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Regulatory Matters: | 12 Months Ended
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Dec. 31, 2021
Regulated Operations [Abstract] |
Regulatory Matters | REGULATORY MATTERS We had the following regulatory assets and liabilities as of December 31 (in thousands):
| 2021 | 2020
Regulatory assets |  |
Winter Storm Uri (a) | $ | 509,025 |  | $ | — |
Deferred energy and fuel cost adjustments (b) | 59,973 |  | 39,035 |
Deferred gas cost adjustments (b) | 9,488 |  | 3,200 |
Gas price derivatives (b) | 2,584 |  | 2,226 |
Deferred taxes on AFUDC (b) | 7,457 |  | 7,491 |
Employee benefit plans and related deferred taxes (c) | 88,923 |  | 116,598 |
Environmental (b) | 1,385 |  | 1,413 |
Loss on reacquired debt (b) | 21,011 |  | 22,864 |
Deferred taxes on flow-through accounting (b) | 63,243 |  | 47,515 |
Decommissioning costs (b) | 5,961 |  | 8,988 |
Gas supply contract termination (b) | — |  | 2,524 |
Other regulatory assets (b) | 27,549 |  | 26,404 |
Total regulatory assets | 796,599 |  | 278,258 |
Less current regulatory assets | (270,290) |  | (51,676) |
Regulatory assets, non-current | $ | 526,309 |  | $ | 226,582 |
Regulatory liabilities |  |
Deferred energy and gas costs (b) | $ | 6,113 |  | $ | 13,253 |
Employee benefit plan costs and related deferred taxes (c) | 32,241 |  | 40,256 |
Cost of removal (b) | 179,976 |  | 172,902 |
Excess deferred income taxes (c) | 264,042 |  | 285,259 |
Other regulatory liabilities (c) | 20,579 |  | 21,050 |
Total regulatory liabilities | 502,951 |  | 532,720 |
Less current regulatory liabilities | (17,574) |  | (25,061) |
Regulatory liabilities, non-current | $ | 485,377 |  | $ | 507,659 |
_____________________ (a) Timing of Winter Storm Uri incremental cost recovery and associated carrying costs vary by jurisdiction and some jurisdictions are still subject to pending applications with the respective utility commission. See further information below. (b) Recovery of costs, but we are not allowed a rate of return. (c) In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base. Regulatory assets represent items we expect to recover from customers through probable future rates. Winter Storm Uri - See discussion below for Winter Storm Uri regulatory asset information. Deferred Energy and Fuel Cost Adjustments - Deferred energy and fuel cost adjustments represent the cost of electricity delivered to our Electric Utilities’ customers that is either higher or lower than the current rates and will be recovered or refunded in future rates. Deferred energy and fuel cost adjustments are recorded and recovered or amortized as approved by the appropriate state regulatory commission. Our Electric Utilities file periodic quarterly, semi-annual and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state regulatory commissions. The recovery period for these costs is less than a year. Deferred Gas Cost Adjustment s - Our regulated Gas Utilities have GCA provisions that allow them to pass the cost of gas on to their customers. The GCA is based on forecasts of the upcoming gas costs and recovery or refund of prior under-recovered or over-recovered costs. To the extent that gas costs are under-recovered or over-recovered, they are recorded as a regulatory asset or liability, respectively. Our Gas Utilities file periodic estimates of future gas costs based on market forecasts with state regulatory commissions. The recovery period for these costs is less than a year. Gas Price Derivatives - Our regulated Gas Utilities, as allowed or required by state regulatory commissions, have entered into certain exchange-traded natural gas futures and options to reduce our customers’ underlying exposure to fluctuations in gas prices. Gas price derivatives represent our unrealized positions on our commodity contracts supporting our utilities. Gas price derivatives at December 31, 2021 are hedged over a maximum forward term of two years. Deferred Taxes on AFUDC - The equity component of AFUDC is considered a permanent difference for tax purposes with the tax benefit being flowed through to customers as prescribed or allowed by regulators. If, based on a regulator’s action, it is probable the utility will recover the future increase in taxes payable represented by this flow-through treatment through a rate revenue increase, a regulatory asset is recognized. This regulatory asset is a temporary difference for which a deferred tax liability must be recognized. Accounting standards for income taxes specifically address AFUDC-equity and require a gross-up of such amounts to reflect the revenue requirement associated with a rate-regulated environment. Employee Benefit Plans and Related Deferred Taxes - Employee benefit plans include the unrecognized prior service costs and net actuarial loss associated with our defined benefit pension plan and post-retirement benefit plans in regulatory assets rather than in AOCI. In addition, this regulatory asset includes the income tax effect of the adjustment required under accounting for compensation - defined benefit plans, to record the full pension and post-retirement benefit obligations. Such income tax effect has been grossed-up to account for the revenue requirement associated with a rate regulated environment. Environmental - Environmental costs associated with certain former manufactured gas plant sites. These costs are first offset by recognition of insurance proceeds and settlements with other third parties. Any remaining cost will be requested for recovery in future rate filings. Recovery for these specific environmental costs has not yet been approved by the applicable state regulatory commission and therefore, the recovery period is unknown at this time. Loss on Reacquired Debt - Loss on reacquired debt is recovered over the remaining life of the original issue or, if refinanced, over the life of the new issue. Deferred Taxes on Flow-Through Accounting - Under flow-through accounting, the income tax effects of certain tax items are reflected in our cost of service for the customer and result in lower utility rates in the year in which the tax benefits are realized. A regulatory asset was established to reflect that future increases in income taxes payable will be recovered from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record a tax benefit for costs considered currently deductible for tax purposes, but are capitalized for book purposes. Decommissioning Costs - South Dakota Electric and Colorado Electric received approval in 2014 for recovery of the remaining net book values and decommissioning costs of their decommissioned coal plants. In 2018, Arkansas Gas received approval to record Liquefied Natural Gas Plant decommissioning costs as a regulatory asset and received approval in 2020 to begin recovering those costs over three years. Gas Supply Contract Termination - With the 2016 SourceGas acquisition, we assumed agreements requiring the Company to purchase all of the natural gas produced over the productive life of specific leaseholds in the Bowdoin Field in Montana. The prices to be paid under these agreements exceeded market prices at the time of acquisition. We received state utility commission approvals to terminate these agreements and Orders allowing us to create a regulatory asset for the net contract buyout costs with recovery over five years. We terminated the contract and settled the liability on April 29, 2016. Regulatory liabilities represent items we expect to refund to customers through probable future decreases in rates. Deferred Energy and Gas Costs - Deferred energy and gas costs that have been over-recovered through customer rates and will be returned to customers in future periods. Employee Benefit Plan Costs and Related Deferred Taxes - Employee benefit plans represent the cumulative excess of pension and retiree healthcare costs recovered in rates over pension expense recorded in accordance with accounting standards for compensation - retirement benefits. In addition, this regulatory liability includes the income tax effect of the adjustment required under accounting for compensation - defined benefit plans, to record the full pension and post-retirement benefit obligations. Such income tax effect has been grossed-up to account for the revenue requirement associated with a rate regulated environment. Cost of Removal - Cost of removal represents the estimated cumulative net provisions for future removal costs for which there is no legal obligation for removal included in depreciation expense. Excess Deferred Income Taxes - The revaluation of the regulated utilities' deferred tax assets and liabilities due to the passage of the TCJA was recorded as an excess deferred income tax to be refunded to customers primarily using the normalization principles as prescribed in the TCJA. See Note 15 for additional information. Recent Regulatory Activity Winter Storm Uri In February 2021, a prolonged period of historic cold temperatures across the central United States covered all of our Utilities’ service territories, caused a substantial increase in heating and energy demand and contributed to unforeseeable and unprecedented market prices for natural gas and electricity. As a result of Winter Storm Uri, we incurred significant incremental fuel, purchased power and natural gas costs. Our Utilities submitted Winter Storm Uri cost recovery applications in our state jurisdictions seeking to recover $546 million of these incremental costs through separate tracking mechanisms over a weighted-average recovery period of 3.5 years. These incremental cost estimates are subject to adjustments as final decisions are issued by the respective utility commissions. In these applications, we sought approval to recover carrying costs. For the year ended December 31, 2021, $4.1 million of carrying costs were accrued and recorded to a regulatory asset. We are also seeking recovery of $13 million of previously disclosed Winter Storm Uri incremental costs through our existing regulatory mechanisms. To date, Iowa Gas, Kansas Gas, Nebraska Gas and South Dakota Electric received commission approval for Winter Storm Uri cost recovery. Additionally, Arkansas Gas and Wyoming Gas received approval for interim cost recovery subject to a final decision on carrying costs and recovery periods at a later date. Colorado Gas and Colorado Electric filed settlement agreements for their applications with final rates to be implemented in 2022. These settlements are subject to final approval by the CPUC. For the year ended December 31, 2021, our Utilities collected $40 million of Winter Storm Uri incremental costs and carrying costs from customers. TCJA On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA reduced the U.S. federal corporate tax rate from 35% to 21%. As such, the Company remeasured our deferred income taxes at the 21% federal tax rate as of December 31, 2017. In 2018 and 2019, the Company successfully delivered several of these tax benefits from the TCJA to its utility customers. In 2020, regulatory proceedings resolved the last of the Company’s open dockets seeking approval of its TCJA plans. As a result, the Company relieved certain TCJA-related liabilities, which resulted in an increase to net income for the year ended December 31, 2020 of $4.0 million. On December 30, 2020, an administrative law judge approved a settlement of Colorado Electric’s plan to provide $9.3 million of TCJA-related bill credits to its customers. The bill credits, which represent a disposition of excess deferred income tax benefits resulting from the TCJA, were delivered to customers in February 2021. The settlement agreement further provided for Colorado Electric to deliver annual bill credits to customers, starting in April 2021, until remaining excess deferred income tax regulatory liabilities associated with the TCJA