If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the ~~registrant is~~registrants are a shell company (as defined in Rule 12b-2 of the Exchange Act).

CONSOLIDATED ~~STATEMENTS OF COMPREHENSIVE INCOME~~

BALANCE SHEETS (Unaudited)

Three Months Ended June 30,

Six Months Ended June 30,

2020

2019

2020

2019

(millions)

Net income (loss) including noncontrolling interests

$
(1,132
)

$
58

$
(1,371
)

$
(619
)
Other comprehensive income (loss), net of taxes:

Net deferred gains (losses) on derivatives-hedging activities⁽¹⁾

2

(78
)

(264
)

(102
)
Changes in unrealized net gains (losses) on investment
securities⁽²⁾

19

13

28

29

Changes in net unrecognized pension and other postretirement
benefit costs⁽³⁾

(1
)

113

(1
)

113

Amounts reclassified to net income (loss):

Net derivative (gains) losses-hedging activities⁽⁴⁾

5

(21
)

27

(52
)
Net realized (gains) losses on investment securities⁽⁵⁾

(5
)

(1
)

(14
)

(1
)
Net pension and other postretirement benefit costs⁽⁶⁾

18

22

37

30

Total other comprehensive income (loss)

38

48

(187
)

17

Comprehensive income (loss) including noncontrolling interests

(1,094
)

106

(1,558
)

(602
)
Comprehensive income attributable to noncontrolling interests

37

4

68

7

Comprehensive income (loss) attributable to Dominion Energy

$
(1,131
)

$
102

$
(1,626
)

$
(609
)

~~(1)~~

Net of $(4) million and $27 million tax for the three months ended June 30, 2020 and 2019, respectively, and net of $89 million and $32 million tax for the six months ended June 30, 2020 and 2019, respectively.

(continued)

~~(2)~~

Net of $(6) million and $(5) million tax for the three months ended June 30, 2020 and 2019, respectively, and net of $(10) million and $(11) million tax for the six months ended June 30, 2020 and 2019, respectively.

(Amounts in millions)

~~(3)~~

Net of $3 million and $(49) million tax for the three months ended June 30, 2020 and 2019, respectively, and net of $3 million and $(49) million tax for the six months ended June 30, 2020 and 2019 respectively


	As of
	March 31,		December 31,
	2021		2020
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	1,548	$	1,867
Accrued interest	642		555
Accrued property, income and other taxes	515		582
Accrued employee expenses	412		383
Short-term debt	2,699		2,286
Current portion of long-term debt	2,011		1,839
Other current liabilities	1,948		1,626
Total current liabilities	9,775		9,138

BHE senior debt	12,999		12,997
BHE junior subordinated debentures	100		100
Subsidiary debt	34,351		34,930
Regulatory liabilities	7,355		7,221
Deferred income taxes	11,630		11,775
Other long-term liabilities	4,261		4,178
Total liabilities	80,471		80,339

Commitments and contingencies (Note 9)			0

Equity:
BHE shareholders' equity:
Preferred stock - 100 shares authorized, $0.01 par value, 4 shares issued and outstanding	3,750		3,750
Common stock - 115 shares authorized, 0 par value, 76 shares issued and outstanding	0		0
Additional paid-in capital	6,377		6,377
Long-term income tax receivable	(658)		(658)
Retained earnings	35,060		35,093
Accumulated other comprehensive loss, net	(1,440)		(1,552)
Total BHE shareholders' equity	43,089		43,010
Noncontrolling interests	3,962		3,967
Total equity	47,051		46,977

Total liabilities and equity	$	127,522	$	127,316

~~(4)~~Net of $(2) million and $8 million tax for the three months ended June 30, 2020 and 2019, respectively, and net of $(9) million and $18 million tax for the six months ended June 30, 2020 and 2019, respectively.

~~(5)~~Net of $— million and $— million tax for the three months ended June 30, 2020 and 2019, respectively, and net of $4 million and $— million tax for the six months ended June 30, 2020 and 2019, respectively.

~~(6)~~Net of $(8) million and $3 million tax for the three months ended June 30, 2020 and 2019 respectively, and net of $(13) million and $(11) million tax for the six months ended June 30, 2020 and 2019, respectively.

The accompanying notes are an integral part of ~~Dominion Energy’s Consolidated Financial Statements.~~

these consolidated financial statements.

~~DOMINION~~

BERKSHIRE HATHAWAY ENERGY ~~INC.~~

COMPANY AND SUBSIDIARIES

CONSOLIDATED ~~BALANCE SHEETS~~

STATEMENTS OF OPERATIONS (Unaudited)

June 30, 2020

December 31, 2019⁽¹⁾

(millions)

ASSETS

Current Assets

Cash and cash equivalents

$
675

$
166

Customer receivables (less allowance for doubtful accounts of $44 and $20)

2,040

2,278

Other receivables (less allowance for doubtful accounts of $3 at both dates)⁽²⁾

233

367

Inventories

1,735

1,742

Prepayments

589

328

Regulatory assets

616

879

Other

236

328

Total current assets

6,124

6,088

Investments

Nuclear decommissioning trust funds

6,018

6,192

Investment in equity method affiliates

584

1,646

Other

382

379

Total investments

6,984

8,217

Property, Plant and Equipment

Property, plant and equipment

96,527

97,466

Accumulated depreciation, depletion and amortization

(28,547
)

(28,384
)
Total property, plant and equipment, net

67,980

69,082

Deferred Charges and Other Assets

Goodwill

8,946

8,946

Regulatory assets

9,438

7,687

Other

4,256

3,803

Total deferred charges and other assets

22,640

20,436

Total assets

$
103,728

$
103,823

~~(1)~~

~~Dominion Energy’s Consolidated Balance Sheet at December 31, 2019 has been derived from the audited Consolidated Balance Sheet at that date.~~

~~(2)~~

~~See Note 10 for amounts attributable to related parties.~~

(Amounts in millions)


	Three-Month Periods
	Ended March 31,
		2021		2020
Operating revenue:
Energy		$	4,849	$	3,634
Real estate		1,232		893
Total operating revenue		6,081		4,527

Operating expenses:
Energy:
Cost of sales		1,569		1,038
Operations and maintenance		934		737
Depreciation and amortization		915		809
Property and other taxes		210		151
Real estate		1,120		873
Total operating expenses		4,748		3,608

Operating income		1,333		919

Other income (expense):
Interest expense		(530)		(483)
Capitalized interest		14		17
Allowance for equity funds		26		34
Interest and dividend income		21		20
(Losses) gains on marketable securities, net		(1,118)		27
Other, net		8		(27)
Total other income (expense)		(1,579)		(412)

(Loss) income before income tax benefit and equity loss		(246)		507
Income tax benefit		(535)		(184)
Equity loss		(179)		(18)
Net income		110		673
Net income attributable to noncontrolling interests		106		3
Net income attributable to BHE shareholders		4		670
Preferred dividends		38		0
(Loss) earnings on common shares		$	(34)	$	670

The accompanying notes are an integral part of ~~Dominion Energy’s Consolidated Financial Statements.~~

these consolidated financial statements.

~~DOMINION~~

BERKSHIRE HATHAWAY ENERGY ~~INC.~~

COMPANY AND SUBSIDIARIES

CONSOLIDATED ~~BALANCE SHEETS—(Continued)~~

STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

June 30, 2020

December 31, 2019⁽¹⁾

(millions)

LIABILITIES AND EQUITY

Current Liabilities

Securities due within one year

$
2,799

$
3,162

Supplemental 364-Day credit facility borrowings

225

—

Short-term debt

386

911

Accounts payable

797

1,115

Accrued interest, payroll and taxes

1,011

1,323

Regulatory liabilities

749

497

Reserves for SCANA legal proceedings

538

696

Derivative liabilities

586

408

Other⁽²⁾

2,446

1,827

Total current liabilities

9,537

9,939

Long-Term Debt

Long-term debt

33,844

30,313

Junior subordinated notes

2,858

3,406

Other

444

105

Total long-term debt

37,146

33,824

Deferred Credits and Other Liabilities

Deferred income taxes and investment tax credits

5,921

6,277

Regulatory liabilities

10,680

11,001

Derivative liabilities

748

332

Other⁽²⁾

8,812

8,417

Total deferred credits and other liabilities

26,161

26,027

Total liabilities

72,844

69,790

Commitments and Contingencies (see Note 17)

Equity

Preferred stock (See Note 16)

2,387

2,387

Common stock – no par⁽³⁾

23,984

23,824

Retained earnings

4,480

7,576

Accumulated other comprehensive loss

(1,980
)

(1,793
)
Total shareholders' equity

28,871

31,994

Noncontrolling interests

2,013

2,039

Total equity

30,884

34,033

Total liabilities and equity

$
103,728

$
103,823

(Amounts in millions)

~~(1) Dominion Energy’s Consolidated Balance Sheet at December 31, 2019 has been derived from the audited Consolidated Balance Sheet at that date.~~

~~(2) See Note 10 for amounts attributable to related parties.~~

~~(3) 1.8 billion shares authorized; 840 million shares and 838 million shares outstanding at June 30, 2020 and December 31, 2019, respectively.~~


	Three-Month Periods
	Ended March 31,
		2021		2020

Net income		$	110	$	673

Other comprehensive income (loss), net of tax:
Unrecognized amounts on retirement benefits, net of tax of $4 and $11		7		34
Foreign currency translation adjustment		91		(548)
Unrealized gains (losses) on cash flow hedges, net of tax of $5 and $(10)		14		(33)
Total other comprehensive income (loss), net of tax		112		(547)

Comprehensive income		222		126
Comprehensive income attributable to noncontrolling interests		106		3
Comprehensive income attributable to BHE shareholders		$	116	$	123

The accompanying notes are an integral part of ~~Dominion Energy’s Consolidated Financial Statements.~~

these consolidated financial statements.

