PUC hearing examines Black Hills clean‑heat settlement, renewable natural gas and electrification study

The Colorado Public Utilities Commission heard testimony Oct. 27 on Black Hills Colorado Gas’s application for its clean‑heat plan. The company and most settling parties presented a revised settlement that trims the program timeline, preserves energy‑efficiency spending and adds three new elements: a $300,000 stakeholder‑led electrification study, a pilot in the Rocky Ford area coordinated with Black Hills Colorado Electric, and authority to pursue renewable natural gas (RNG) purchases beginning in 2027 with a $700,000 budget.

Why it matters: The hearing probed whether the settlement’s balance of demand‑side measures, limited RNG purchases and further study offers a reasonable path to meet Colorado’s clean‑heat obligations without improper cost shifting. Commissioners and intervenors pressed the company on whether recovered‑methane limits in state guidance constrain RNG eligibility, how the plan’s costs and emissions were modeled, and whether beneficial electrification programs would unfairly shift fixed gas‑system costs to nonparticipating customers.

What the company told the PUC: Black Hills regulatory director Michael Harrington summarized the second settlement and asked the commission to approve it “without modification.” Harrington said the settlement shortens the plan (effectively removing program year 2025 because of hearing delays), preserves core DSM measures (focused on weatherization and envelope work), and adds an electrification study intended to reconcile divergent modeling assumptions among the parties. He said the company and settling parties agreed to reduce an RNG line item originally budgeted at a higher amount and to replace it with an electrification research allocation.

On RNG, senior manager Maria Garduna told the Commission the company initially used a conservative placeholder price for recovered‑methane credits (roughly $1,206 per metric ton CO2e) based on early RFI responses. After a developer supplied supplemental, protocol‑level calculations, the company modeled a lower abatement cost ($392/metric ton CO2e) and included a $700,000 annual budget for RNG beginning in 2027 in the settlement. Garduna cautioned that the strict Colorado recovered‑methane protocols (and the requirement that qualifying RNG projects be located in Colorado and certified under CDPHE protocols) limit near‑term in‑state supply because some developers can obtain higher value for the same gas in other federal or state markets.

On electrification: The settlement requires the company to fund a $300,000 neutral, third‑party electrification study and to convene a technical stakeholder working group; company witnesses said the intent is to agree the inputs (participation, cost, efficiency, emission accounting) before modeling future plans. Company modeling witness Andrew Cottrell testified that two hypothetical beneficial‑electrification scenarios (a full‑switch scenario and a hybrid scenario that retains a gas backup) were modeled at materially higher abatement cost than the DSM options: roughly $308/ton CO2e (full switch) and $582/ton (hybrid) in the company’s supplemental work. Cottrell said both electrification pathways were not cost‑effective under the company’s modeling assumptions.

On DSM: Witnesses explained the settlement would use DSM as a core, cost‑effective resource but would not include every theoretically available DSM measure. Cottrell described a three‑tier DSM supply curve (tier 1 = lowest cost/achievable potential; tier 2 = economic potential; tier 3 = technical potential that may require higher incentives) and said the settlement funds prioritize the lowest‑cost, highest‑certainty DSM measures. Parties disputed how much additional DSM funding would increase uptake, whether higher incentives would move harder‑to‑reach customers, and how rebates should be conditioned on replacing less‑efficient gas equipment.

On emissions accounting: Counsel and witnesses debated the recovered‑methane cap and how to measure net emission reductions when customers electrify. Garduna and staff discussed how CDPHE’s verification workbook calculates allowable recovered methane and explained the company’s workbook (filed in the record) shows the settlement is within the PUC rules as the company interprets them; opposing parties urged a stricter reading of the limit.

Other testimony and operational items: Operations witness Christopher Downey described a proposed advanced mobile leak detection (AMLD) deployment (equipment, O&M and incremental repair costs). GTI witness Dan Lafebvre (who sponsored a GTI report filed in the case) said the GTI analysis was technical and not a policy recommendation. Sweep and other intervenors cross‑examined company witnesses on survey wording, customer preferences, forecast assumptions and whether a portion of the plan could leave remaining gas customers bearing higher fixed costs if many customers electrified and left the system.

What the settlement would do (if approved): - Keep a core DSM program focused on weatherization and envelope measures; - Authorize the company to spend up to $300,000 on a public, stakeholder‑based electrification study; - Authorize limited RNG procurement beginning in 2027 (company modeled $392/metric ton abatement cost for that procurement and a $700,000 2027 budget); - Fund a Rocky Ford pilot coordinated with the electric affiliate and the Colorado Energy Office (company testimony describes coordination on rebate administration; the pilot’s federal incentive funding had not been finalized at hearing).

What’s next: The hearing record remained open for additional exhibits and the parties asked the company to file confidential RFI details (developer price data) as a late exhibit. The Commission had not voted on the settlement during the Oct. 27 hearing; commissioners continued questioning witnesses and signaled they would consider the record and applicable law before issuing a decision.

Reporting note: Article quotes are from participants on the record. Witnesses and counsel named in this story are listed in the meeting record and were present at the Oct. 27, 2025 hearing of the Colorado Public Utilities Commission.