Regulatory Matters

12 Months Ended

Dec. 31, 2021

Schedule Of Regulatory Assets and Liabilities [Line Items]

Regulatory Matters

Regulatory Matters

Regulatory Assets

Regulatory assets represent costs that are expected to be recovered in future regulated rates. The Company's regulatory assets reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):

	Weighted
	Average
	Remaining Life	2021		2020
Asset retirement obligations	14 years	$	742	$	640
Deferred net power costs	1 year	531		139
Employee benefit plans(1)	15 years	472		722
Deferred income taxes(2)	Various	342		283
Asset disposition costs	Various	285		347
Demand side management	10 years	211		197
Unrealized loss on regulated derivative contracts	Various	157		31
Environmental costs	28 years	108		89
Deferred operating costs	9 years	103		124
Other	Various	1,012		868
Total regulatory assets		$	3,963	$	3,440
Reflected as:
Current assets		$	544	$	283
Noncurrent assets		3,419		3,157
Total regulatory assets		$	3,963	$	3,440

(1)Includes amounts not yet recognized as a component of net periodic benefit cost that are expected to be included in regulated rates when recognized.

(2)Amounts primarily represent income tax benefits related to certain property-related basis differences and other various differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse.

The Company had regulatory assets not earning a return on investment of $1.8 billion and $1.6 billion as of December 31, 2021 and 2020, respectively.

Regulatory Liabilities

Regulatory liabilities represent income to be recognized or amounts to be returned to customers in future periods. The Company's regulatory liabilities reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):

	Weighted
	Average
	Remaining Life	2021		2020
Deferred income taxes(1)	Various	$	3,185	$	3,600
Cost of removal(2)	26 years	2,424		2,435
Asset retirement obligations	31 years	345		305
Levelized depreciation	29 years	259		281
Employee benefit plans(3)	Various	243		187
Other	Various	758		667
Total regulatory liabilities		$	7,214	$	7,475
Reflected as:
Current liabilities		$	254	$	254
Noncurrent liabilities		6,960		7,221
Total regulatory liabilities		$	7,214	$	7,475

(1)Amounts primarily represent income tax liabilities related to the federal tax rate change from 35% to 21% that are probable to be passed on to customers, offset by income tax benefits related to certain property-related basis differences and other various differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse.

(2)Amounts represent estimated costs, as accrued through depreciation rates and exclusive of ARO liabilities, of removing regulated property, plant and equipment in accordance with accepted regulatory practices. Amounts are deducted from rate base or otherwise accrue a carrying cost.

(3)Includes amounts not yet recognized as a component of net periodic benefit cost that are expected to be returned to customers in future periods when recognized.

PAC

Schedule Of Regulatory Assets and Liabilities [Line Items]

Regulatory Matters

Regulatory Matters

Regulatory Assets

Regulatory assets represent costs that are expected to be recovered in future rates. PacifiCorp's regulatory assets reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):

	Weighted
	Average
	Remaining
	Life	2021		2020
Employee benefit plans(1)	17 years	$	286	$	432
Utah mine disposition(2)	Various	116		117
Unamortized contract values	2 years	36		42
Deferred net power costs	2 years	151		78
Unrealized loss on derivative contracts	N/A	—		17
Environmental costs	28 years	108		89
Asset retirement obligation	29 years	241		252
Demand side management (DSM)(3)	10 years	211		196
Other	Various	203		172
Total regulatory assets		$	1,352	$	1,395
Reflected as:
Current assets		$	65	$	116
Noncurrent assets		1,287		1,279
Total regulatory assets		$	1,352	$	1,395

(1)Represents amounts not yet recognized as a component of net periodic benefit cost that are expected to be included in rates when recognized.

(2)Amounts represent regulatory assets established as a result of the Utah mine disposition in 2015 for the United Mine Workers of America ("UMWA") 1974 Pension Plan withdrawal and closure costs incurred to date considered probable of recovery.

(3)In accordance with the Utah general rate case order issued in December 2020, $185 million of amounts billed to Utah customers under the Utah STEP program were used to accelerate depreciation of certain coal-fueled generation units as discussed in Note 3.