~~DOMINION~~

BERKSHIRE HATHAWAY ENERGY ~~INC.~~

COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY ~~- QUARTER-TO-DATE~~

(Unaudited)

Preferred Stock

Common Stock

Dominion Energy Shareholders

Total

Shares

Amount

Shares

Amount

Retained Earnings

AOCI

Shareholders'
Equity

Noncontrolling
Interests

Total
Equity

(millions, except per share amounts)

March 31, 2019

—

$
—

802

$
20,834

$
7,806

$
(1,731
)

$
26,909

$
690

$
27,599

Net income including noncontrolling interests

54

54

4

58

Issuance of stock

2

1,596

1

78

1,674

1,674

Stock purchase contract component of 2019 Equity Units⁽¹⁾

(264
)

(264
)

(264
)
Stock awards (net of change in unearned compensation)

12

12

12

Dividends ($0.9175 per common share) and distributions

(736
)

(736
)

(10
)

(746
)
Other comprehensive income, net of tax

48

48

48

June 30, 2019

2

$
1,596

803

$
20,660

$
7,124

$
(1,683
)

$
27,697

$
684

$
28,381

March 31, 2020

2

$
2,387

839

$
23,902

$
6,455

$
(2,018
)

$
30,726

$
2,026

$
32,752

Net income (loss) including noncontrolling interests

(1,169
)

(1,169
)

37

(1,132
)
Issuance of stock

1

70

70

70

Stock awards (net of change in unearned compensation)

13

13

13

Preferred stock dividends⁽¹⁾

(16
)

(16
)

(16
)
Common stock dividends ($0.940 per share) and distributions

(789
)

(789
)

(50
)

(839
)
Other comprehensive income, net of tax

38

38

38

Other

(1
)

(1
)

(2
)

(2
)
June 30, 2020

2

$
2,387

840

$
23,984

$
4,480

$
(1,980
)

$
28,871

$
2,013

$
30,884

(Amounts in millions)

~~(1) See Note 16 for further information.~~


	BHE Shareholders' Equity
							Long-term				Accumulated
					Additional		Income				Other
	Preferred		Common		Paid-in		Tax		Retained		Comprehensive		Noncontrolling		Total
	Stock		Stock		Capital		Receivable		Earnings		Loss, Net		Interests		Equity








Balance, December 31, 2019	$	0	$	0	$	6,389	$	(530)	$	28,296	$	(1,706)	$	129	$	32,578
Net income	—		0		0		—		670		0		3		673
Other comprehensive loss	—		0		0		—		0		(547)		0		(547)
Common stock purchases	—		0		(6)		—		(120)		0		0		(126)
Distributions	—		0		0		—		0		0		(5)		(5)
Other equity transactions	—		0		(1)		—		0		0		0		(1)
Balance, March 31, 2020	$	0	$	0	$	6,382	$	(530)	$	28,846	$	(2,253)	$	127	$	32,572










Balance, December 31, 2020	$	3,750	$	0	$	6,377	$	(658)	$	35,093	$	(1,552)	$	3,967	$	46,977
Net income	—		0		0		—		4		0		106		110
Other comprehensive income	—		0		0		—		0		112		0		112
Preferred stock dividend	—		—		—		—		(38)		—		—		(38)

Distributions	—		0		0		0		0		0		(113)		(113)

Other equity transactions	—		0		0		0		1		0		2		3
Balance, March 31, 2021	$	3,750	$	0	$	6,377	$	(658)	$	35,060	$	(1,440)	$	3,962	$	47,051

The accompanying notes are an integral part of ~~Dominion Energy’s Consolidated Financial Statements.~~

these consolidated financial statements.

~~DOMINION~~

BERKSHIRE HATHAWAY ENERGY ~~INC.~~

COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF ~~EQUITY - YEAR-TO-DATE~~

CASH FLOWS (Unaudited)

Preferred Stock

Common Stock

Dominion Energy Shareholders

Total

Shares

Amount

Shares

Amount

Retained Earnings

AOCI

Shareholders'
Equity

Noncontrolling
Interests

Total
Equity

(millions, except per share amounts)

��

December 31, 2018

—

$
—

681

$
12,588

$
9,219

$
(1,700
)

$
20,107

$
1,941

$
22,048

Net income (loss) including noncontrolling interests

(626
)

(626
)

7

(619
)
Issuance of stock

2

1,596

4

325

1,921

1,921

Stock purchase contract component of 2019 Equity Units⁽¹⁾

(264
)

(264
)

(264
)
Acquisition of SCANA

96

6,818

6,818

6,818

Acquisition of public interest in Dominion Energy Midstream

22

1,181

1,181

(1,221
)

(40
)
Stock awards (net of change in unearned compensation)

12

12

12

Dividends ($1.835 per common share) and distributions

(1,469
)

(1,469
)

(43
)

(1,512
)
Other comprehensive income, net of tax

17

17

17

June 30, 2019

2

$
1,596

803

$
20,660

$
7,124

$
(1,683
)

$
27,697

$
684

$
28,381

December 31, 2019

2

$
2,387

838

$
23,824

$
7,576

$
(1,793
)

$
31,994

$
2,039

$
34,033

Cumulative-effect of changes in accounting principles

(48
)

(48
)

(48
)
Net income (loss) including noncontrolling interests

(1,439
)

(1,439
)

68

(1,371
)
Issuance of stock

2

148

148

148

Stock awards (net of change in unearned compensation)

13

13

13

Preferred stock dividends⁽¹⁾

(32
)

(32
)

(32
)
Common stock dividends ($1.880 per share) and distributions

(1,577
)

(1,577
)

(94
)

(1,671
)
Other comprehensive loss, net of tax

(187
)

(187
)

(187
)
Other

(1
)

(1
)

(1
)
June 30, 2020

2

$
2,387

840

$
23,984

$
4,480

$
(1,980
)

$
28,871

$
2,013

$
30,884

(Amounts in millions)


	Three-Month Periods
	Ended March 31,
	2021		2020
Cash flows from operating activities:
Net income	$	110	$	673
Adjustments to reconcile net income to net cash flows from operating activities:
Losses (gains) on marketable securities, net	1,118		(27)
Depreciation and amortization	927		821
Allowance for equity funds	(26)		(34)
Equity loss, net of distributions	221		29
Changes in regulatory assets and liabilities	(9)		0
Deferred income taxes and amortization of investment tax credits	(135)		47
Other, net	9		63
Changes in other operating assets and liabilities, net of effects from acquisitions:
Trade receivables and other assets	(249)		(118)
Derivative collateral, net	14		(19)
Pension and other postretirement benefit plans	(21)		(23)
Accrued property, income and other taxes, net	(453)		(364)
Accounts payable and other liabilities	19		117
Net cash flows from operating activities	1,525		1,165

Cash flows from investing activities:
Capital expenditures	(1,295)		(1,356)

Purchases of marketable securities	(128)		(188)
Proceeds from sales of marketable securities	104		180
Equity method investments	(26)		(153)
Other, net	(29)		43
Net cash flows from investing activities	(1,374)		(1,474)

Cash flows from financing activities:
Proceeds from BHE senior debt	0		3,231
Repayments of BHE senior debt	(450)		(350)

Common stock purchases	0		(126)
Proceeds from subsidiary debt	0		1,093
Repayments of subsidiary debt	(26)		(1,347)
Net proceeds from (repayments of) short-term debt	409		(1,109)

Distributions to noncontrolling interests	(115)		(2)
Other, net	(9)		(32)
Net cash flows from financing activities	(191)		1,358

Effect of exchange rate changes	1		(13)

Net change in cash and cash equivalents and restricted cash and cash equivalents	(39)		1,036
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	1,445		1,268
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	1,406	$	2,304

~~1) See Note 16 for further information.~~

The accompanying notes are an integral part of ~~Dominion Energy’s Consolidated Financial Statements.~~

these consolidated financial statements.

~~DOMINION~~

BERKSHIRE HATHAWAY ENERGY ~~INC.~~

~~CONSOLIDATED STATEMENTS OF CASH FLOWS~~

~~(Unaudited)~~

Six Months Ended June 30,

2020

2019

(millions)

Operating Activities

Net loss including noncontrolling interests

$
(1,371
)

$
(619
)
Adjustments to reconcile net loss including noncontrolling interests to net cash
provided by operating activities:

Depreciation, depletion and amortization (including nuclear fuel)

1,497

1,472

Deferred income taxes and investment tax credits

(231
)

107

Provision for refunds and rate credits to electric utility customers

—

953

Impairment of assets and other charges

1,297

1,012

Loss for equity method investee

2,315

—

Charge related to a voluntary retirement program

—

409

Net losses (gains) on nuclear decommissioning trust funds and other investments

117

(371
)
Revision to future ash pond and landfill closure costs

—

(113
)
Other adjustments

4

4

Changes in:

Accounts receivable

396

492

Inventories

7

(14
)
Deferred fuel and purchased gas costs, net

237

120

Prepayments

(193
)

22

Accounts payable

(191
)

(446
)
Accrued interest, payroll and taxes

(313
)

(264
)
Customer deposits

(7
)

(85
)
Margin deposit assets and liabilities

19

113

Other operating assets and liabilities

(447
)

(479
)
Net cash provided by operating activities

3,136

2,313

Investing Activities

Plant construction and other property additions (including nuclear fuel)

(2,915
)

(2,112
)
Cash and restricted cash acquired in the SCANA Combination

—

389

Acquisition of solar development projects

(187
)

(152
)
Proceeds from sales of securities

1,660

882

Purchases of securities

(1,710
)

(888
)
Proceeds from sales of assets and equity method investments

—

196

Contributions to equity method affiliates

(39
)

(132
)
Acquisition of equity method investments

(178
)

—

Other

35

(16
)
Net cash used in investing activities

(3,334
)

(1,833
)
Financing Activities

Issuance (repayment) of short-term debt, net

(525
)

2,040

Issuance of short-term notes

1,125

—

Repayment of short-term notes

(625
)

—

Supplemental 364-Day credit facility borrowings

225

—

Repayment of credit facility borrowings

—

(113
)
Issuance of long-term debt

4,355

798

Repayment of long-term debt, including redemption premiums

(2,210
)

(3,378
)
Issuance of 2019 Equity Units

—

1,582

Issuance of common stock

148

325

Common dividend payments

(1,577
)

(1,469
)
Other

(245
)

(96
)
Net cash provided by (used in) financing activities

671

(311
)
Increase in cash, restricted cash and equivalents

473

169

Cash, restricted cash and equivalents at beginning of period

269

391

Cash, restricted cash and equivalents at end of period

$
742

$
560

Supplemental Cash Flow Information

Significant noncash investing and financing activities:⁽¹⁾⁽²⁾

Accrued capital expenditures

$
346

$
311

Leases⁽³⁾

35

24

COMPANY AND SUBSIDIARIES

~~(1)~~

~~See Note 3 for noncash investing and financing activities related to the SCANA Combination.~~

~~(2)~~

See Note 16 for noncash financing activities related to derivative restructuring, the acquisition of the public interest in Dominion Energy Midstream and the issuance of stock purchase contracts associated with the 2019 Equity Units. See Note 18 to the Consolidated Financial Statements in Dominion Energy’s Annual Report on Form 10-K for the year ended December 31, 2019 for non-cash financing activities related to the remarketing of RSNs.

