN7UfAg9mV2hwzjWjwQo7GsFTWiiApPgiqaQcObEl8WTPxnzpkzrXMCOyI0ucn9H-QQs~p683lL6llqGENRPOkR-6~4kaEh75-8fTAtcSq1Z3nJfd4kDowRJ4JCsjQIGYfPnzOylow-r4IJAwaVW5Wto0hIVqSw0Omn6shZxt1fz0-09Aoomkz0eMG7h1S8HAyF9H1rNp6r~QwJk2tXjkquNaY-nh-1ywZRDS3JuHw__&Key-Pair-Id=KUT5TJCACFTXG","Chair Gibson opened a follow-up presentation on a proposed New Mexico Municipal Energy Acquisition Authority (NMEA) prepaid natural-gas refinancing at the Board of Public Utilities work session on Feb. 5.

The board heard from Ben Ulbrich, the county’s deputy utility manager for power supply, and George Majors, financial advisor to NMEA, who said the 2025 remarketing under discussion would be a refunding of the 2019 transaction. Majors and representatives from Royal Bank of Canada (RBC) explained how the financial mechanics of a prepaid transaction generate a discount available to participating members.

Majors and RBC described the transaction as an arbitrage driven by the spread between tax‑exempt municipal rates and the taxable reinvestment rate institutions pay. Jim Loszde of RBC told the board, “we’re not locking in a fixed cost of gas for the next 5 years,” and emphasized that the structure yields a discount off an index price rather than a fixed gas price.

Why it matters: prepaid transactions have been used for gas and power since the mid‑2000s and are explicitly addressed in federal law, the presenters said. If market conditions in early March produce a large spread between municipal and taxable rates, those conditions would produce a larger discount for NMEA participants than in the prior remarketings.

Key contractual and program details

- The RBC team and Majors said the expected mechanics: NMEA would issue intermediate‑term tax‑exempt bonds (roughly five years), prepay proceeds to a bank counterparty, and the counterparty would in turn discount cash flows and pass value back to participants as a per‑unit discount on index gas purchases.
- Jason (RBC) and Ben Ulbrich explained that Los Alamos’s index premiums for the April 2025 through September 2030 reset period are expected to be 15¢ per MMBtu and that those premiums would be covered by the transaction structure.
- Majors described a 2019 repricing agreement that created a contractual “minimum discount” test for participants if the transaction were remarketed. He and Jason said that the 2019 repricing agreement set a minimum discount threshold referenced during the presentation as 33¢ per MMBtu; participants would have an option not to proceed if the available discount at pricing were below that threshold. Majors summarized the practical effect: participants have an opt‑out if the market discount is below the negotiated floor.

Board concerns and clarifications

Board members asked about the magnitude of savings and operational obligations. Ben Ulbrich and the RBC panel presented a simple illustrative table showing how the prepayment creates an annual dollar stream that divided by delivered units yields a per‑unit discount. Board member Matt asked whether prior transactions’ savings equate to the figures in the attachment; staff cautioned that earlier transactions used differing structures (some had variable components) and that the illustrative numbers are conceptual rather than a guaranteed future result.

On operational commitments, Majors stated bluntly: “You’re never obligated to take gas you don’t need, ever.” He explained that if Los Alamos reduces its physical demand faster than expected, the contract suite includes mechanisms to remarket unneeded volumes; that remarketing can be done by the county or by RBC under the contract provisions.

Potential savings and risks presented

- Presenters showed past, fixed discounts for earlier transactions (for example, 20¢ in 2009, about 28.9¢ in 2014 and about 29.5¢ in 2019 under the structures used then) and discussed how current rate spreads could produce materially higher discounts in 2025.
- Consultants and RBC warned that the ultimate discount will depend on market conditions at the time of pricing; the board would only know real numbers when the transaction is marketed in March.
- The presenters noted tradeoffs: participating volumes cannot be simultaneously committed to an identical physical fixed‑price contract elsewhere. However, Los Alamos can still use financial hedges (NYMEX futures or swaps) to lock budgets while participating in the prepaid structure.

Next steps and timing

Staff told the board they expect to bring a resolution to the regular Board meeting in two weeks and then seek council approval so the county could participate in a March remarketing if the board sets acceptable parameters (for example, a minimum discount or delegated authority to execute if pricing meets a threshold).