PacifiCorp had regulatory assets not earning a return on investment of $723 million and $707 million as of December 31, 2021 and 2020, respectively.

Regulatory Liabilities

Regulatory liabilities represent income to be recognized or amounts to be returned to customers in future periods. PacifiCorp's regulatory liabilities reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):

	Weighted
	Average
	Remaining
	Life	2021		2020
Cost of removal(1)	26 years	$	1,187	$	1,125
Deferred income taxes(2)	Various	1,307		1,463
Unrealized gain on regulated derivatives	1 year	53		—
Other	Various	221		254
Total regulatory liabilities		$	2,768	$	2,842
Reflected as:
Current liabilities		$	118	$	115
Noncurrent liabilities		2,650		2,727
Total regulatory liabilities		$	2,768	$	2,842

(1)Amounts represent estimated costs, as generally accrued through depreciation rates, of removing property, plant and equipment in accordance with accepted regulatory practices. Amounts are deducted from rate base or otherwise accrue a carrying cost.

(2)Amounts primarily represent income tax liabilities related to the federal tax rate change from 35% to 21% that are probable of being passed on to customers, offset by income tax benefits related to certain property-related basis differences and other various differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse.

MEC

Schedule Of Regulatory Assets and Liabilities [Line Items]

Regulatory Matters

Regulatory Matters

Regulatory Assets

Regulatory assets represent costs that are expected to be recovered in future regulated rates. MidAmerican Energy's regulatory assets reflected on the Balance Sheets consist of the following as of December 31 (in millions):

	Weighted
	Average
	Remaining Life	2021		2020
Asset retirement obligations(1)	6 years	$	393	$	298
Employee benefit plans(2)	13 years	42		66
Unrealized loss on regulated derivative contracts	1 year	5		—
Other	Various	33		28
Total		$	473	$	392

(1)Amount predominantly relates to AROs for fossil-fueled and wind-powered generating facilities. Refer to Note 11 for a discussion of AROs.

(2)Represents amounts not yet recognized as a component of net periodic benefit cost that are expected to be included in regulated rates when recognized.

MidAmerican Energy had regulatory assets not earning a return on investment of $470 million and $389 million as of December 31, 2021 and 2020, respectively.

Regulatory Liabilities

Regulatory liabilities represent amounts expected to be returned to customers in future periods. MidAmerican Energy's regulatory liabilities reflected on the Balance Sheets consist of the following as of December 31 (in millions):

	Weighted
	Average
	Remaining Life	2021		2020
Cost of removal accrual(1)	29 years	$	394	$	466
Asset retirement obligations(2)	31 years	341		300
Iowa electric revenue sharing accrual(3)	1 year	115		—
Deferred income taxes(4)	Various	83		263
Employee benefit plans(5)	9 years	55		20
Pre-funded AFUDC on transmission MVPs(6)	51 years	34		35
Unrealized gain on regulated derivative contracts	1 year	26		2
Other	Various	32		25
Total		$	1,080	$	1,111

(1)Amounts represent estimated costs, as accrued through depreciation rates and exclusive of ARO liabilities, of removing utility plant in accordance with accepted regulatory practices. Amounts are deducted from rate base or otherwise accrue a carrying cost.

(2)Amount represents the excess of nuclear decommission trust assets over the related ARO. Refer to Note 11 for a discussion of AROs.

(3)Represents current-year accruals under a regulatory arrangement in Iowa in which equity returns exceeding specified thresholds reduce utility plant upon final determination.

(4)Amounts primarily represent income tax liabilities primarily related to the federal tax rate change from 35% to 21% that are probable to be passed on to customers, offset by income tax benefits related to state accelerated tax depreciation and certain property-related basis differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse.

(5)Represents amounts not yet recognized as a component of net periodic benefit cost that are to be returned to customers in future periods when recognized.

(6)Represents AFUDC accrued on transmission MVPs that is deducted from rate base as a result of the inclusion of related construction work-in-progress in rate base.