~~(3) Includes $32 million and $22 million of financing leases at June 30, 2020 and 2019, respectively, and $3 million and $2 million of operating leases at June 30, 2020 and 2019, respectively.~~

~~The accompanying notes are an integral part of Dominion Energy’s Consolidated Financial Statements.~~

~~VIRGINIA ELECTRIC AND POWER COMPANY~~

~~CONSOLIDATED STATEMENTS OF INCOME~~

~~(Unaudited)~~

Three Months Ended June 30,

Six Months Ended June 30,

2020

2019

2020

2019

(millions)

Operating Revenue⁽¹⁾

$
1,805

$
1,938

$
3,735

$
3,903

Operating Expenses

Electric fuel and other energy-related purchases⁽¹⁾

366

536

858

1,132

Purchased (excess) electric capacity

(8
)

13

(17
)

46

Other operations and maintenance:

Affiliated suppliers

80

127

167

213

Other

296

438

627

631

Depreciation and amortization

307

299

618

603

Other taxes

85

90

172

175

Impairment of assets and other charges

44

197

808

743

Total operating expenses

1,170

1,700

3,233

3,543

Income from operations

635

238

502

360

Other income

52

16

—

53

Interest and related charges⁽¹⁾

137

135

263

270

Income before income tax expense

550

119

239

143

Income tax expense

60

19

29

23

Net Income

$
490

$
100

$
210

$
120

~~(1)~~

~~See Note 19 for amounts attributable to affiliates.~~

~~The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.~~

~~VIRGINIA ELECTRIC AND POWER COMPANY~~

~~CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME~~

~~(Unaudited)~~

Three Months Ended June 30,

Six Months Ended June 30,

2020

2019

2020

2019

(millions)

Net income

$
490

$
100

$
210

$
120

Other comprehensive income (loss), net of taxes:

Net deferred gains (losses) on derivatives-hedging activities⁽¹⁾

1

(11
)

(44
)

(18
)
Changes in unrealized net gains (losses) on nuclear
decommissioning trust funds⁽²⁾

6

2

4

4

Amounts reclassified to net income (loss):

Net derivative (gains) losses-hedging activities⁽³⁾

—

1

—

1

Net realized (gains) losses on nuclear decommissioning
trust funds⁽⁴⁾

(2
)

(1
)

(1
)

(1
)
Total other comprehensive income (loss)

5

(9
)

(41
)

(14
)
Comprehensive income

$
495

$
91

$
169

$
106

~~(1)~~

Net of $(1) million and $4 million tax for the three months ended June 30, 2020 and 2019, respectively, and net of $15 million and $6 million tax for the six months ended June 30, 2020 and 2019, respectively.

~~(2)~~

Net of $(1) million and $— million tax for the three months ended June 30, 2020 and 2019, respectively, and net of $(1) million and $(1) million tax for the six months ended June 30, 2020 and 2019, respectively.

~~(3)~~

~~Net of~~$(1) million and $ — million tax for the three months ended June 30, 2020 and 2019, respectively, and net of $ (1) million and $ — million tax for the six months ended June 30, 2020 and 2019, respectively.

~~(4)~~

Net of $2 million and $ — million tax for the three months ended June 30, 2020 and 2019, respectively, and net of $1 million and $ — million tax for the six months ended June 30, 2020 and 2019, respectively.

~~The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.~~

~~VIRGINIA ELECTRIC AND POWER COMPANY~~

~~CONSOLIDATED BALANCE SHEETS~~

~~(Unaudited)~~

June 30, 2020

December 31, 2019⁽¹⁾

(millions)

ASSETS

Current Assets

Cash and cash equivalents

$
37

$
17

Customer receivables (less allowance for doubtful accounts of $20 and $9)

1,184

1,163

Other receivables (less allowance for doubtful accounts of $2 at both dates)

94

106

Affiliated receivables

2

27

Inventories (average cost method)

874

873

Regulatory assets

197

433

Other⁽²⁾

64

57

Total current assets

2,452

2,676

Investments

Nuclear decommissioning trust funds

2,782

2,881

Other

3

3

Total investments

2,785

2,884

Property, Plant and Equipment

Property, plant and equipment

45,273

47,038

Accumulated depreciation and amortization

(13,774
)

(14,156
)
Total property, plant and equipment, net

31,499

32,882

Deferred Charges and Other Assets

Regulatory assets

3,780

1,863

Other⁽²⁾

1,524

1,123

Total deferred charges and other assets

5,304

2,986

Total assets

$
42,040

$
41,428

~~(1)~~

~~Virginia Power’s Consolidated Balance Sheet at December 31, 2019 has been derived from the audited Consolidated Balance Sheet at that date.~~

~~(2)~~

~~See Note 19 for amounts attributable to affiliates.~~

~~The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.~~

~~VIRGINIA ELECTRIC AND POWER COMPANY~~

~~CONSOLIDATED BALANCE SHEETS—(Continued)~~

~~(Unaudited)~~

June 30, 2020

December 31, 2019⁽¹⁾

(millions)

LIABILITIES AND SHAREHOLDER’S EQUITY

Current Liabilities

Securities due within one year

$
7

$
4

Short-term debt

—

243

Accounts payable

305

334

Payables to affiliates

406

210

Affiliated current borrowings

340

107

Accrued interest, payroll and taxes

276

253

Asset retirement obligations

91

340

Regulatory liabilities

296

167

Derivative liabilities⁽²⁾

478

243

Other

598

571

Total current liabilities

2,797

2,472

Long-Term Debt

Long-term debt

12,328

12,325

Finance leases

30

16

Total long-term debt

12,358

12,341

Deferred Credits and Other Liabilities

Deferred income taxes and investment tax credits

2,739

2,962

Asset retirement obligations

3,548

3,241

Regulatory liabilities

4,954

5,074

Other⁽²⁾

1,700

1,349

Total deferred credits and other liabilities

12,941

12,626

Total liabilities

28,096

27,439

Commitments and Contingencies (see Note 17)

Common Shareholder’s Equity

Common stock – no par⁽³⁾

5,738

5,738

Other paid-in capital

1,113

1,113

Retained earnings

7,163

7,167

Accumulated other comprehensive loss

(70
)

(29
)
Total common shareholder’s equity

13,944

13,989

Total liabilities and shareholder’s equity

$
42,040

$
41,428

~~(1)~~

~~Virginia Power’s Consolidated Balance Sheet at December 31, 2019 has been derived from the audited Consolidated Balance Sheet at that date.~~

~~(2)~~

~~See Note 19 for amounts attributable to affiliates.~~

~~(3)~~

~~500,000 shares authorized; 274,723 sharesoutstanding at June 30, 2020 and December 31, 2019.~~

~~The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.~~

~~VIRGINIA ELECTRIC AND POWER COMPANY~~

~~CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER’S EQUITY~~

~~(Unaudited)~~

~~QUARTER-TO-DATE~~

Common Stock

Shares

Amount

Other Paid-In Capital

Retained Earnings

AOCI

Total

(millions, except for shares)

(thousands)

March 31, 2019

275

$
5,738

$
1,113

$
6,110

$
(17
)

$
12,944

Net income

100

100

Dividends

(71
)

(71
)
Other comprehensive loss, net of tax

(9
)

(9
)
June 30, 2019

275

$
5,738

$
1,113

$
6,139

$
(26
)

$
12,964

March 31, 2020

275

$
5,738

$
1,113

$
6,780

$
(75
)

$
13,556

Net income

490

490

Dividends

(107
)

(107
)
Other comprehensive income, net of tax

5

5

June 30, 2020

275

$
5,738

$
1,113

$
7,163

$
(70
)

$
13,944

~~YEAR-TO-DATE~~

Common Stock

Shares

Amount

Other Paid-In Capital

Retained Earnings

AOCI

Total

(millions, except for shares)

(thousands)

December 31, 2018

275

$
5,738

$
1,113

$
6,208

$
(12
)

$
13,047

Net income

120

120

Dividends

(189
)

(189
)
Other comprehensive loss, net of tax

(14
)

(14
)
June 30, 2019

275

$
5,738

$
1,113

$
6,139

$
(26
)

$
12,964

December 31, 2019

275

$
5,738

$
1,113

$
7,167

$
(29
)

$
13,989

Net income

210

210

Dividends

(215
)

(215
)
Other comprehensive loss, net of tax

(41
)

(41
)
Other

1

1

June 30, 2020

275

$
5,738

$
1,113

$
7,163

$
(70
)

$
13,944

~~The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.~~

~~VIRGINIA ELECTRIC AND POWER COMPANY~~

~~CONSOLIDATED STATEMENTS OF CASH FLOWS~~

~~(Unaudited)~~

Six Months Ended June 30,

2020

2019

(millions)

Operating Activities

Net income

$
210

$
120

Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation and amortization (including nuclear fuel)

702

690

Deferred income taxes and investment tax credits

(220
)

(43
)
Revision to future ash pond and landfill closure costs

—

(113
)
Impairment of assets and other charges

806

608

Charge related to a voluntary retirement program

—

190

Other adjustments

2

(51
)
Changes in:

Accounts receivable

1

68

Affiliated receivables and payables

220

(179
)
Inventories

(1
)

(30
)
Prepayments

—

(4
)
Deferred fuel expenses, net

136

153

Accounts payable

(9
)

(35
)
Accrued interest, payroll and taxes

18

14

Net realized and unrealized changes related to derivative activities

(20
)

17

Other operating assets and liabilities

47

(331
)
Net cash provided by operating activities

1,892

1,074

Investing Activities

Plant construction and other property additions

(1,474
)

(1,079
)
Purchases of nuclear fuel

(154
)

(67
)
Acquisition of solar development projects

(19
)

(150
)
Proceeds from sales of securities

530

447

Purchases of securities

(549
)

(478
)
Other

18

(11
)
Net cash used in investing activities

(1,648
)

(1,338
)
Financing Activities

(Repayment) issuance of short-term debt, net

(243
)

986

Issuance (repayment) of affiliated current borrowings, net

233

(153
)
Issuance of long-term debt

105

198

Repayment of long-term debt

(105
)

(589
)
Common dividend payments to parent

(215
)

