Utah PSC hears Rocky Mountain Power seek roughly $431.6 million final EBA recovery; regulator and intervenors propose major disallowances

Rocky Mountain Power asked the Utah Public Service Commission to approve final recovery of its 2023 energy balancing account, seeking roughly $431.6 million in Utah-allocated net power cost after the Commission’s interim-rate adjustments.

The request was presented during a multi‑day evidentiary hearing on docket 24‑035‑1. Jack Painter, the company’s net power cost advisor, summarized the company’s filing and the adjustments that remain in dispute. “The company filed its annual EBA application on May 1, 2024 for the deferral period of January 2023 through December 2023,” Painter said in his sworn summary, noting an original request of about $455,000,000 and a revised recovery level the company now seeks of $431,600,000.

Why it matters: The EBA lets Rocky Mountain Power pass through most net power costs between rate cases. Large EBA balances affect customer charges and prompt scrutiny from state regulators and intervenors when market prices, generation outages, or accounting changes drive sharp swings.

What the company told the commission - Painter and other company witnesses said the 2023 balance reflects multiple drivers: reduced coal generation due to fuel and supply issues, lower hydro and wind production, higher wholesale prices, and a change in interim‑rates carrying charge treatment. Painter described the company’s remaining contested items as: a $600,000 (including interest) prior‑period replacement‑power entry tied to thermal outages; $19,400,000 (including interest) related to Washington Climate Commitment Act compliance costs for the Chehalis facility; $72,300,000 (including interest) the Division says is an improper portion of Pac West trading activity allocated to Utah; and a $4,800,000 prior‑period entry for Schedule 137 costs arising from billing/accounting reconciliation errors. - Robert Meredith, Rocky Mountain Power’s director of pricing and tariff policy, summarized proposed rate‑spread changes for 2024 and recommended a technical fix to how Schedule 9 was grouped with schedules 31 and 32; he proposed reducing Schedule 9 recovery by $3,300,000 in 2024 and making up the shortfall pro rata across other full‑requirements classes. - Michael Wilding, vice president of Energy Supply Management, defended the company’s hedging and market purchases. Wilding said Utah customers benefit from Pacificorp’s access to Mid‑C and other western market hubs and from the system’s geographic diversity. He urged the Commission not to disallow hedge costs at Mid‑C, arguing the alternative — reserving firm transmission and making all purchases closer to Utah — would be costlier or less liquid.

What regulators and intervenors said - The Division of Public Utilities (DPU) and its consultant Daymark proposed several major adjustments. In its updated recommendation the division proposed an annual Utah‑allocated EBA recovery of $334,500,000 (an update to the division’s earlier filing), a reduction of about $97,100,000 from the company’s interim rate level. The Division’s remaining adjustments included: $629,000 disallowed for replacement power costs associated with certain forced outages it viewed as imprudent; $19,400,000 to remove Washington CCA compliance costs from Utah rates; $4,800,000 to exclude the prior‑period Schedule 137 entry that the Division characterized as known and knowable but omitted by the company in earlier EBAs; and $72,300,000 to reallocate Pac West trading/hedging costs that the Division says do not benefit Utah customers in proportion to cost assignment. - The Office of Consumer Services (OCS) likewise recommended removal of Schedule 137 prior‑period costs (about $4.8 million) and the Washington CCA compliance charges (about $19.4 million Utah‑allocated for 2023). OCS witnesses emphasized the distinction between prior‑period adjustments that were genuinely unknowable when filed (accepted in past proceedings) versus costs the company knew or should have known about when earlier EBAs were filed. - Intervenor Utah Association of Energy Users (UAE) supported a situs assignment of Washington CCA benefits to Washington and endorsed company and DPU proposals that would correct allocation anomalies affecting Schedule 9.

Key points of dispute - Washington Climate Commitment Act (CCA): Pacificorp argues the Chehalis compliance cost functions like a generation tax and should be system‑allocated; DPU, OCS and UAE counter that Washington customers received no‑cost allowances tied to Washington retail load and that the paid allowance costs that remain should not be charged to Utah customers. The company has active litigation against Washington and has asked the Commission to allow recovery pending resolution; regulators in other states (Idaho, Wyoming, Oregon) have disallowed the discriminatory portion. - Hedging and Pac West (Mid‑C) allocations: The Division argues that a large portion of Pac West hedge and trading activity does not benefit Utah customers proportionately and recommends disallowing most of the Pac West portion allocated to Utah (DPU’s corrected position reduces its initial larger adjustment to $72.3M). Company witnesses say Mid‑C is the most liquid, lowest‑cost hub for hedging and that system co‑optimization means Utah customers do benefit from those hedges. - Prior‑period Schedule 137 entry: Rocky Mountain Power seeks to include about $4.8M of pre‑2023 Schedule 137 costs that the company says were omitted earlier because of a billing/accounting interface error; DPU and OCS said the costs were known and knowable earlier and should not be recovered in the 2023 EBA.

Formal and procedural steps at the hearing - The Commission admitted multiple company and intervenor witness testimonies and exhibits into the record after routine oath and identification. The Commission also granted a motion to allow one Office of Consumer Services witness to testify remotely because of a travel disruption. - Parties briefly moved into a confidential session to address commercially sensitive information (hedging/auction strategies and other confidential exhibits) and then returned to open session. - Commissioners indicated an administrative target for issuing a final EBA order before the statutory/administrative deadline (the parties noted an internal 300‑day target and referenced a February deadline).

What’s next No final Commission decision was issued at the hearing. The Commission heard testimony and cross‑examination on the contested adjustments and stated it will issue an order on the EBA docket following review of the record. The parties and consultants developed detailed exhibits and data requests that the Commission will consider in drafting a final order.

Ending note: The contested issues in this single annual EBA filing combine technical accounting items (Schedule 137), allocation methodology (Pac West hedges; grouping of rate schedules), and a policy and jurisdictional dispute (Washington CCA). The Commission’s eventual ruling will determine which costs Utah customers will carry and which will be borne elsewhere in the Pacificorp system.