Natural Gas Purchased for Resale

In February 2021, severe cold weather over the central United States caused disruptions in natural gas supply from the southern part of the United States. These disruptions, combined with increased demand, resulted in historically high prices for natural gas purchased for resale to MidAmerican Energy's retail customers and caused an approximate $245 million increase in natural gas costs above those normally expected. These increased costs are reflected in cost of natural gas purchased for resale and other on the Statement of Operations and their recovery through the Purchased Gas Adjustment Clause is reflected in regulated natural gas and other revenue.

To mitigate the impact to MidAmerican Energy's customers, the IUB ordered the recovery of these higher costs to be applied to customer bills over the period April 2021 through April 2022 based on a customer's monthly natural gas usage. The unbilled portion of these costs as of December 31, 2021, is reflected in trade receivables, net on the Balance Sheet. While sufficient liquidity is available to MidAmerican Energy, the increased costs and longer recovery period resulted in higher working capital requirements during the year ended December 31, 2021.

MidAmerican Funding, LLC

Schedule Of Regulatory Assets and Liabilities [Line Items]

Regulatory Matters

Regulatory MattersRefer to Note 5 of MidAmerican Energy's Notes to Financial Statements.

NPC

Schedule Of Regulatory Assets and Liabilities [Line Items]

Regulatory Matters

Regulatory Matters

Regulatory Assets

Regulatory assets represent costs that are expected to be recovered in future rates. Nevada Power's regulatory assets reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):

	Weighted
	Average
	Remaining Life	2021		2020
Deferred energy costs	1 year	$	273	$	39
Decommissioning costs	2 years	169		230
Unrealized loss on regulated derivative contracts	1 year	117		11
Merger costs from 1999 merger	23 years	110		115
Deferred operating costs	12 years	93		119
Asset retirement obligations	6 years	73		70
ON Line deferrals	32 years	42		43
Legacy meters	11 years	41		45
Employee benefit plans(1)	8 years	11		50
Other	Various	90		72
Total regulatory assets		$	1,019	$	794
Reflected as:
Current assets		$	291	$	48
Noncurrent assets		728		746
Total regulatory assets		$	1,019	$	794

(1)Represents amounts not yet recognized as a component of net periodic benefit cost that are expected to be included in regulated rates when recognized.

Nevada Power had regulatory assets not earning a return on investment of $371 million and $288 million as of December 31, 2021 and 2020, respectively. The regulatory assets not earning a return on investment primarily consist of merger costs from the 1999 merger, AROs, deferred operating costs, a portion of the employee benefit plans, losses on reacquired debt and deferred energy costs.

Regulatory Liabilities

Regulatory liabilities represent amounts that are expected to be returned to customers in future periods. Nevada Power's regulatory liabilities reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):

	Weighted
	Average
	Remaining Life	2021		2020
Deferred income taxes(1)	Various	$	603	$	647
Cost of removal(2)	31 years	348		340
Other	Various	198		226
Total regulatory liabilities		$	1,149	$	1,213
Reflected as:
Current liabilities		$	49	$	50
Noncurrent liabilities		1,100		1,163
Total regulatory liabilities		$	1,149	$	1,213

(1)Amounts primarily represent income tax liabilities related to the federal tax rate change from 35% to 21% that are probable to be passed on to customers, offset by income tax benefits related to accelerated tax depreciation and certain property-related basis differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse.

(2)Amounts represent estimated costs, as accrued through depreciation rates and exclusive of ARO liabilities, of removing regulated property, plant and equipment in accordance with accepted regulatory practices.

Deferred Energy

Nevada statutes permit regulated utilities to adopt deferred energy accounting procedures. The intent of these procedures is to ease the effect on customers of fluctuations in the cost of purchased natural gas, fuel and electricity and are subject to annual prudency review by the PUCN. Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates that excess is not recorded as a current expense on the Consolidated Statements of Operations but rather is deferred and recorded as a regulatory asset on the Consolidated Balance Sheets and would be included in the table above as deferred energy costs. Conversely, a regulatory liability is recorded to the extent fuel and purchased power costs recoverable through current rates exceed actual fuel and purchased power costs and is included in the table above as deferred energy costs. These excess amounts are reflected in quarterly adjustments to rates and recorded as cost of fuel, energy and capacity in future time periods.