(189
)
Other

(3
)

(2
)
Net cash provided by (used in) financing activities

(228
)

251

Increase (decrease) in cash, restricted cash and equivalents

16

(13
)
Cash, restricted cash and equivalents at beginning of period

24

38

Cash, restricted cash and equivalents at end of period

$
40

$
25

Supplemental Cash Flow Information

Significant noncash investing activities:

Accrued capital expenditures

$
239

$
193

Financing leases

20

9

~~The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.~~

~~DOMINION ENERGY GAS HOLDINGS, LLC~~

~~CONSOLIDATED STATEMENTS OF INCOME~~

~~(Unaudited)~~

Three Months Ended June 30,

Six Months Ended June 30,

2020

2019

2020

2019

(millions)

Operating Revenue⁽¹⁾

$
510

$
530

$
1,066

$
1,096

Operating Expenses

Purchased (excess) gas⁽¹⁾

—

(3
)

8

9

Other energy-related purchases

1

1

1

1

Other operations and maintenance:

Affiliated suppliers

39

54

79

93

Other

111

156

236

293

Depreciation and amortization

94

92

187

182

Other taxes

35

38

77

78

Impairment of assets and other charges

482

13

482

13

Total operating expenses

762

351

1,070

669

Income (loss) from continuing operations

(252
)

179

(4
)

427

Earnings from equity method investees

8

9

23

22

Other income⁽¹⁾

46

44

95

85

Interest and related charges⁽¹⁾

50

86

108

173

Income (loss) from continuing operations before income tax expense

(248
)

146

6

361

Income tax expense (benefit)

(82
)

23

(30
)

66

Net income (loss) from continuing operations

(166
)

123

36

295

Net income from discontinued operations

—

26

—

80

Net income (loss) including noncontrolling interests

(166
)

149

36

375

Noncontrolling interests

32

30

65

66

Net Income (Loss) attributable to Dominion Energy Gas

$
(198
)

$
119

$
(29
)

$
309

~~(1)~~

~~See Note 19 for amounts attributable to related parties.~~

~~The accompanying notes are an integral part of Dominion Energy Gas’ Consolidated Financial Statements.~~

~~DOMINION ENERGY GAS HOLDINGS, LLC~~

~~CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME~~

~~(Unaudited)~~

Three Months Ended June 30,

Six Months Ended June 30,

2020

2019

2020

2019

(millions)

Net income (loss) including noncontrolling interests

$
(166
)

$
149

$
36

$
375

Other comprehensive income (loss), net of taxes:

Net deferred gains (losses) on derivatives-hedging activities⁽¹⁾

—

(24
)

(91
)

(51
)
Changes in unrecognized pension and other postretirement benefits⁽²⁾

—

29

—

29

Amounts reclassified to net income (loss):

Net derivative (gains) losses-hedging activities⁽³⁾

(2
)

(2
)

4

1

Net pension and other postretirement benefit costs⁽⁴⁾

2

2

3

3

Total other comprehensive income (loss)

—

5

(84
)

(18
)
Comprehensive income (loss) including noncontrolling interests

(166
)

154

(48
)

357

Comprehensive income attributable to noncontrolling interests

32

30

65

65

Comprehensive income (loss) attributable to Dominion Energy Gas

$
(198
)

$
124

$
(113
)

$
292

~~(1)~~

Net of $(1) million and $8 million tax for the three months ended June 30, 2020 and 2019, respectively, and $31 million and $17 million tax for the six months ended June 30, 2020 and 2019, respectively.

~~(2)~~

~~Net of $~~ — ~~million and $(11) million tax for the three months ended June 30, 2020 and 2019, respectively, and $~~ — ~~million and $(11) million tax for the six months ended June 30, 2020 and 2019, respectively.~~

~~(3)~~

~~Net of $~~ — ~~million and $~~— ~~million tax for the three months ended June 30, 2020 and 2019, respectively, and $(2) million and $~~ — ~~million tax for the six months ended June 30, 2020 and 2019, respectively.~~

~~(4)~~

~~Net of $~~ — ~~million and $~~ — ~~million tax for the three months ended June 30, 2020 and 2019, respectively, and $(1) million and $(1) million tax for the six months ended June 30, 2020 and 2019, respectively.~~

~~The accompanying notes are an integral part of Dominion Energy Gas’ Consolidated Financial Statements.~~

~~DOMINION ENERGY GAS HOLDINGS, LLC~~

~~CONSOLIDATED BALANCE SHEETS~~

~~(Unaudited)~~

June 30, 2020

December 31, 2019⁽¹⁾

(millions)

ASSETS

Current Assets

Cash and cash equivalents

$
53

$
27

Customer receivables (less allowance for doubtful accounts of $5 and $2)

151

173

Other receivables⁽²⁾

12

26

Affiliated receivables

77

362

Affiliated notes receivable

263

—

Inventories

130

122

Prepayments

43

73

Gas imbalances⁽²⁾

25

52

Other

23

23

Total current assets

777

858

Investments

Affiliated notes receivable

2,272

3,437

Investment in equity method affiliates

310

312

Total investments

2,582

3,749

Property, Plant and Equipment

Property, plant and equipment

14,899

15,166

Accumulated depreciation and amortization

(3,695
)

(3,538
)
Total property, plant and equipment, net

11,204

11,628

Deferred Charges and Other Assets

Goodwill

1,471

1,471

Other⁽²⁾

1,107

1,078

Total deferred charges and other assets

2,578

2,549

Total assets

$
17,141

$
18,784

~~(1)~~

~~Dominion Energy Gas’ Consolidated Balance Sheet at December 31, 2019 has been derived from the audited Consolidated Balance Sheet at that date.~~

~~(2)~~

~~See Note 19 for amounts attributable to related parties.~~

~~The accompanying notes are an integral part of Dominion Energy Gas’ Consolidated Financial Statements.~~

~~DOMINION ENERGY GAS HOLDINGS, LLC~~

~~CONSOLIDATED BALANCE SHEETS—(Continued)~~

~~(Unaudited)~~

June 30, 2020

December 31, 2019⁽¹⁾

(millions)

LIABILITIES AND EQUITY

Current Liabilities

Securities due within one year

$
1,200

$
700

Short-term debt

—

62

Accounts payable

52

59

Payables to affiliates

159

82

Affiliated current borrowings

314

260

Other⁽²⁾

382

289

Total current liabilities

2,107

1,452

Long-Term Debt

Long-term debt

4,324

4,821

Finance leases

5

5

Total long-term debt

4,329

4,826

Deferred Credits and Other Liabilities

Deferred income taxes and investment tax credits

1,156

1,288

Other

1,093

989

Total deferred credits and other liabilities

2,249

2,277

Total liabilities

8,685

8,555

Commitments and Contingencies (see Note 17)

Equity

Membership interests

7,352

9,031

Accumulated other comprehensive loss

(271
)

(187
)
Total members' equity

7,081

8,844

Noncontrolling interests

1,375

1,385

Total equity

8,456

10,229

Total liabilities and equity

$
17,141

$
18,784

~~(1)~~

~~Dominion Energy Gas’ Consolidated Balance Sheet at December 31, 2019 has been derived from the audited Consolidated Balance Sheet at that date.~~

~~(2)~~

~~See Note 19 for amounts attributable to related parties.~~

~~The accompanying notes are an integral part of Dominion Energy Gas’ Consolidated Financial Statements.~~

~~DOMINION ENERGY GAS HOLDINGS, LLC~~

~~CONSOLIDATED STATEMENTS OF EQUITY~~

~~(Unaudited)~~

~~QUARTER-TO-DATE~~

Predecessor Equity

Membership Interests

AOCI

Total Members' Equity

Noncontrolling Interests

Total

(millions)

March 31, 2019

$
2,938

$
4,682

$
(191
)

$
7,429

$
1,432

$
8,861

Net income

72

47

119

30

149

Dividends and distributions

(153
)

(153
)

(36
)

(189
)
Other comprehensive income, net of tax

5

5

5

Other

2

2

2

June 30, 2019

$
2,859

$
4,729

$
(186
)

$
7,402

$
1,426

$
8,828

March 31, 2020

$
—

$
8,968

$
(271
)

$
8,697

$
1,381

$
10,078

Net income (loss)

(198
)

(198
)

32

(166
)
Dividends and distributions

(1,418
)

(1,418
)

(38
)

(1,456
)
June 30, 2020

$
—

$
7,352

$
(271
)

$
7,081

$
1,375

$
8,456

~~YEAR-TO-DATE~~

Predecessor Equity

Membership Interests

AOCI

Total
Members'
Equity

Noncontrolling Interests

Total

(millions)

December 31, 2018

$
1,804

$
4,566

$
(169
)

$
6,201

$
2,664

$
8,865

Net income

146

163

309

66

375

Acquisition of public interest in Dominion Energy Midstream

1,181

1,181

(1,221
)

(40
)
Dividends and distributions

(266
)

(266
)

(82
)

(348
)
Other comprehensive loss, net of tax

(17
)

(17
)

(1
)

(18
)
Other

(6
)

(6
)

(6
)
June 30, 2019

$
2,859

$
4,729

$
(186
)

$
7,402

$
1,426

$
8,828

December 31, 2019

$
—

$
9,031

$
(187
)

$
8,844

$
1,385

$
10,229

Net income (loss)

(29
)

(29
)

65

36

Dividends and distributions

(1,650
)

(1,650
)

(75
)

(1,725
)
Other comprehensive loss, net of tax

(84
)

(84
)

(84
)
June 30, 2020

$
—

$
7,352

$
(271
)

$
7,081

$
1,375

$
8,456

~~The accompanying notes are an integral part of Dominion Energy Gas’ Consolidated Financial Statements.~~

~~DOMINION ENERGY GAS HOLDINGS, LLC~~

~~CONSOLIDATED STATEMENTS OF CASH FLOWS~~

~~(Unaudited)~~

Six Months Ended June 30,

2020

2019

(millions)

Operating Activities

Net income including noncontrolling interests

$
36

$
375

Adjustments to reconcile net income to net cash provided by operating activities:

Depreciation and amortization

187

227

Deferred income taxes and investment tax credits

(97
)

39

Charge related to a voluntary retirement program

—

73

Impairment of assets and other charges

482

13

Other adjustments

(1
)

15

Changes in:

Accounts receivable

37

88

Affiliated receivables and payables

362

(48
)
Inventories

(8
)

