Board hears interim electrification study showing up to about 44 MW additional peak load under high scenario

Los Alamos Board of Public Utilities Chair Gibson heard an interim report on June 4 from consultants Jacob Wells and Elliot Popel on a 30-year electrification forecast and its distribution-grid impacts. The consultants presented three scenarios — high, medium and low — projecting additional total peak load by 2055 ranging from about 13.5 megawatts (low) to roughly 44 megawatts (high), with a middle case near 28 megawatts.

The board was told the study models both vehicle electrification and building electrification together and separates the expected contributions. In the high scenario the consultants attributed roughly 22.4 MW of the increase to electric-vehicle charging and about 33.3 MW to electrified building loads; the mid and low scenarios show smaller contributions (EVs: 18.2 MW and 8.1 MW; buildings: 18.7 MW and 9.9 MW). “The technology that you need to accomplish this is commercially available, widely available, and it is very achievable,” Elliot Popel said, summarizing why the county’s climate goals are feasible but will require grid preparation.

Why this matters: consultants and board members said the county’s primary near-term constraint is substation capacity rather than the longer distribution feeders. The study’s initial power-flow modeling — updated to reflect the upcoming LASS (Los Alamos) substation being energized — showed feeders are relatively lightly loaded today but that substation capacity and service transformers (the equipment that serves small groups of homes) are the parts of the system most likely to need upgrades if electrification proceeds as modeled.

Consultants described key assumptions and timing that drive the forecasts. Scenario inputs include building-efficiency improvements of +20% (high), +10% (medium) and 0% (low); solar and behind-the-meter battery adoption (high case assumes as much as 50% of homes with solar and up to 20% with battery storage in some discussion); and differing EV adoption curves. The study uses a 30% diversity factor for coincident EV charging, and assumes about 80% of EV charging will occur at home. The consultants also modeled charging behavior in three buckets: roughly 30% of drivers plug in and begin charging immediately on arrival, about 40% schedule charging to occur later (often overnight), and the remainder rely on slower level‑1 charging.

On daily timing, the consultants reported winter peak demand shifts: space‑heating loads for electrified homes rise overnight and into the early morning, producing a modeled system peak near 6 a.m. in the high scenario; scheduled EV charging produces a separate peak around 1 a.m. that can coincide with heating loads. Jacob Wells said those differing peaks mean the summed total is not simply a straight addition of EV and building peaks because they occur at different hours.

On specific system impacts and mitigations, consultants said: - Initial power-flow runs show the town-site feeders have spare capacity, and energizing a new substation will reduce feeder loading and outage impact; however, substation transformer capacity is a pinch point for future growth. - Service transformers and secondary conductors (the hardware from the transformer to individual homes) are likely to see the most localized overloads and may need upgrades as vehicles with higher-power chargers become common. The consultant team said they will estimate how many service transformers may need replacement as an output of the final report. - Hosting-capacity mapping is planned to identify how much additional rooftop solar each line section can accept before voltage, equipment loading, or protection limits are exceeded. Consultants said protection settings and two‑way power flow are likely to limit solar hosting capacity on some circuits.

Board members asked about several assumptions, including the reasonableness of 50% rooftop-solar penetration in the high case and whether the study accounts for local garage/parking patterns that affect home charging access. Consultants said the 50% solar figure is an optimistic boundary condition and that newer permitting trends could push solar uptake, but stressed the three-scenario approach is meant to bound possible outcomes. Board members also discussed winter charging behavior and the potential effects of a planned time-of-use rate the county may consider — the consultants said such rates tend to sharply shift charging to the discounted hours and can create “cliffs” in hourly load.

Next steps and timeline: the consultants said they will deliver a full draft to the Department of Utilities and the BPU by July 9, plan to return in person on July 16 for additional discussion, and aim for a middle‑July to end‑of‑July final report delivery. The forthcoming report will include the power‑flow results, hosting‑capacity maps by line segment, planning recommendations (substation/transmission needs, feeder or conductor upgrades, voltage regulation, switchgear and protection updates), and staffing or budgetary implications for the utility.

The presentation and questions took place during the June 4 meeting; board members indicated they want earlier access to draft chapters where possible so they can review assumptions and underlying data in more depth before the July meetings. The consultants said they will provide intermediate chapters for review in mid‑June and follow up with detailed assumptions used in the forecast.

Ending: The consultants told the board the analysis is still in progress and aimed to identify a set of common system improvements that would be required under multiple scenarios; they emphasized substation capacity and service‑level equipment replacement as priorities for planning and budgeting over the coming decades.