Natural Disaster Protection Plan ("NDPP")

In March 2021, Nevada Power filed an application seeking recovery of the 2020 expenditures, approval for an update to the initial NDPP that was ordered by the PUCN and filed their first amendment to the 2020 NDPP. A hearing related to the application for approval of the first amendment to the 2020 NDPP was held in June 2021. Nevada Power filed a partial-party stipulation resolving all issues. One of the intervening parties filed an opposition to the partial-party stipulation and other intervenors filed legal briefs. The partial-party stipulation was approved by the PUCN in June 2021 with the lone dissenting party retaining the right to argue a single issue in future proceedings with the primary issue being a single statewide rate as a cost recovery mechanism. In July 2021, a hearing was held on the cost recovery of 2020 expenditures. In September 2021, the PUCN issued an order, approving the recovery of the 2020 expenditures with adjustments for vegetation management, inspections and corrections and rate structure. Certain vegetation management expenditures were to be removed from the NDPP rate and deemed to be recovered through the general three-year regulatory rate review process. A portion of the inspections and corrections were deferred to seek recovery in a future NDPP rate filing. Lastly, the order approved cost recovery based on a hybrid rate calculation comprised of a statewide rate component for operating costs and a service territory specific rate component for capital costs. In September 2021, Nevada Power and one of the intervening parties filed petitions for reconsideration that were granted by the PUCN. In January 2022, the PUCN issued an order reaffirming its order from September 2021.

Regulatory Rate Review

In June 2020, Nevada Power filed an electric regulatory rate review with the PUCN. The filing supported an annual revenue reduction of $96 million but requested an annual revenue reduction of $120 million. In September 2020, Nevada Power filed an all-party settlement for the electric regulatory rate review. The settlement resolved all but one issue and provided for an annual revenue reduction of $93 million and required Nevada Power to issue a $120 million one-time bill credit, composed primarily of existing regulatory liabilities, to customers beginning in October 2020. The continuation of the earning sharing mechanism was the one issue that was not addressed in the settlement. In October 2020, the PUCN held a hearing on the continuation of the earning sharing mechanism and issued an interim order accepting the settlement and requiring the one-time bill credit be issued to customers. The $120 million one-time bill credit was issued to customers in the fourth quarter of 2020. In December 2020, the PUCN issued a final order directing Nevada Power to continue the earning sharing mechanism subject to any modifications made to the earning sharing mechanism pursuant to an alternative rate-making ruling and to use the weather normalization methodology adopted for Sierra Pacific in its 2019 regulatory rate review. The new rates were effective on January 1, 2021.

Energy Efficiency Program Rates ("EEPR") and Energy Efficiency Implementation Rates ("EEIR")

EEPR was established to allow Nevada Power to recover the costs of implementing energy efficiency programs and EEIR was established to offset the negative impacts on revenue associated with the successful implementation of energy efficiency programs. These rates change once a year in the utility's annual DEAA application based on energy efficiency program budgets prepared by Nevada Power and approved by the PUCN in integrated resource plan proceedings. When Nevada Power's regulatory earned rate of return for a calendar year exceeds the regulatory rate of return used to set base tariff general rates, it is obligated to refund energy efficiency implementation revenue previously collected for that year. In March 2021, Nevada Power filed an application to reset the EEIR and EEPR and to refund the EEIR revenue received in 2020, including carrying charges. In August 2021, the PUCN issued an order accepting a stipulation requiring Nevada Power to refund the 2020 revenue and reset the rates as filed effective October 1, 2021. The EEIR liability for Nevada Power is $8 million, which is included in current regulatory liabilities on the Consolidated Balance Sheets as of December 31, 2021 and 2020.