(31
)
Prepayments

30

59

Accounts payable

6

(105
)
Accrued interest, payroll and taxes

(16
)

(55
)
Customer deposits

(1
)

(81
)
Pension and other postretirement benefits

(35
)

(64
)
Other operating assets and liabilities

26

(45
)
Net cash provided by operating activities

1,008

460

Investing Activities

Plant construction and other property additions

(147
)

(341
)
Repayment of loans by affiliates

1,165

—

Advances to affiliates

(263
)

—

Other

(4
)

(12
)
Net cash provided by (used in) investing activities

751

(353
)
Financing Activities

Issuance (repayment) of short-term debt, net

(62
)

240

Issuance (repayment) of affiliated current borrowings, net

54

(11
)
Repayment of long-term debt

—

(300
)
Issuance of affiliated long-term debt

—

395

Repayment of credit facility borrowings

—

(73
)
Dividends and distributions

(1,725
)

(348
)
Other

(1
)

(1
)
Net cash used in financing activities

(1,734
)

(98
)
Increase in cash, restricted cash and equivalents

25

9

Cash, restricted cash and equivalents at beginning of period

39

198

Cash, restricted cash and equivalents at end of period

$
64

$
207

Supplemental Cash Flow Information

Significant noncash investing activities:

Accrued capital expenditures

$
24

$
43

Financing leases

1

6

~~The accompanying notes are an integral part of Dominion Energy Gas’ Consolidated Financial Statements.~~

~~COMBINED~~ NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

~~(Unaudited)~~

~~Note 1. Nature of Operations~~

~~Dominion~~

(1) General

Berkshire Hathaway Energy headquartered in Richmond, Virginia, is one of the nation’s largest producers and transporters of energy. Dominion Energy’s operations are conducted through various subsidiaries, including Virginia Power and Dominion Energy Gas. Dominion Energy’s operations also include DESC, an equity investment in Atlantic Coast Pipeline and regulated gas distribution operations primarily in the eastern and Rocky Mountain regions of the U.S. Dominion Energy’s nonregulated operations include merchant generation and retail energy marketing operations. Virginia Power is a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and northeastern North Carolina. Dominion Energy GasCompany ("BHE") is a holding company that ~~conducts~~owns a highly diversified portfolio of locally managed businesses principally engaged in the energy industry (collectively with its subsidiaries, the "Company") and is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

The Company's operations are organized as 8 business ~~activities~~segments: PacifiCorp and its subsidiaries ("PacifiCorp"), MidAmerican Funding, LLC and its subsidiaries ("MidAmerican Funding") (which primarily consists of MidAmerican Energy Company ("MidAmerican Energy")), NV Energy, Inc. and its subsidiaries ("NV Energy") (which primarily consists of Nevada Power Company and its subsidiaries ("Nevada Power") and Sierra Pacific Power Company and its subsidiaries ("Sierra Pacific")), Northern Powergrid Holdings Company ("Northern Powergrid") (which primarily consists of Northern Powergrid (Northeast) plc and Northern Powergrid (Yorkshire) plc), BHE Pipeline Group, LLC and its subsidiaries (which primarily consists of BHE GT&S, LLC ("BHE GT&S"), Northern Natural Gas Company ("Northern Natural Gas") and Kern River Gas Transmission Company ("Kern River")), BHE Transmission (which consists of BHE Canada Holdings Corporation ("BHE Canada") (which primarily consists of AltaLink, L.P. ("AltaLink")) and BHE U.S. Transmission, LLC), BHE Renewables (which primarily consists of BHE Renewables, LLC and CalEnergy Philippines) and HomeServices of America, Inc. and its subsidiaries ("HomeServices"). The Company, through ~~FERC-regulated~~these locally managed and operated businesses, owns 4 utility companies in the United States serving customers in 11 states, 2 electricity distribution companies in Great Britain, 5 interstate natural gas ~~transmission~~ pipeline companies and ~~underground~~interests in a liquefied natural gas ("LNG") export, import and storage ~~systems~~facility in the ~~eastern~~United States, an electric transmission business in Canada, interests in electric transmission businesses in the United States, a renewable energy business primarily investing in wind, solar, geothermal and ~~Rocky Mountain regions~~hydroelectric projects, the largest residential real estate brokerage firm in the United States and 1 of the ~~U.S., as well as~~largest residential real estate brokerage franchise networks in the ~~Cove Point LNG Facility. In addition, Dominion Energy Gas owns a 50% noncontrolling interest~~United States.

The unaudited Consolidated Financial Statements have been prepared in ~~both Iroquois~~accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and ~~White River Hub. See Note 3 for additional information on~~ the ~~Dominion Energy Gas Restructuring. In July 2020, Dominion Energy entered an agreement to sell substantially all of its gas transmission~~United States Securities and ~~storage operations, including Dominion Energy Gas, to BHE. See Note 3 for additional information.~~

~~Note 2. Significant Accounting Policies~~

~~As permitted by the~~Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the ~~SEC,~~disclosures required by GAAP for annual financial statements. Management believes the ~~Companies’ accompanying~~ unaudited Consolidated Financial Statements contain ~~certain condensed financial information and exclude certain footnote disclosures normally included in annual audited consolidated financial statements prepared in accordance with GAAP. These~~all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements ~~should~~as of March 31, 2021 and for the three-month periods ended March 31, 2021 and 2020. The results of operations for the three-month period ended March 31, 2021 are not necessarily indicative of the results to be ~~read~~expected for the full year.

The preparation of the unaudited Consolidated Financial Statements in ~~conjunction~~conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the unaudited Consolidated Financial Statements and the reported amounts of revenue and expenses during the period. Actual results may differ from the estimates used in preparing the unaudited Consolidated Financial Statements. Note 2 of Notes to Consolidated Financial Statements included in the ~~Companies’~~Company's Annual Report on Form 10-K for the year ended December 31, ~~2019.~~

In2020 describes the ~~Companies’ opinion,~~most significant accounting policies used in the ~~accompanying~~preparation of the unaudited Consolidated Financial Statements contain all adjustments necessary to present fairly their financial position at June 30, 2020, their results of operations and changes in equity for the three and six months ended June 30, 2020 and 2019 and their cash flows for the six months ended June 30, 2020 and 2019. Such adjustments are normal and recurring in nature unless otherwise noted.

The Companies make certain estimates and assumptions in preparing their Consolidated Financial Statements in accordance with GAAP. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses for the periods presented. Actual results may differ from those estimates.

The Companies’ accompanying unaudited Consolidated Financial Statements include, after eliminating intercompany transactions and balances, their accounts, those of their respective majority-owned subsidiaries and non-wholly-owned entities in which they have a controlling financial interest. For certain partnership structures, income is allocated based on the liquidation value of the underlying contractual arrangements. At June 30, 2020, Dominion Energy owns 50% of the voting interests in Four Brothers and Three Cedars and has a controlling financial interest over the entities through its right to control operations. GIP’s ownership interest in Four Brothers and Three Cedars, Terra Nova Renewable Partners’ 33% interest in certain Dominion Energy merchant solar projects, Brookfield’s 25% interest in Cove Point (effective December 2019) and the non-Dominion Energy held interest in Dominion Energy Midstream (through January 2019) are reflected as noncontrolling interest in Dominion Energy’s Consolidated Financial Statements. Terra Nova Renewable Partners has a future option to buy all or a portion of Dominion Energy’s remaining 67% ownership in certain merchant projects upon the occurrence of certain events, none of which are expected to occur in the next 12 months. Brookfield’s 25% interest in Cove Point (effective December 2019) and the public’s ownership interest in Dominion Energy Midstream (through January 2019) are reflected as noncontrolling interest in Dominion Energy Gas’ Consolidated Financial Statements.

The results of operations for interim periods are not necessarily indicative of the results expected for the full year. Information for quarterly periods is affected by seasonal variations in sales, rate changes, electric fuel and other energy-related purchases, purchased gas expenses and other factors.

Certain amounts in the Companies’ 2019 Consolidated Financial Statements and Notes have been reclassified to conform to the 2020 presentation for comparative purposes; however, such reclassifications did not affect the Companies’ net income, total assets, liabilities, equity or cash flows.

~~Amounts disclosed for Dominion Energy are inclusive of Virginia Power and/or Dominion Energy Gas, where applicable.~~ There have been no significant changes ~~from Note 2 to the Consolidated Financial Statements~~ in the ~~Companies’ Annual Report on Form 10-K for~~Company's assumptions regarding significant accounting estimates and policies during the ~~year~~three-month period ended ~~December~~March 31, ~~2019, with the exception~~2021.

(2) Business Acquisition

BHE GT&S Acquisition

Transaction Description

On November 1, 2020, BHE completed its acquisition of substantially all of the ~~items described below.~~

natural gas transmission and storage business of Dominion Energy, Inc. ("DEI") and Dominion Energy Questar Corporation ("Dominion Questar"), exclusive of Dominion Energy Questar Pipeline, LLC and related entities (the "Questar Pipeline Group") (the "GT&S Transaction"). Under the terms of the Purchase and Sale Agreement, dated July 3, 2020 (the "GT&S Purchase Agreement"), BHE paid approximately $2.5 billion in cash, after post-closing adjustments (the "GT&S Cash ~~Restricted Cash~~Consideration"), and ~~Equivalents~~

~~The following table provides~~assumed approximately $5.6 billion of existing indebtedness for borrowed money, including fair value adjustments, for 100% of the equity interests of Eastern Gas Transmission and Storage, Inc. ("EGTS") (formerly known as Dominion Energy Transmission, Inc.) and Carolina Gas Transmission, LLC (formerly known as Dominion Energy Carolina Gas Transmission, LLC); 50% of the equity interests of Iroquois Gas Transmission System L.P. ("Iroquois"); and a ~~reconciliation~~25% economic interest in Cove Point LNG, LP ("Cove Point") (formerly known as Dominion Energy Cove Point LNG, LP), consisting of 100% of the general partnership interest and 25% of the total ~~cash, restricted cash~~limited partnership interests. BHE became the operator of Cove Point after the GT&S Transaction. The GT&S Transaction received clearance under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended ("HSR Approval") in October 2020, and ~~equivalents reported within~~approval by the ~~Companies’ Consolidated Balance Sheets~~Department of Energy with respect to a change in control of Cove Point and the Federal Communications Commission with respect to the ~~corresponding amounts reported within~~transfer of certain licenses earlier in 2020.

