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Regulatory Matters | 12 Months Ended
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Dec. 31, 2021
Regulated Operations [Abstract] |
Regulatory Matters | NOTE 23. REGUL ATORY MATTERS Regulatory Assets and Liabilities The following table presents the Company’s regulatory assets and liabilities as of December 31, 2021 (dollars in thousands):
|  |  |  |  | Receiving Regulatory Treatment |  |  |  |  |  | 2021 |  |  | 2020 |
|  | Remaining Amortization Period |  |  | (1) Earning A Return |  |  | Not Earning A Return |  |  | (2) Expected Recovery or Refund |  |  | Current |  |  | Non- current |  |  | Current |  |  | Non- current |
Regulatory Assets: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Deferred income tax |  |  | (3 | ) |  | $ | 244,154 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 244,154 |  |  | $ | — |  |  | $ | 108,517 |
Pensions and other postretirement benefit plans |  |  | (4 | ) |  |  | — |  |  |  | 165,696 |  |  |  | — |  |  |  | — |  |  |  | 165,696 |  |  |  | — |  |  |  | 198,746 |
Energy commodity derivatives |  |  | (5 | ) |  |  | — |  |  |  | 15,385 |  |  |  | — |  |  |  | 12,447 |  |  |  | 2,938 |  |  |  | 2,073 |  |  |  | 5,722 |
Unamortized debt repurchase costs |  |  | (6 | ) |  |  | 6,768 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 6,768 |  |  |  | — |  |  |  | 7,512 |
Settlement with Coeur d’Alene Tribe |  | 2059 |  |  |  | 38,926 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 38,926 |  |  |  | — |  |  |  | 40,043 |
Demand side management programs |  |  | (3 | ) |  |  | — |  |  |  | 3,974 |  |  |  | — |  |  |  | — |  |  |  | 3,974 |  |  |  | — |  |  |  | 3,814 |
Decoupling surcharge |  | 2023 |  |  |  | 24,532 |  |  |  | — |  |  |  | — |  |  |  | 9,907 |  |  |  | 14,625 |  |  |  | 7,123 |  |  |  | 17,123 |
Utility plant to be abandoned |  |  | (7 | ) |  |  | 26,771 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 26,771 |  |  |  | — |  |  |  | 28,916 |
Interest rate swaps |  |  | (8 | ) |  |  | 158,082 |  |  |  | — |  |  |  | 41,672 |  |  |  | — |  |  |  | 199,754 |  |  |  | — |  |  |  | 214,851 |
Deferred power costs |  |  | (3 | ) |  |  | 10,835 |  |  |  | — |  |  |  | — |  |  |  | 7,334 |  |  |  | 3,501 |  |  |  | 1,775 |  |  |  | 1,562 |
Deferred natural gas costs |  |  | (3 | ) |  |  | 21,027 |  |  |  | — |  |  |  | — |  |  |  | 14,095 |  |  |  | 6,932 |  |  |  | 2,308 |  |  |  | — |
AFUDC above FERC allowed rate |  |  | (11 | ) |  |  | 48,455 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 48,455 |  |  |  | — |  |  |  | 47,393 |
COVID-19 deferrals |  |  | (12 | ) |  |  | — |  |  |  | — |  |  |  | 13,591 |  |  |  | — |  |  |  | 13,591 |  |  |  | — |  |  |  | 8,166 |
Advanced meter infrastructure |  |  | (13 | ) |  |  | 36,008 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 36,008 |  |  |  | — |  |  |  | 26,379 |
Other regulatory assets |  |  | (3 | ) |  |  | 37,045 |  |  |  | 8,563 |  |  |  | 2,925 |  |  |  | — |  |  |  | 48,533 |  |  |  | 394 |  |  |  | 41,699 |
Total regulatory assets |  |  |  |  | $ | 652,603 |  |  | $ | 193,618 |  |  | $ | 58,188 |  |  | $ | 43,783 |  |  | $ | 860,626 |  |  | $ | 13,673 |  |  | $ | 750,443 |
Regulatory Liabilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Deferred natural gas costs |  |  | (3 | ) |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 874 |  |  | $ | — |
Deferred power costs |  |  | (3 | ) |  |  | 11,891 |  |  |  | — |  |  |  | — |  |  |  | 6,457 |  |  |  | 5,434 |  |  |  | 20,299 |  |  |  | 17,570 |
Utility plant retirement costs |  |  | (9 | ) |  |  | 350,190 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 350,190 |  |  |  | — |  |  |  | 325,832 |
Income tax related liabilities |  | (3) (10) |  |  |  | 346,847 |  |  |  | 24,411 |  |  |  | 143,862 |  |  |  | 56,331 |  |  |  | 458,789 |  |  |  | 14,952 |  |  |  | 399,677 |
Interest rate swaps |  |  | (8 | ) |  |  | 13,589 |  |  |  | — |  |  |  | 1,473 |  |  |  | — |  |  |  | 15,062 |  |  |  | — |  |  |  | 15,046 |
Decoupling rebate |  | 2022 |  |  |  | 9,308 |  |  |  | — |  |  |  | — |  |  |  | 3,049 |  |  |  | 6,259 |  |  |  | 1,447 |  |  |  | 1,519 |
COVID-19 deferrals |  |  | (12 | ) |  |  | — |  |  |  | — |  |  |  | 12,500 |  |  |  | — |  |  |  | 12,500 |  |  |  | — |  |  |  | 10,949 |