SPPC

Schedule Of Regulatory Assets and Liabilities [Line Items]

Regulatory Matters

Regulatory Matters

Regulatory Assets

Regulatory assets represent costs that are expected to be recovered in future rates. Sierra Pacific's regulatory assets reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):

	Weighted
	Average
	Remaining Life	2021		2020
Deferred energy costs	1 year	$	107	$	22
Merger costs from 1999 merger	25 years	66		68
Natural disaster protection plan	1 year	62		45
Employee benefit plans(1)	8 years	46		81
Unrealized loss on regulated derivative contracts	1 year	35		2
Deferred operating costs	8 years	31		27
Abandoned projects	5 years	19		22
Other	Various	74		67
Total regulatory assets		$	440	$	334
Reflected as:
Current assets		$	177	$	67
Noncurrent assets		263		267
Total regulatory assets		$	440	$	334

(1)Represents amounts not yet recognized as a component of net periodic benefit cost that are expected to be included in regulated rates when recognized.

Sierra Pacific had regulatory assets not earning a return on investment of $158 million and $149 million as of December 31, 2021 and 2020, respectively. The regulatory assets not earning a return on investment primarily consist of merger costs from the 1999 merger, a portion of the employee benefit plans, losses on reacquired debt, AROs and legacy meters.

Regulatory Liabilities

Regulatory liabilities represent amounts that are expected to be returned to customers in future periods. Sierra Pacific's regulatory liabilities reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):

	Weighted
	Average
	Remaining Life	2021		2020
Deferred income taxes(1)	Various	$	234	$	249
Cost of removal(2)	36 years	201		197
Other	Various	28		51
Total regulatory liabilities		$	463	$	497
Reflected as:
Current liabilities		$	19	$	34
Noncurrent liabilities		444		463
Total regulatory liabilities		$	463	$	497

(1)Amounts primarily represent income tax liabilities related to the federal tax rate change from 35% to 21% that are probable to be passed on to customers, offset by income tax benefits related to accelerated tax depreciation and certain property-related basis differences and other various differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse.

(2)Amounts represent estimated costs, as accrued through depreciation rates and exclusive of ARO liabilities, of removing regulated property, plant and equipment in accordance with accepted regulatory practices.

Deferred Energy

Nevada statutes permit regulated utilities to adopt deferred energy accounting procedures. The intent of these procedures is to ease the effect on customers of fluctuations in the cost of purchased natural gas, fuel and electricity and are subject to annual prudency review by the PUCN. Under deferred energy accounting, to the extent actual fuel and purchased power costs exceed fuel and purchased power costs recoverable through current rates that excess is not recorded as a current expense on the Consolidated Statements of Operations but rather is deferred and recorded as a regulatory asset on the Consolidated Balance Sheets and would be included in the table above as deferred energy costs. Conversely, a regulatory liability is recorded to the extent fuel and purchased power costs recoverable through current rates exceed actual fuel and purchased power costs and is included in the table above as deferred energy costs. These excess amounts are reflected in quarterly adjustments to rates and recorded as cost of fuel, energy and capacity in future time periods.

Natural Disaster Protection Plan ("NDPP")

In March 2021, Sierra Pacific filed an application seeking recovery of the 2020 expenditures, approval for an update to the initial NDPP that was ordered by the PUCN and filed their first amendment to the 2020 NDPP. A hearing related to the application for approval of the first amendment to the 2020 NDPP was held in June 2021. Sierra Pacific filed a partial-party stipulation resolving all issues. One of the intervening parties filed an opposition to the partial-party stipulation and other intervenors filed legal briefs. The partial-party stipulation was approved by the PUCN in June 2021 with the lone dissenting party retaining the right to argue a single issue in future proceedings with the primary issue being a single statewide rate as a cost recovery mechanism. In July 2021, a hearing was held on the cost recovery of 2020 expenditures. In September 2021, the PUCN issued an order, approving the recovery of the 2020 expenditures with adjustments for vegetation management, inspections and corrections and rate structure. Certain vegetation management expenditures were to be removed from the NDPP rate and deemed to be recovered through the general three-year regulatory rate review process. A portion of the inspections and corrections were deferred to seek recovery in a future NDPP rate filing. Lastly, the order approved cost recovery based on a hybrid rate calculation comprised of a statewide rate component for operating costs and a service territory specific rate component for capital costs. In September 2021, Sierra Pacific and one of the intervening parties filed petitions for reconsideration that were granted by the PUCN. In January 2022, the PUCN issued an order reaffirming its order from September 2021.