On October 5, 2020, DEI and Dominion Questar, as permitted under the ~~Companies’ Consolidated Statements~~terms of ~~Cash Flows~~the GT&S Purchase Agreement, delivered notice to BHE of their election to terminate the GT&S Transaction with respect to the Questar Pipeline Group and, in connection with the execution of the Q-Pipe Purchase Agreement referenced below, to waive the related termination fee under the GT&S Purchase Agreement. Also on October 5, 2020, BHE entered into a second Purchase and Sale Agreement (the "Q-Pipe Purchase Agreement") with Dominion Questar providing for BHE's purchase of the ~~six months ended June 30, 2020 and 2019:~~

Cash, Restricted Cash and Equivalents
at End of Period

Cash, Restricted Cash and Equivalents
at Beginning of Period

June 30, 2020

June 30, 2019

December 31, 2019

December 31, 2018

(millions)

Dominion Energy

Cash and cash equivalents

$
675

$
382

$
166

$
268

Restricted cash and equivalents⁽¹⁾

67

178

103

123

Cash, restricted cash and equivalents shown in the Consolidated Statements of Cash Flows

$
742

$
560

$
269

$
391

Virginia Power

Cash and cash equivalents

$
37

$
17

$
17

$
29

Restricted cash and equivalents⁽¹⁾

3

8

7

9

Cash, restricted cash and equivalents shown in the Consolidated Statements of Cash Flows

$
40

$
25

$
24

$
38

Dominion Energy Gas

Cash and cash equivalents⁽²⁾

$
53

$
195

$
27

$
108

Restricted cash and equivalents ⁽¹⁾

11

12

12

90

Cash, restricted cash and equivalents shown in the Consolidated Statements of Cash Flows

$
64

$
207

$
39

$
198

~~(1)~~

~~Restricted cash and equivalent balances are presented within other current assets in the Companies’ Consolidated Balance Sheets.~~

~~(2)~~

~~At June 30, 2019 and December 31, 2018, Dominion Energy Gas had $12 million and $9 million of cash and cash equivalents included in current assets of discontinued operations, respectively.~~

~~Property, Plant and Equipment~~

~~In January 2019, Virginia Power committed to a plan to retire certain automated metering reading infrastructure associated with its electric operations before the end~~Questar Pipeline Group from Dominion Questar (the "Q-Pipe Transaction") after receipt of ~~its estimated useful life and replace such equipment with more current AMI technology. As a result, Virginia Power recorded a charge of $160 million ($119 million after-tax)~~HSR Approval, which is currently anticipated in the first ~~quarter~~half of ~~2019,~~2021, for a cash purchase price of approximately $1.3 billion (the "Q-Pipe Cash Consideration"), subject to adjustment for cash and indebtedness as of the closing, and the assumption of approximately $430 million of existing indebtedness for borrowed money. DEI is also a party to the Q-Pipe Purchase Agreement, as guarantor for certain provisions regarding the Purchase Price Repayment Amount (as defined below) and other matters.

Under the Q-Pipe Purchase Agreement, BHE delivered the Q-Pipe Cash Consideration of approximately $1.3 billion, which is included in ~~impairment~~other current assets on the Consolidated Balance Sheet as of ~~assets~~March 31, 2021 and ~~other charges~~December 31, 2020, to Dominion Questar on November 2, 2020. If the Q-Pipe Transaction does not close, Dominion Questar has agreed to repay all or (depending on the repayment date) substantially all of the Q-Pipe Cash Consideration (the "Purchase Price Repayment Amount") to BHE on or prior to December 31, 2021. If HSR Approval has not been obtained by June 30, 2021, upon BHE's written request, Dominion Questar will seek alternative buyers for all or a material portion of the Questar Pipeline Group (an "Alternative Transaction"). The Purchase Price Repayment Amount may be paid in ~~its Consolidated Statements~~cash or in shares of ~~Income. This charge is considered~~common stock, no par value, of DEI, or a ~~component of Virginia Power’s base rates deemed recovered under the GTSA,~~combination thereof, subject to ~~review~~certain limitations as ~~discussed~~to stock repayments set forth in ~~Note 13~~the Q-Pipe Purchase Agreement; provided any payment on or after December 15, 2021 must be paid in cash only.

The assets acquired in the GT&S Transaction include (i) approximately 5,400 miles of operated natural gas transmission, gathering and storage pipelines with approximately 12.5 billion cubic feet ("Bcf") per day of design capacity; (ii) 420 Bcf of operated natural gas storage design capacity, of which 306 Bcf is owned by BHE GT&S; and (iii) an LNG export, import and storage facility with LNG storage capacity of approximately 14.6 billions of cubic feet equivalent.

On October 29, 2020, BHE issued $3.75 billion of its 4.00% Perpetual Preferred Stock to certain subsidiaries of Berkshire Hathaway Inc. in order to fund the GT&S Cash Consideration and the Q-Pipe Cash Consideration.

Included in BHE's Consolidated ~~Financial Statements in Virginia Power’s Annual Report on Form 10-K~~Statement of Operations within the BHE Pipeline Group reportable segment for the ~~year~~three-month periods ended ~~December~~March 31, ~~2019.~~

~~In March 2019, Virginia Power committed~~2021, is operating revenue and net income attributable to ~~retire certain electric generating units before the end~~BHE shareholders of ~~their useful lives~~$559 million and completed the retirement of certain units at 6 facilities representing 1,292 MW of electric generating capacity, which had previously been placed in cold reserve. An additional unit at Possum Point power station will be retired after it meets its capacity obligation to PJM in 2021. As a result, Virginia Power recorded a charge of $369$107 million, ($275 million after-tax) in the first quarter of 2019, primarily included in impairment of assets and other charges in its Consolidated Statements of Income. This charge is considered a component of Virginia Power’s base rates deemed recovered under the GTSA, subject to review as discussed in Note 13 to the Consolidated Financial Statements in Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2019.

In May 2019, Virginia Power abandoned a coal rail project at its Mt. Storm generating facility. As a result, Virginia Power recorded a charge of $62 million ($46 million after-tax) in the second quarter of 2019, included in impairment of assets and other charges in its Consolidated Statements of Income.

In March 2020, Virginia Power committed to retire certain coal- and oil-fired generating units before the end of their useful lives based on economic and other factors, including but not limited to market power prices and the VCEA. These units will be retired after they meet their capacity obligations to PJM in 2023.As a result, Virginia Power recorded a charge of $754 million ($561 million after-tax) in the first quarter of 2020, primarily included in impairment of assets and other charges in its Consolidated Statements of Income. This charge is considered a component of Virginia Power’s base rates deemed recovered under the GTSA, subject to review as discussed in Note 13 to the Consolidated Financial Statements in Virginia Power’s Annual Report on Form 10-K for the year ended December 31, 2019.

In the second quarter of 2020, Virginia Power recorded charges of $30 million ($22 million after-tax) associated with dismantling certain of these electric generation facilities, recorded in impairment of assets and other charges in its Consolidated Statements of Income.

~~In the first quarter of 2020, Virginia Power updated depreciation rates for its nuclear plants to reflect lower depreciation rates~~respectively, as a result of ~~the expected approval~~including BHE GT&S from November 1, 2020.

Preliminary Allocation of license extensions from the NRC. This adjustment resulted in a decrease in depreciation expense of $8 million ($6 million after-tax) and $16 million ($12 million after-tax) for the three and six months ended June 30, 2020, respectively, in Virginia Power’s Consolidated Statements of Income and a $0.01 increase in Dominion Energy’s EPS, for both the three and six months ended June 30, 2020. This revision is expected to decrease annual depreciation expense by approximately $31 million ($23 million after-tax) and increase Dominion Energy’s EPS by $0.03 for the year ended December 31, 2020.

In the second quarter of 2020, DESC completed a nuclear decommissioning cost study related to Summer. As a result of the study, Dominion Energy recorded an $89 million increase to its nuclear decommissioning ARO, with a corresponding increase to property, plant and equipment.

In December 2014, DETI entered into a precedent agreement with Atlantic Coast Pipeline for the Supply Header Project. As a result of the cancellation of the Atlantic Coast Pipeline Project, Dominion Energy and Dominion Energy Gas recorded a charge of $482 million ($359 million after-tax) in impairment of assets and other charges in their Consolidated Statements of Income for the three and six months ended June 30, 2020 associated with the probable abandonment of a significant portion of the project as well as the establishment of a $75 million ARO. As DETI evaluates its future use, approximately $40 million remains within property, plant and equipment for a potential modified project.

~~Credit Risk~~

Credit risk is the risk of financial loss if counterparties fail to perform their contractual obligations. In order to minimize overall credit risk, credit policies are maintained, including the evaluation of counterparty financial condition, collateral requirements and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, counterparties may make available collateral, including letters of credit or cash held as margin deposits, as a result of exceeding agreed-upon credit limits, or may be required to prepay the transaction.

Effective January 2020, expected credit losses are estimated and recorded based on historical experience, current conditions and reasonable and supportable forecasts that affect the collectability of financial assets held at amortized cost as well as expected credit losses on commitments with respect to financial guarantees.

~~Investments~~

~~Debt and Equity Securities with Readily Determinable Fair Value~~

Dominion Energy accounts for and classifies investments in debt securities as trading or available-for-sale securities. Virginia Power classifies investments in debt securities as available-for-sale securities.

• Purchase Price

~~Debt securities classified as trading securities~~
include securities held by Dominion Energy in rabbi trusts associated with certain deferred compensation plans. These securities are reported in other investments in the Consolidated Balance Sheets at fair value with net realized and unrealized gains and losses included in other income in the Consolidated Statements of Income.

• ~~Debt securities classified as available-for-sale securities~~ include all other debt securities, primarily comprised of securities held in the nuclear decommissioning trusts. These investments are reported at fair value in nuclear decommissioning trust funds in the Consolidated Balance Sheets. Net realized and unrealized gains and losses (including any credit-related impairments) on investments held in Virginia Power’s nuclear decommissioning trusts are deferred to a regulatory asset or liability as applicable for certain jurisdictions subject to cost-based regulation. For all other available-for-sale debt securities, including those held in Dominion Energy’s merchant generation nuclear decommissioning trusts, net realized gains and losses (including any credit-related impairments) are included in other income and unrealized gains and losses are reported as a component of AOCI, after-tax.

