We had the following regulatory assets and liabilities as of December 31 (in thousands):


	2022			2021
Regulatory assets
Winter Storm Uri (a)	$	347,980		$	509,025
Deferred energy and fuel cost adjustments (b)		72,580			59,973
Deferred gas cost adjustments (b)		12,147			9,488
Gas price derivatives (b)		8,793			2,584
Deferred taxes on AFUDC (b)		7,333			7,457
Employee benefit plans and related deferred taxes (c)		89,259			88,923
Environmental (b)		1,343			1,385
Loss on reacquired debt (b)		19,213			21,011
Deferred taxes on flow-through accounting (b)		69,529			63,243
Decommissioning costs (b)		3,472			5,961
Other regulatory assets (b)		21,332			27,549
Total regulatory assets		652,981			796,599
Less current regulatory assets		(260,312	)		(270,290	)
Regulatory assets, non-current	$	392,669		$	526,309

Regulatory liabilities
Deferred energy and gas costs (b)	$	24,030		$	6,113
Employee benefit plan costs and related deferred taxes (c)		34,258			32,241
Cost of removal (b)		175,614			179,976
Excess deferred income taxes (c)		254,833			264,042
Other regulatory liabilities (c)		29,838			20,579
Total regulatory liabilities		518,573			502,951
Less current regulatory liabilities		(46,013	)		(17,574	)
Regulatory liabilities, non-current	$	472,560		$	485,377

(a)

Timing of Winter Storm Uri incremental cost recovery and associated carrying costs vary by jurisdiction. 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.

Deferred Gas Cost Adjustments - 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 monthly, quarterly, semi-annual and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state regulatory commissions.

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, 2022 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.

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 ASC 715, Compensation-Retirement Benefits. In addition, this regulatory liability includes the income tax effect of the adjustment required under ASC 715, Compensation-Retirement Benefits, 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.

In February 2021, Winter Storm Uri 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, 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. In these applications, we sought approval to recover carrying costs. We have received final commission approval for all of our Winter Storm Uri cost recovery applications, which will allow our Utilities to recover incremental fuel, purchased power and natural gas costs.

For the years ended December 31, 2022 and 2021, our Utilities collected $174 million and $40 million, respectively, of Winter Storm Uri incremental costs and carrying costs from customers. As of December 31, 2022, we estimate that our remaining Winter Storm Uri regulatory asset has a weighted-average recovery period of 2.6 years.

For years ended December 31, 2022 and 2021, $22 million and $4.1 million, respectively, of carrying costs were accrued and recorded to a regulatory asset. The carrying costs accrued during the year ended December 31, 2022 included a one-time, $10 million true-up recorded in the second quarter to reflect commission authorized rates.

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.

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.

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.

As part of Kansas Gas’ 2021 rate review settlement agreement, Kansas Gas will deliver $9.1 million, or approximately $3.0 million of TCJA and state tax reform benefits to customers annually, for three years starting in 2022. For the year ended December 31, 2022, Kansas Gas delivered TCJA and state tax reform benefits to customers of $2.9 million.

These Colorado Electric, Kansas Gas and Nebraska Gas tax benefits delivered to customers, 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 years ended December 31, 2022 and 2021.

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. On October 10, 2022, the APSC approved a partial settlement agreement with all intervening parties for a general rate increase and authorized a capital structure of 45% equity and 55% debt and a return on equity of 9.6%. The APSC’s decision shifts approximately $10 million of rider revenue to base rates and is expected to generate $8.8 million of new annual revenue. The APSC also approved a new comprehensive safety and integrity rider which replaces three former riders. New rates were effective on October 21, 2022.

On June 1, 2022, Wyoming Electric filed a rate review with the WPSC seeking recovery of significant infrastructure investments in its 1330-mile electric distribution and 59-mile electric transmission systems. On January 26, 2023, the WPSC approved a settlement agreement with intervening parties for a general rate increase. The settlement is expected to generate $8.7 million in new annual revenue with a capital structure of 52% equity and 48% debt and a return on equity of 9.75%. New rates will be effective on March 1, 2023. The agreement also includes approval of a new rider that will be filed annually to recover transmission investment and expenses.

On October 7, 2022, RMNG filed a rate review with the CPUC seeking recovery of significant infrastructure investments in its 600-mile natural gas pipeline system. The rate review requests $12.3 million in new annual revenue based on a future test year with a capital structure of 52% equity and 48% debt and a return on equity of 12.3%. The rate review also requests a $7.7 million shift of SSIR revenues to base rates. The request seeks to finalize rates in the third quarter of 2023.

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. New 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.

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 shifted $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.

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.

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, 2022, the annual revenue requirement for the FERC Transmission Formula Rate was $30 million and included estimated weighted average capital additions of $30 million for 2021 and 2022 combined.

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 expire after 11 years.