Other regulatory liabilities |  |  | (3 | ) |  |  | 6,905 |  |  |  | 17,688 |  |  |  | — |  |  |  | 11,312 |  |  |  | 13,281 |  |  |  | 8,863 |  |  |  | 14,227 |
Total regulatory liabilities |  |  |  |  | $ | 738,730 |  |  | $ | 42,099 |  |  | $ | 157,835 |  |  | $ | 77,149 |  |  | $ | 861,515 |  |  | $ | 46,435 |  |  | $ | 784,820 |
(1) Earning a return includes either interest on the regulatory asset/liability or a return on the investment as a component of rate base at the allowed rate of return. (2) Expected recovery is pending regulatory treatment including regulatory assets and liabilities with prior regulatory precedence. (3) Remaining amortization period varies depending on timing of underlying transactions. (4) As the Company has historically recovered and currently recovers its pension and other postretirement benefit costs related to its regulated operations in retail rates, the Company records a regulatory asset for that portion of its pension and other postretirement benefit funding deficiency. (5) The WUTC and the IPUC issued accounting orders authorizing Avista Corp. to offset energy commodity derivative assets or liabilities with a regulatory asset or liability. This accounting treatment is intended to defer the recognition of mark-to-market gains and losses on energy commodity transactions until the period of delivery. Realized benefits and losses result in adjustments to retail rates through PGAs, the ERM in Washington, the PCA mechanism in Idaho and periodic general rates cases. The resulting regulatory assets associated with energy commodity derivative instruments have been concluded to be probable of recovery through future rates. (6) Premiums paid or discounts received to repurchase debt are amortized over the remaining life of the original debt that was repurchased or, if new debt is issued in connection with the repurchase, these costs are amortized over the life of the new debt. These costs are recovered through retail rates as a component of interest expense. (7) The WUTC approved recovery of AMI project costs through the 2020 general rate case settlements, including amortization of retired meters replaced through the project through 2033. There are additional smaller projects included in the balance that the Company expects to fully recover, which have not yet been through the regulatory process. (8) For interest rate swap derivatives, Avista Corp. records all mark-to-market gains and losses in each accounting period as assets and liabilities, as well as offsetting regulatory assets and liabilities, such that there is no income statement impact. The interest rate swap derivatives are risk management tools similar to energy commodity derivatives. Upon settlement of interest rate swap derivatives, the regulatory asset or liability is amortized as a component of interest expense over the term of the associated debt. The Company records an offset of interest rate swap derivative assets and liabilities with regulatory assets and liabilities, based on the prior practice of the commissions to provide recovery through the ratemaking process. Settled interest rate swap derivatives which have been through a general rate case proceeding are classified as earning a return in the table above, whereas all unsettled interest rate swap derivatives and settled interest rate swap derivatives which have not been included in a general rate case are classified as expected recovery. (9) This amount is dependent upon the cost of removal of underlying utility plant assets and the life of utility plant. (10) The majority of this balance represents amounts due back to customers and resulted from the Tax Cuts and Jobs Act signed into law in December 2017, which changed the federal income tax rate from 35 percent to 21 percent. The Company revalued all deferred income taxes as of December 31, 2017. The Company expects the amounts for utility plant items for Avista Utilities to be returned to customers over a period of approximately 32 years. The Company expects the AEL&P amounts to be returned to customers over a period of approximately 40 years. A significant portion of the regulatory liability attributable to non-plant excess deferred taxes was used