~~In determining realized gains and losses for debt securities, the cost basis of the security is based on the specific identification method.~~

Equity securities with readily determinable fair values include securities held by Dominion Energy in rabbi trusts associated with certain deferred compensation plans and securities held by Dominion Energy and Virginia Power in the nuclear decommissioning

trusts. Dominion Energy and Virginia Power record all equity securities with a readily determinable fair value, or for which they are permitted to estimate fair value using NAV (or its equivalent), at fair value in nuclear decommissioning trust funds and other investments in the Consolidated Balance Sheets. However, Dominion Energy and Virginia Power may elect a measurement alternative for equity securities without a readily determinable fair value. Under the measurement alternative, equity securities are reported at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the identical or a similar investment of the same issuer. Dominion Energy and Virginia Power qualitatively assess equity securities reported using the measurement alternative to determine whether an investment is impaired on an ongoing basis. Net realized and unrealized gains and losses on equity securities held in Virginia Power’s nuclear decommissioning trusts are deferred to a regulatory asset or liability, as applicable, for certain jurisdictions subject to cost-based regulation. For all other equity securities, including those held in Dominion Energy’s merchant generation nuclear decommissioning trusts and rabbi trusts, net realized and unrealized gains and losses are included in other income in the Consolidated Statements of Income.

~~Equity Securities without Readily Determinable Fair Values~~

The Companies account for illiquid and privately held securities without readily determinable fair values under either the equity method or cost method. Equity securities without readily determinable fair values include:

• ~~Equity method investments~~ when the Companies have the ability to exercise significant influence, but not control, over the investee. Dominion Energy and Dominion Energy Gas’ investments are included in investments in equity method affiliates in their Consolidated Balance Sheets. Dominion Energy and Dominion Energy Gas record equity method adjustments in other income and earnings from equity method investees, respectively, in their Consolidated Statements of Income, including their proportionate share of investee income or loss, gains or losses resulting from investee capital transactions, amortization of certain differences between the carrying value and the equity in the net assets of the investee at the date of investment and other adjustments required by the equity method.

• ~~Cost method investments~~ when Dominion Energy and Virginia Power do not have the ability to exercise significant influence over the investee. Dominion Energy and Virginia Power’s investments are included in other investments and nuclear decommissioning trust funds. Cost method investments are reported at cost less impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for identical or similar investments of the same issuer.

~~Other-Than-Temporary Impairment~~

The Companies periodically review their equity method investments to determine whether a decline in fair value should be considered other-than-temporary. If a decline in the fair value of any equity method investment is determined to be other-than-temporary, the investment is written down to its fair value at the end of the reporting period.

~~Credit Impairment~~

Effective January 2020, Dominion Energy and Virginia Power periodically review their available-for-sale debt securities to determine whether a decline in fair value should be considered credit related. If a decline in the fair value of any available-for-sale debt security is determined to be credit related, the credit-related impairment is recorded to an allowance included in nuclear decommissioning trust funds in Dominion Energy and Virginia Power’s Consolidated Balance Sheets at the end of the reporting period, with such allowance for credit losses subject to reversal in subsequent evaluations.

Using information obtained from their nuclear decommissioning trust fixed-income investment managers, Dominion Energy and Virginia Power record in earnings, or defer as applicable for certain jurisdictions subject to cost-based regulation, any unrealized loss for a debt security when the manager intends to sell the debt security or it is more-likely-than-not that the manager will have to sell the debt security before recovery of its fair value up to its cost basis. If that is not the case, but the debt security is deemed to have experienced a credit loss, Dominion Energy and Virginia Power record the credit loss in earnings with the remaining non-credit portion of the unrealized loss recorded in AOCI. Credit losses are evaluated primarily by considering the credit ratings of the issuer, prior instances of non-performance by the issuer and other factors.

~~Note 3. Acquisitions and Dispositions~~

~~Acquisition of SCANA~~

In January 2019, Dominion Energy issued 95.6 million shares of Dominion Energy common stock, valued at $6.8 billion, representing 0.6690 of a share of Dominion Energy common stock for each share of SCANA common stock, in connection with the completion of the SCANA Combination. SCANA, through its regulated subsidiaries, is primarily engaged in the generation, transmission and distribution of electricity in the central, southern and southwestern portions of South Carolina and in the distribution of natural gas in

North Carolina and South Carolina. In addition, at the closing of the SCANA Combination, SCANA marketed natural gas to retail customers in the southeast U.S. Following completion of the SCANA Combination, SCANA operates as a wholly-owned subsidiary of Dominion Energy. In addition, SCANA’s debt totaled $6.9 billion at closing. The SCANA Combination expanded Dominion Energy’s portfolio of regulated electric generation, transmission and distribution and regulated natural gas distribution infrastructure operations.

See Note 3 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019 for more information on the SCANA Combination, including merger approval and conditions, information onBHE GT&S' assets acquired and liabilities assumed were measured at estimated fair value at closing. The majority of BHE GT&S' operations are subject to the rate-setting authority of the Federal Energy Regulatory Commission ("FERC") and are accounted for pursuant to GAAP, including the authoritative guidance for regulated operations. The rate-setting and cost-recovery provisions provide for revenues derived from costs, including a return on investment of assets and liabilities included in rate base. As such, the fair value of BHE GT&S' assets acquired and liabilities assumed subject to these rate-setting provisions are assumed to approximate their carrying values and, therefore, no fair value adjustments have been reflected related to these amounts.

The fair value of BHE GT&S' assets acquired and liabilities assumed not subject to the rate-setting provisions discussed above was determined using an income and cost approach. The income approach is based on significant estimates and assumptions, including Level 3 inputs, which are judgmental in nature. The estimates and assumptions include the projected timing and amount of future cash flows, discount rates reflecting the risk inherent in the future cash flows and future market prices. Additionally, the fair value of long-term debt assumed was determined based on quoted market prices, which is considered a Level 2 fair value measurement.

The fair value of certain contracts and property, plant and equipment related to non-regulated operations, certain regulatory assets and other items included in rate base, an equity method investment and deferred income tax amounts are provisional and are subject to revision for up to 12 months following the acquisition date until the related valuations are completed. These items may be adjusted through regulatory assets or liabilities, to the extent recoverable in rates, or goodwill provided additional information is obtained about the facts and circumstances that existed as of the acquisition date. Such information includes, but is not limited to, the receipt of further information regarding the fair value of the contracts and property, plant and equipment related to non-regulated operations, the equity method investment and any associated deferred income tax amounts as well as the evolution of the rate-making process for regulated operations.

The following table summarizes the preliminary fair values of the assets acquired and liabilities assumed as of the acquisition date (in millions):


	Fair Value

Current assets, including cash and cash equivalents of $104	$	569
Property, plant and equipment	9,254
Goodwill	1,732
Regulatory assets	108
Deferred income taxes	275
Other long-term assets	1,424
Total assets	13,362

Current liabilities, including current portion of long-term debt of $1,200	1,567
Long-term debt, less current portion	4,415
Regulatory liabilities	661
Other long-term liabilities	289
Total liabilities	6,932
Noncontrolling interest	3,916
Net assets acquired	$	2,514

Goodwill

The excess of the purchase price ~~allocation. In addition, see Note 17~~paid over the estimated fair values of the identifiable assets acquired and liabilities assumed totaled $1.7 billion and is reflected as goodwill in the BHE Pipeline Group reportable segment. The goodwill reflects the value paid primarily for the long-term opportunity to improve operating results through the efficient management of operating expenses and the deployment of capital. Goodwill is not amortized, but rather is reviewed annually for impairment or more frequently if indicators of impairment exist. For income tax purposes, the GT&S Acquisition is treated as a ~~discussion~~deemed asset acquisition resulting from tax elections being made, therefore all tax goodwill is deductible. Due to book and tax basis differences of certain ~~legal proceedings involving Dominion Energy, SCANA or DESC relating to events occurring before closing~~items, book and tax goodwill will differ. The amount of ~~the SCANA Combination.~~

~~In accordance with the SCANA Merger Approval Order, Dominion Energy incurred certain charges to its Consolidated Statements of Income for the following:~~

•

In the first quarter of 2019, DESC recorded a reduction in operating revenue and a corresponding regulatory liability of $1.0 billion representing a refund of amounts previously collected from retail electric customers of DESC for the NND Project to be credited over an estimated 11-year period, effective January 2019, As a result, Dominion Energy’s Consolidated Statement of Income for the six months ended June 30, 2019 includes a $756 million after-tax charge.

tax goodwill is approximately $0.9 billion and will be amortized over 15 years.

•

Dominion Energy committed to forgo recovery of $105 million of certain property, plant and equipment associated with the NND Project. As a result, Dominion Energy’s Consolidated Statement of Income for the six months ended June 30, 2019 includes a charge of $105 million ($79 million after-tax), included in impairment of assets and other charges.

•

Dominion Energy committed to forgo recovery of $264 million of certain income tax-related regulatory assets associated with the NND Project. As a result, Dominion Energy’s Consolidated Statement of Income for the six months ended June 30, 2019 includes a charge of $198 million included in income tax expense.

~~Results of Operations and Unaudited~~ Pro Forma Financial Information

The impact of the SCANA Combination on Dominion Energy’s operating revenue was an increase of $701 million and $909 million for the three months ended June 30, 2020 and 2019, respectively, and an increase of $1.6 billion and $1.1 billion for the six months ended June 30, 2020 and 2019, respectively, in the Consolidated Statements of Income. The impact of the SCANA Combination on net income attributable to Dominion Energy was an increase of $58 million and a decrease of $102 million for the three months ended June 30, 2020 and 2019, respectively, and an increase of $112 million and a decrease of $1.2 billion for the six months ended June 30, 2020 and 2019, respectively, in the Consolidated Statements of Income.

Dominion Energy incurred merger and integration-related costs of $23 million and $42 million for the three and six months ended June 30, 2020, respectively, of which $20 million and $39 million are recorded in other operations and maintenance expense in the Consolidated Statements of Income. Dominion Energy incurred merger and integration-related costs of $443 million and $567 million in the Consolidated Statements of Income for the three and six months ended June 30, 2019, respectively. These amounts for both the three and six months ended June 30, 2019 include $423 million for a charge related to a voluntary retirement program. See Note 20 for additional information. Of the remaining merger and integration-related costs, $20 million and $135 million was recorded in other operations and maintenance expense in the Consolidated Statements of Income for the three and six months ended June 30, 2019, respectively, and $9 million was recorded in interest and related charges in the Consolidated Statement of Income for the six months ended June 30, 2019. There were 0 such charges recorded in interest and related charges for the three months ended June 30, 2019. These costs consist of professional fees, charitable contribution commitments, employee-related expenses, certain financing costs and other miscellaneous costs.