Energy Efficiency Program Rates ("EEPR") and Energy Efficiency Implementation Rates ("EEIR")

EEPR was established to allow Sierra Pacific to recover the costs of implementing energy efficiency programs and EEIR was established to offset the negative impacts on revenue associated with the successful implementation of energy efficiency programs. These rates change once a year in the utility's annual DEAA application based on energy efficiency program budgets prepared by Sierra Pacific. When Sierra Pacific's regulatory earned rate of return for a calendar year exceeds the regulatory rate of return used to set base tariff general rates, it is obligated to refund energy efficiency implementation revenue previously collected for that year. In March 2021, Sierra Pacific filed an application to reset the EEIR and EEPR and to refund the EEIR revenue received in 2020, including carrying charges. In August 2021, the PUCN issued an order accepting a stipulation requiring Sierra Pacific to refund the 2020 revenue and reset the rates as filed effective October 1, 2021.The EEIR liability for Sierra Pacific is $1 million and $2 million, which is included in current regulatory liabilities on the Consolidated Balance Sheets as of December 31, 2021 and 2020, respectively.

EEGH

Schedule Of Regulatory Assets and Liabilities [Line Items]

Regulatory Matters

Regulatory Matters

Regulatory Assets

Regulatory assets represent costs that are expected to be recovered in future regulated rates. Eastern Energy Gas' regulatory assets reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):

	Weighted Average Remaining Life	2021		2020
Employee benefit plans(1)	14 years	$	62	$	70
Other	Various	12		12
Total regulatory assets		$	74	$	82
Reflected as:
Other current assets		$	6	$	8
Other assets		68		74
Total regulatory assets		$	74	$	82

(1)Represents costs expected to be recovered through future rates generally over the expected remaining service period of plan participants by certain rate-regulated subsidiaries.

Eastern Energy Gas had regulatory assets not earning a return on investment of $8 million and $10 million as of December 31, 2021 and 2020, respectively.

Regulatory Liabilities

Regulatory liabilities represent income to be recognized or amounts expected to be returned to customers in future periods. Eastern Energy Gas' regulatory liabilities reflected on the Consolidated Balance Sheets consist of the following as of December 31 (in millions):

	Weighted Average Remaining Life	2021		2020
Income taxes refundable through future rates(1)	Various	$	468	$	473
Other postretirement benefit costs(2)	Various	116		115
Cost of removal(3)	44 years	73		88
Other	Various	28		33
Total regulatory liabilities		$	685	$	709
Reflected as:
Current liabilities		$	40	$	40
Noncurrent liabilities		645		669
Total regulatory liabilities		$	685	$	709

(1)Amounts primarily represent income tax liabilities related to the federal tax rate change from 35% to 21% that are probable to be passed on to customers, offset by income tax benefits related to certain property-related basis differences and other various differences that were previously passed on to customers and will be included in regulated rates when the temporary differences reverse.

(2)Reflects a regulatory liability for the collection of postretirement benefit costs allowed in rates in excess of expense incurred.

(3)Amounts represent estimated costs, as accrued through depreciation rates and exclusive of ARO liabilities, of removing regulated property, plant and equipment in accordance with accepted regulatory practices.

Regulatory Matters

Eastern Gas Transmission and Storage, Inc.

In September 2021, Eastern Gas Transmission and Storage, Inc. ("EGTS") filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective November 1, 2021. EGTS' previous general rate case was settled in 1998. EGTS proposed an annual cost-of-service of approximately $1.1 billion, and requested increases in various rates, including general system storage rates by 85% and general system transportation rates by 60%. In October 2021, the FERC issued an order that accepted the November 1, 2021 effective date for certain changes in rates, while suspending the other changes for five months following the proposed effective date, until April 1, 2022, subject to refund and the outcome of hearing procedures. This matter is pending.