Ending

Board members expressed interest but asked staff to return with more detailed, pricing‑dependent numbers as March pricing crystallizes. No formal board action on the transaction was taken at the Feb. 5 session.","Chair Gibson opened a follow-up presentation on a proposed New Mexico Municipal Energy Acquisition Authority (NMEA) prepaid natural-gas refinancing on Feb. 5, when county staff and financial advisers briefed the Board of Public Utilities on the structure, likely discounts and the operational limits of participating in a remarketing planned for March.",{"_33":88,"_35":36,"_37":38,"_39":89,"_41":90,"_43":91,"_45":92,"_47":93,"_49":94,"_51":95,"_53":96,"_55":56,"_57":58,"_59":97,"_61":62,"_63":64,"_65":98,"_67":68,"_69":70,"_71":72,"_73":74,"_75":74},6688963,"Foxtail Flats solar: staff shows daytime surplus, nightly shortfall and three response paths — sell, store, or add dispatchable capacity",1725,9893000,11618000,"/Search/View?dp=1&key=2237704-01d72a459eb1ca0b7921b2d37a1e9b53&start=9893&end=11618","https://assets.pipeline.soar.com/2237704-01d72a459eb1ca0b7921b2d37a1e9b53/thumbnail_9893000.jpg","/articles/6688963/New-Mexico/Foxtail-Flats-solar-staff-shows-daytime-surplus-nightly-shortfall-and-three-response-paths-sell-store-or-add-dispatchable-capacity","https://secure.pipeline.soar.com/6688963-bafae5c94b3b114e0284b40c07ce0875/orig.mp4?Expires=1771178767&Signature=ToJzRzbsDOpjWYmQy7W6bN43bFANcDei5n1HIP8PwRTFAf9B8jACO~J-rLjhbaS-CT88ljWpJ-o~v2-wdpvr0jO64UsfjIHNdIuEuRDOZrQ~ezxLKvlTu4p8ciuTzkRzAk4rlBrH-p1aUIlTmokFkC7LrkeBK5jC~bdHfgQLCejfGvqgK4h3NFvf6EPdgd13IsMzTqPVYUHzBI-nXRDj3pA0r2oTiCfhTjddpfIhD0ayQHz44liQTbJFsny0-IfS~UAB3upF38XmVpnVVJgfynrSgW3Jquq5DnqwlWWqirgnoPScmCQh0tpr-7GYqfQcH7B8J5qml82HYChbIxj9uQ__&Key-Pair-Id=KUT5TJCACFTXG","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.","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.",{"_33":100,"_35":36,"_37":38,"_39":101,"_41":102,"_43":103,"_45":104,"_47":105,"_49":106,"_51":107,"_53":108,"_55":56,"_57":58,"_59":109,"_61":62,"_63":64,"_65":110,"_67":68,"_69":70,"_71":72,"_73":74,"_75":74},6688958,"Draft ECA not yet available; staff weighing short extension or closed review options",334,12678000,13012000,"/Search/View?dp=1&key=2237704-01d72a459eb1ca0b7921b2d37a1e9b53&start=12678&end=13012","https://assets.pipeline.soar.com/2237704-01d72a459eb1ca0b7921b2d37a1e9b53/thumbnail_12678000.jpg","/articles/6688958/New-Mexico/Draft-ECA-not-yet-available-staff-weighing-short-extension-or-closed-review-options","https://secure.pipeline.soar.com/6688958-fa484f0f9e93bcc98abb49d508f8dc33/orig.mp4?Expires=1771178767&Signature=ECCxmR530oxSff8lfnexU8HofBWX-P2MmgEdBQ6nqa4mRHTkztjdk38UCNDZR3R55bWG3zj1AEA7iP55Q3iEBRhk9LmWWP6q79AEXspuOVurFRyRu-jbiqVkefm97BYJCItDhbJ5reJDbGYFWuLC-pBtzjonTKthgPa07SGFACV1Dkxg~eTvAqwc3d6VerNVElGrOXaxT4zZuazQ~4jgCxxbXUk6~1szNDfo7EKn~JdVWtK-1n01w4RhyGzNiGbVKThRw0xGI6jXGRclRFqovGJAQWHFAaEvBox98PQ1ufytZ7CN72wkKpP0G52Sgmcy20cNI18ewVa4nx1bnKbtIw__&Key-Pair-Id=KUT5TJCACFTXG","At the Feb. 5 work session the board was updated on the status of the draft Electrical Coordination Agreement (ECA) with federal partners.

County staff told the board they had expected a draft from the Department of Energy (DOE) by the end of January but the document had not arrived. Staff said they were investigating two practical options: (1) request a six‑month extension along the lines of prior short extensions to preserve continuity while DOE completes work; or (2) arrange for a restricted review process in which a small, designated subcommittee of board members and counsel would review a commercially sensitive draft under confidentiality rules.

Why it matters: the current ECA governs how certain power arrangements are scheduled and procured between the county and federal entities. Staff cautioned that uncertainty about the new ECA’s timing presents operational and procurement risk for power purchases and cooperative planning.

Staff notes and next steps

- Procurement manager Matthew Barela had earlier signaled staff expected a draft in late January; staff have not confirmed a new delivery date.
- Staff will discuss the two options with DOE and the county attorney’s office; staff said one practical path would be a simple short amendment to the current agreement (an example form of a six‑month modification was distributed) while the DOE process continued.
- Board members discussed the possibility of a longer continuity period if DOE timing required it; one board member stated a preference for a multi‑year option, but staff described a near‑term six‑month extension as the likely short‑term path while continuing negotiations.

Ending

Staff will report back with a recommended procedural path (extension request or confidential subcommittee review) and any proposed amendment language; no formal board action was taken on Feb. 5.","County staff told the Board of Public Utilities that the Department of Energy had not delivered a promised draft of the replacement electrical coordination agreement (ECA) and that staff are exploring options — including a six‑month extension or a restricted subcommittee review — to avoid an abrupt lapse in the county’s power agreement.","actionData","errors"]

Article not found

Board reviews electric rate proposal: staff recommends 9% FY26 increase and opt‑out time‑of‑use rollout with demand charge

Board hears NMEA prepaid natural-gas refinancing plan; experts outline discounts and contractual limits

Foxtail Flats solar: staff shows daytime surplus, nightly shortfall and three response paths — sell, store, or add dispatchable capacity

Draft ECA not yet available; staff weighing short extension or closed review options