are fully amortized. In April 2021, Colorado Electric delivered $0.9 million of TCJA-related bill credits to customers. On January 26, 2021, the NPSC approved Nebraska Gas’s plan to provide $2.9 million of TCJA-related bill credits to its customers. The bill credits, which represent a disposition of excess deferred income tax benefits resulting from the TCJA, were delivered to customers in June 2021. These Colorado Electric and Nebraska Gas bill credits, which resulted in a reduction in revenue, were offset by a reduction in income tax expense and resulted in a minimal impact to Net income for the year ended December 31, 2021. As part of the 2021 rate review settlement agreement discussed further below, Kansas Gas will deliver $3.0 million of TCJA and state tax reform benefits to customers, annually, for each of the next three years starting in 2022 (approximately $9.1 million of total benefits expected to be delivered). Arkansas Gas On December 10, 2021, Arkansas Gas filed a rate review with the APSC seeking recovery of significant infrastructure investments in its 7,200-mile natural gas pipeline system. The rate review requests $22 million in new annual revenue with a capital structure of 50.9% equity and 49.1% debt and a return on equity of 10.2%. The request seeks to finalize rates in the fourth quarter of 2022. Colorado Gas Rate Reviews and SSIR On June 1, 2021, Colorado Gas filed a rate review with the CPUC seeking recovery of significant infrastructure investments in its 7,000-mile natural gas pipeline system. In the fourth quarter of 2021, Colorado Gas reached a settlement agreement with the CPUC staff and various intervenors for a general rate increase, which was subsequently approved by an administrative law judge. N ew rates were effective January 1, 2022, and the settlement is expected to generate $6.5 million of new annual revenue. The new revenue is based on a return on equity of 9.2% and a capital structure of 50.3% equity and 49.7% debt. On September 11, 2020, in accordance with the final Order from the rate review filed on February 1, 2019, Colorado Gas filed a SSIR proposal with the CPUC that would recover safety and integrity focused investments in its system for five years. On July 6, 2021, Colorado Gas received approval from the CPUC for its SSIR proposal to recover these investments for three years effective January 1, 2022. The return on SSIR investments will be the current weighted-average cost of long-term debt. Iowa Gas Rate Review On June 1, 2021, Iowa Gas filed a rate review with the IUB seeking recovery of significant infrastructure investments in its 5,000-mile natural gas pipeline system. On December 28, 2021, the IUB approved a settlement agreement with all intervening parties for a general rate increase. The settlement will shift $2.2 million of rider revenue to base rates and is expected to generate $3.7 million in new annual revenue with a capital structure of 50% equity and 50% debt and a return on equity of 9.6%. Final rates were enacted on January 1, 2022, and replaced interim rates effective June 11, 2021. Kansas Gas Rate Review On May 7, 2021, Kansas Gas filed a rate review and rider renewal with the KCC seeking recovery of significant infrastructure investments in its 4,600-mile natural gas pipeline system. On December 30, 2021, Kansas Gas received approval from the KCC on its Global Settlement agreement with KCC staff and various intervenors for a general rate increase and renewal of its safety and integrity rider. The settlement shifted $6.6 million of rider revenue to base rates, effective January 1, 2022, and also allowed rider renewal for at least five more years. Nebraska Gas Jurisdictional Consolidation and Rate Review On January 26, 2021, Nebraska Gas received approval from the NPSC to consolidate rate schedules into a new, single statewide structure and recover significant infrastructure investments in its 13,000-mile natural gas pipeline system. Final rates were enacted on March 1, 2021, which replaced interim rates effective September 1, 2020. The approval shifted $4.6 million of SSIR revenue to base rates and is expected to generate $6.5 million in new annual revenue with a capital structure of 50% equity and 50% debt and a return on equity of 9.5%. The approval also included an extension of the SSIR for five years and an expansion of this mechanism across the consolidated jurisdictions. South Dakota Electric FERC Formula Rate The annual rate determination process is governed by the FERC formula rate protocols established in the filed FERC joint-access transmission tariff. Effective January 1, 2021, the annual revenue requirement for the FERC Transmission Formula Rate was $26 million and included estimated weighted average capital additions of $5.0 million for 2020 and 2021 combined. Black Hills Wyoming and Wyoming Electric Wygen I FERC Filing On October 15, 2020, the FERC approved a settlement agreement that represents a resolution of all issues in the joint application filed by Wyoming Electric and Black Hills Wyoming on August 2, 2019 for approval of a new 60 MW PPA. Under the terms of the settlement, Wyoming Electric will continue to receive 60 MW of capacity and energy from the Wygen I power plant. The new agreement commenced on January 1, 2022, replaced the existing PPA and will continue for 11 years.

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- Definition The entire disclosure for detailed information about regulatory assets and liabilities, including current and noncurrent assets created when regulatory agencies permit the deferral of costs to the balance sheet that would otherwise be required to appear on the company's income statement and would be charged against current expenses or revenues, as well as current and noncurrent liabilities created when regulatory agencies permit. + References No definition available. + Details
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