In July 2017, the FERC audit staff communicated to EGTS that it had substantially completed an audit of EGTS' compliance with the accounting and reporting requirements of the FERC's Uniform System of Accounts and provided a description of matters and preliminary recommendations. In November 2017, the FERC audit staff issued its audit report. In December 2017, EGTS provided its response to the audit report. EGTS requested FERC review of the contested findings and submitted its plan for compliance with the uncontested portions of the report. EGTS reached resolution of certain matters with the FERC in the fourth quarter of 2018. EGTS recognized a charge for a disallowance of plant, originally established beginning in 2012, for the resolution of one matter with the FERC. In December 2020, the FERC issued a final ruling on the remaining matter, which resulted in a $43 million ($31 million after-tax) charge for disallowance of capitalized AFUDC, recorded within operations and maintenance expense in the Consolidated Statement of Operations. As a condition of the December 2020 ruling, EGTS filed its proposed accounting entries and supporting documentation with the FERC during the second quarter of 2021. During the finalization of these entries, EGTS refined the estimated charge for disallowance of capitalized AFUDC, which resulted in a reduction to the estimated charge of $11 million ($8 million after-tax) that was recorded in operations and maintenance expense in the Consolidated Statement of Operations in the second quarter of 2021. In September 2021, the FERC approved EGTS' accounting entries and supporting documentation.

In December 2014, EGTS entered into a precedent agreement with Atlantic Coast Pipeline, LLC ("Atlantic Coast Pipeline") for the project previously intended for EGTS to provide approximately 1,500,000 decatherms ("Dth") of firm transportation service to various customers in connection with the Atlantic Coast Pipeline project ("Supply Header Project"). As a result of the cancellation of the Atlantic Coast Pipeline project, in the second quarter of 2020 Eastern Energy Gas recorded a charge of $482 million ($359 million after-tax) in operations and maintenance expense in its Consolidated Statement of Operations associated with the probable abandonment of a significant portion of the project as well as the establishment of a $75 million ARO. In the third quarter of 2020, Eastern Energy Gas recorded an additional charge of $10 million ($7 million after-tax) associated with the probable abandonment of a significant portion of the project and a $29 million ($20 million after-tax) benefit from a revision to the previously established ARO, both of which were recorded in operations and maintenance expense in Eastern Energy Gas' Consolidated Statement of Operations. As EGTS evaluates its future use, approximately $40 million remains within property, plant and equipment for a potential modified project.

In January 2018, EGTS filed an application to request FERC authorization to construct and operate certain facilities located in Ohio and Pennsylvania for the Sweden Valley project. In June 2019, EGTS withdrew its application for the project due to certain regulatory delays. As a result of the project abandonment, during the second quarter of 2019, EGTS recorded a charge of $13 million ($10 million after-tax), included in operations and maintenance expenses in the Consolidated Statement of Operations.

Cove Point

In January 2020, pursuant to the terms of a previous settlement, Cove Point filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective March 1, 2020. Cove Point proposed an annual cost-of-service of $182 million. In February 2020, FERC approved suspending the changes in rates for five months following the proposed effective date, until August 1, 2020, subject to refund. In November 2020, Cove Point reached an agreement in principle with the active participants in the general rate case proceeding. Under the terms of the agreement in principle, Cove Point's rates effective August 1, 2020 result in an increase to annual revenues of $4 million and a decrease in annual depreciation expense of $1 million, compared to the rates in effect prior to August 1, 2020. The interim settlement rates were implemented November 1, 2020, and Cove Point's provision for rate refunds for August 2020 through October 2020 totaled $7 million. The agreement in principle was reflected in a stipulation and agreement filed with the FERC in January 2021. In March 2021, the FERC approved the stipulation and agreement and the rate refunds to customers were processed in late April 2021.