to offset a portion of the costs associated with accelerating the depreciation of Colstrip based on settlements in Washington and Idaho. (11) This amount is being amortized based on the underlying utility plant assets and the life of utility plant. (12) The WUTC, IPUC and OPUC issued accounting orders allowing the Company to defer certain costs, net of any benefits, related to the COVID-19 pandemic. The Company has recorded all benefits on a gross basis as a regulatory liability to customers and all additional allowed costs are a regulatory asset. The ratemaking treatment will be determined in future general rate cases in each jurisdiction. (13) This amount represents the deferral of the depreciation expense of the Company’s AMI project in Washington state. Recovery of these amounts was approved by WUTC in the 2021 general rate case order. Power Cost Deferrals and Recovery Mechanisms Deferred power supply costs are recorded as a deferred charge or liability on the Consolidated Balance Sheets for future prudence review and recovery or rebate through retail rates. The power supply costs deferred include certain differences between actual net power supply costs incurred by Avista Utilities and the costs included in base retail rates. This difference in net power supply costs primarily results from changes in: • short-term wholesale market prices and sales and purchase volumes, • the level, availability and optimization of hydroelectric generation, • the level and availability of thermal generation (including changes in fuel prices), • retail loads, and • sales of surplus transmission capacity. In Washington, the ERM allows Avista Utilities to periodically increase or decrease electric rates with WUTC approval to reflect changes in power supply costs. The ERM is an accounting method used to track certain differences between actual power supply costs, net of wholesale sales and sales of fuel, and the amount included in base retail rates for Washington customers and defer these differences (over the $4.0 million deadband and sharing bands) for future surcharge or rebate to customers. For 2021, the Company recognized a pre-tax expense o f $7.7 million under the ERM in Washington compared to a benefit of $6.2 million for 2020. Total net deferred power costs under the ERM were a liabil ity of $11.9 million as of December 31, 2021 and a liability of $37.9 million as of December 31, 2020. These deferred power cost balances represent amounts due to customers. Pursuant to WUTC requirements, should the cumulative deferral balance exceed $30 million in the rebate or surcharge direction, the Company must make a filing with the WUTC to adjust customer rates to either return the balance to customers or recover the balance from customers. As the cumulative rebate balance exceeded $30 million, the Company’s 2019 filing contained a proposed rate refund. The ERM proceeding was considered with the Company’s 2019 general rate case proceeding and a refund was approved and is being returned to customers over a two-year period that began on April 1, 2020. Avista Utilities makes an annual filing on, or before, April 1 of each year to provide the opportunity for the WUTC staff and other interested parties to review the prudence of, and audit, the ERM deferred power cost transactions for the prior calendar year. Avista Utilities has a PCA mechanism in Idaho that allows it to modify electric rates on October 1 of each year with IPUC approval. Under the PCA mechanism, Avista Utilities defers 90 percent of the difference between certain actual net power supply expenses and the amount included in base retail rates for its Idaho customers. The October 1 rate adjustments recover or rebate power costs deferred during the preceding July-June twelve-month period. Total net power supply costs deferred under the PCA mechanism were an asset of $10.8 million as of December 31, 2021 and $2.5 million as of December 31, 2020. Deferred power cost assets represent amounts due from customers and liabilities represent amounts due to customers. Natural Gas Cost Deferrals and Recovery Mechanisms Avista Utilities files a PGA in all three states it serves to adjust natural gas rates for: 1) estimated commodity and pipeline transportation costs to