Apex says split solar system could speed power and tax-credit benefits for Jones Avenue site

Apex consultant Ian summarized options for the Jones Avenue solar proposal and told the Fort Smith Energy Advisory Committee that a hybrid approach — splitting generation between a front-of-meter system and a behind-the-meter array serving the high school — could deliver the city earlier savings and a better near-term net present value than a single large system. Ian said all three modeled scenarios assumed municipal group or remote net metering credits.

Why it matters: the choice of configuration affects whether the project triggers a transmission‑level affected-system/operator (ASO) study, which Apex estimated would add roughly nine months and $50,000–$80,000 in study and engineering costs. That schedule and cost difference could determine whether the city can qualify for federal Investment Tax Credit (ITC) treatment under current timelines and so materially changes the economics.

Ian described three approaches: a single, front‑of‑meter municipal system; a hybrid split system with a behind‑the‑meter segment at the high school; and a private-developer PPA. He said the private PPA produced the least favorable city value because the developer retains most of the output value and the city would only receive a discounted rate. “All 3 of the models or all 3 of the scenarios did assume the city would use ... group or remote net metering,” Ian said. “With the private PPA approach ... you only get a discount on the rate.”

On the split approach, Ian said the behind‑the‑meter portion would let the high school consume power during daytime peaks and reduce demand charges; however, it requires an additional underground line of roughly one‑third of a mile from the landfill to the high school, which increases up‑front interconnection and construction cost. “That 2nd line, though, is more than offset by getting the ITC,” Ian said, adding that the split approach can move faster and thus make ITC qualification more likely.

A single large system would likely exceed the roughly 1‑megawatt threshold that triggers an ISO New England ASO study. Ian said the team estimated the Jones single‑system design at about 1.7 MW and warned that a triggered ASO study would add a nine‑month schedule delay and tens of thousands in study costs, “and potential transmission upgrades at the substation level.”

On finances, Apex presented modeled annual savings and revenue: energy credit value of roughly $343,000–$364,000 per year and renewable energy certificate (REC) revenue north of $100,000 per year (declining over time). With a modeled municipal borrowing scenario, Ian said the city could be cash‑flow positive from the start after debt service; he summarized a $278,000 annual debt payment and a 20‑year bond term in the model. “From the city's total budget point of view, you would be cash flow positive from day 1,” Ian said.

Committee members pushed for more sensitivity analysis. They asked Apex for NPV comparisons with and without ITC reinstitution, for different net‑metering assumptions and for cash‑flow timelines under alternate borrowing assumptions. Several members asked Apex to supply a formal written report and a deeper set of model permutations in the next deliverable.

The committee also asked staff to explore rooftop alternatives and asked Apex for a scope and RFP template to evaluate rooftop or rooftop‑fleet options across city buildings. Staff (Christine) said Apex is preparing a formal report that will expand the slides.

Next steps: Apex will deliver a written report with the detailed modeling and requested sensitivity runs. Staff will provide the committee updates and an RFP template for rooftop evaluations. The committee will consider those materials before making a formal recommendation to the council.