serve natural gas customers for the coming year, and 2) the difference between actual and estimated commodity and transportation costs for the prior year. Total net deferred natural gas costs were an asset of $21.0 million as of December 31, 2021 and $1.4 million as of December 31, 2020. Asset balances represent amounts due from customers and liabilities represent amounts due to customers. Decoupling and Earnings Sharing Mechanisms Decoupling (also known as an FCA in Idaho) is a mechanism designed to sever the link between a utility's revenues and consumers' energy usage. In each of Avista Utilities' jurisdictions, Avista Utilities' electric and natural gas revenues are adjusted so as to be based on the number of customers in certain customer rate classes and assumed "normal" kilowatt hour and therm sales, rather than being based on actual kilowatt hour and therm sales. The difference between revenues based on the number of customers and "normal" sales and revenues based on actual usage is deferred and either surcharged or rebated to customers beginning in the following year. Only residential and certain commercial customer classes are included in decoupling mechanisms. Washington Decoupling and Earnings Sharing In Washington, the WUTC approved the Company's decoupling mechanisms for electric and natural gas for a five-year period beginning January 1, 2015. In 2019, the WUTC approved an extension of the mechanisms for an additional five-year term through March 31, 2025, with one modification in that new customers added after any test period would not be decoupled until included in a future test period. Electric and natural gas decoupling surcharge rate adjustments to customers are limited to a 3 percent increase on an annual basis, with any remaining surcharge balance carried forward for recovery in a future period. There is no limit on the level of rebate rate adjustments. The decoupling mechanisms each include an after-the-fact earnings test. At the end of each calendar year, separate electric and natural gas earnings calculations are made for the calendar year just ended. These earnings tests reflect actual decoupled revenues, normalized power supply costs and other normalizing adjustments. If the Company earns more than its authorized ROR in Washington, 50 percent of excess earnings are rebated to customers through adjustments to decoupling surcharge or rebate balances. See below for a summary of cumulative balances under the decoupling and earnings sharing mechanisms. The Company has proposed to modify this earnings test in its 2022 general rate case, so that if the Company earns more than 0.5 percent higher than the ROR authorized by the WUTC in the multi-year rate plan, the Company would defer these excess revenues and later return them to customers. Idaho FCA and Earnings Sharing Mechanisms In Idaho, the IPUC approved the implementation of FCAs for electric and natural gas through March 31, 2025. Oregon Decoupling Mechanism In Oregon, the Company has a decoupling mechanism for natural gas. An earnings review is conducted on an annual basis. In the annual earnings review, if the Company earns more than 100 basis points above its allowed ROE, one-third of the earnings above the 100 basis points would be deferred and later returned to customers. The earnings review is separate from the decoupling mechanism and was in place prior to decoupling. Cumulative Decoupling and Earnings Sharing Mechanism Balances As of December 31, 2021 and December 31, 2020, the Company had the following cumulative balances outstanding related to decoupling and earnings sharing mechanisms in its various jurisdictions (dollars in thousands):
|  | December 31, |  |  | December 31, |
|  | 2021 |  |  | 2020 |
Washington |  |  |  |  |  |
Decoupling surcharge |  | $ | 13,522 |  |  | $ | 21,340 |
Idaho |  |  |  |  |  |
Decoupling (rebate) surcharge |  | $ | (1,450 | ) |  | $ | 1,202 |
Provision for earnings sharing rebate |  |  | (686 | ) |  |  | (686 | )
Oregon |  |  |  |  |  |
Decoupling surcharge (rebate) |  | $ | 3,152 |  |  | $ | (1,262 | )
There were no earnings sharing rebates associated with Washington and Oregon as of December 31, 2021 and December 31, 2020.

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