The following unaudited pro forma financial information reflects the consolidated results of operations of ~~Dominion Energy~~BHE and the amortization of the purchase price adjustments assuming the ~~SCANA Combination~~acquisition had taken place on January 1, ~~2018.~~ 2019, excluding non-recurring transaction costs incurred by BHE during 2020 (in millions):


	Three-Month Period
	Ended March 31, 2020

Operating revenue	$	5,056

Net income attributable to BHE shareholders	$	773

(3) Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following (in millions):


		As of
	Depreciable	March 31,		December 31,
	Life	2021		2020
Regulated assets:
Utility generation, transmission and distribution systems	5-80 years	$	87,898	$	86,730
Interstate natural gas pipeline assets	3-80 years	16,712		16,667
		104,610		103,397
Accumulated depreciation and amortization		(31,653)		(30,662)
Regulated assets, net		72,957		72,735

Nonregulated assets:
Independent power plants	5-30 years	7,034		7,012
Other assets	3-40 years	5,794		5,659
		12,828		12,671
Accumulated depreciation and amortization		(2,337)		(2,586)
Nonregulated assets, net		10,491		10,085

Net operating assets		83,448		82,820
Construction work-in-progress		3,309		3,308
Property, plant and equipment, net		$	86,757	$	86,128

Construction work-in-progress includes $2.9 billion as of March 31, 2021 and $3.2 billion as of December 31, 2020, related to the construction of regulated assets.

(4) Investments and Restricted Cash and Cash Equivalents and Investments

Investments and restricted cash and cash equivalents and investments consists of the following (in millions):


	As of
	March 31,		December 31,
	2021		2020
Investments:
BYD Company Limited common stock	$	4,773	$	5,897
Rabbi trusts	452		440
Other	288		263
Total investments	5,513		6,600

Equity method investments:
BHE Renewables tax equity investments	5,399		5,626
Iroquois Gas Transmission System, L.P.	586		580
Electric Transmission Texas, LLC	581		594
JAX LNG, LLC	80		75
Bridger Coal Company	68		74
Other	113		118
Total equity method investments	6,827		7,067

Restricted cash and cash equivalents and investments:
Quad Cities Station nuclear decommissioning trust funds	697		676
Other restricted cash and cash equivalents	130		155
Total restricted cash and cash equivalents and investments	827		831

Total investments and restricted cash and cash equivalents and investments	$	13,167	$	14,498

Reflected as:
Current assets	$	157	$	178
Noncurrent assets	13,010		14,320
Total investments and restricted cash and cash equivalents and investments	$	13,167	$	14,498

Investments

(Losses) gains on marketable securities, net recognized during the period consists of the following (in millions):


	Three-Month Periods
	Ended March 31,
		2021		2020
Unrealized (losses) gains recognized on marketable securities still held at the reporting date		$	(1,119)	$	25
Net gains recognized on marketable securities sold during the period		1		2
(Losses) gains on marketable securities, net		$	(1,118)	$	27

Equity Method Investments

The ~~unaudited pro forma financial information~~Company has invested in projects sponsored by third parties, commonly referred to as tax equity investments. Once a project achieves commercial operation, the Company enters into a partnership agreement with the project sponsor that directs and allocates the operating profits and tax benefits from the project. Certain of the Company's tax equity investments are located in Texas and have physical settlement hedge obligations that were negatively impacted due to production shortfalls during periods of extreme market pricing volatility as a result of the February 2021 polar vortex weather event. The Company recognized pre-tax equity losses of $218 million, or after-tax losses of $23 million inclusive of production tax credits ("PTCs") of $148 million and other income tax benefits of $47 million, during the three-month period ended March 31, 2021, on its tax equity investments, largely due to the February 2021 polar vortex weather event. The losses for the impacted tax equity investments were based upon the terms of each partnership agreement, as amended, and are subject to change as project-by-project discussions are ongoing among the Company and the respective hedge provider and project sponsor. As of March 31, 2021, the carrying value of the impacted tax equity investments totaled $2.8 billion.

Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

Cash equivalents consist of funds invested in money market mutual funds, United States Treasury Bills and other investments with a maturity of three months or less when purchased. Cash and cash equivalents exclude amounts where availability is restricted by legal requirements, loan agreements or other contractual provisions. Restricted cash and cash equivalents as of March 31, 2021 and December 31, 2020, consist substantially of funds restricted for the purpose of constructing solid waste facilities under tax-exempt bond obligation agreements and debt service obligations for certain of the Company's nonregulated renewable energy projects. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as of March 31, 2021 and December 31, 2020, as presented in the Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance Sheets (in millions):


	As of
	March 31,		December 31,
	2021		2020
Cash and cash equivalents	$	1,276	$	1,290
Restricted cash and cash equivalents	117		140
Investments and restricted cash and cash equivalents and investments	13		15
Total cash and cash equivalents and restricted cash and cash equivalents	$	1,406	$	1,445

(5) Recent Financing Transactions

Long-Term Debt

In April 2021, Northern Natural Gas issued $550 million of 3.40% Senior Bonds due October 2051. Northern Natural Gas used the net proceeds to early redeem in April 2021 all of its $200 million, 4.25% Senior Notes originally due June 2021 and for general corporate purposes.

Credit Facilities

In April 2021, AltaLink Investments, L.P. extended, with lender consent, the expiration date for its existing C$200 million one-year revolving credit facility to April 2022, by exercising a one-year extension option.

(6) Income Taxes

The effective income tax rate for the three-month period ended March 31, 2021, is 217% and results from a $535 million income tax benefit associated with a $246 million pre-tax loss, primarily relating to a pre-tax unrealized loss of $1,124 million on the Company's investment in BYD Company Limited. The $535 million income tax benefit is primarily comprised of a $52 million benefit (21%) from the application of the statutory income tax rate to the pre-tax loss, a $334 million benefit (136%) from income tax credits and a $51 million benefit (21%) from state income tax benefits, net of federal income tax impacts.

A reconciliation of the federal statutory income tax rate to the effective income tax rate applicable to income before income tax benefit is as follows:


	Three-Month Periods
	Ended March 31,
		2021		2020

Federal statutory income tax rate		21	%	21	%
Income tax credits		136		(46)
State income tax, net of federal income tax impacts		21		0
Income tax effect of foreign income		6		(3)
Effects of ratemaking		10		(8)
Equity income		15		(1)
Noncontrolling interest		9		0
Other, net		(1)		1
Effective income tax rate		217	%	(36)	%

Income tax credits relate primarily to PTCs from wind-powered generating facilities owned by MidAmerican Energy, PacifiCorp and BHE Renewables. Federal renewable electricity PTCs are earned as energy from qualifying wind-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. Wind-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service. PTCs for the three-month periods ended March 31, 2021 and 2020 totaled $315 million and $233 million, respectively.

The Company's provision for income taxes has been ~~presented for illustrative purposes only~~computed on a stand-alone basis. Berkshire Hathaway includes the Company in its consolidated United States federal and ~~is not necessarily indicative~~Iowa state income tax returns and the majority of the Company's United States federal income tax is remitted to or received from Berkshire Hathaway. The Company made 0 payments for federal income taxes to Berkshire Hathaway for the three-month period ended March 31, 2021, and made payments for federal income taxes to Berkshire Hathaway totaling $100 million for the three-month period ended March 31, 2020.

(7) Employee Benefit Plans

Domestic Operations

Net periodic benefit cost (credit) for the domestic pension and other postretirement benefit plans included the following components (in millions):


	Three-Month Periods
	Ended March 31,
		2021		2020
Pension:
Service cost		$	7	$	3
Interest cost		20		23
Expected return on plan assets		(33)		(35)
Net amortization		6		9
Net periodic benefit cost		$	0	$	0

Other postretirement:
Service cost		$	2	$	1
Interest cost		5		6
Expected return on plan assets		(5)		(9)
Net amortization		(1)		(1)
Net periodic benefit cost (credit)		$	1	$	(3)

Amounts other than the service cost for pension and other postretirement benefit plans are recorded in Other, net in the Consolidated Statements of Operations. Employer contributions to the domestic pension and other postretirement benefit plans are expected to be $13 million and $13 million, respectively, during 2021. As of March 31, 2021, $3 million and $3 million of contributions had been made to the domestic pension and other postretirement benefit plans, respectively.

Foreign Operations

Net periodic benefit credit for the United Kingdom pension plan included the following components (in millions):


	Three-Month Periods
	Ended March 31,
		2021		2020

Service cost		$	4	$	4
Interest cost		8		10
Expected return on plan assets		(28)		(25)

Net amortization		14		10
Net periodic benefit credit		$	(2)	$	(1)

Amounts other than the service cost for the United Kingdom pension plan are recorded in Other, net in the Consolidated Statements of Operations. Employer contributions to the United Kingdom pension plan are expected to be £50 million during 2021. As of March 31, 2021, £11 million, or $15 million, of contributions had been made to the United Kingdom pension plan.

(8) Fair Value Measurements

The carrying value of the Company's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. The Company has various financial assets and liabilities that are measured at fair value on the Consolidated Financial Statements using inputs from the three levels of the fair value hierarchy. A financial asset or liability classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The three levels are as follows:

•Level 1 — Inputs are unadjusted quoted prices in active markets for identical assets or liabilities that the Company has the ability to access at the measurement date.

•Level 2 — Inputs include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).

•Level 3 — Unobservable inputs reflect the Company's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The Company develops these inputs based on the best information available, including its own data.

The following table presents the Company's financial assets and liabilities recognized on the Consolidated Balance Sheets and measured at fair value on a recurring basis (in millions):


	Input Levels for Fair Value Measurements
	Level 1		Level 2		Level 3		Other(1)		Total
As of March 31, 2021
Assets:
Commodity derivatives	$	1	$	72	$	154	$	(18)	$	209
Foreign currency exchange rate derivatives	—		12		—		—		12
Interest rate derivatives	0		33		47		—		80
Mortgage loans held for sale	0		2,065		0		—		2,065
Money market mutual funds(2)	807		0		0		—		807
Debt securities:
United States government obligations	210		0		0		—		210
International government obligations	0		5		0		—		5
Corporate obligations	0		71		0		—		71
Municipal obligations	0		2		0		—		2
Agency, asset and mortgage-backed obligations	0		5		0		—		5
Equity securities:
United States companies	395		0		0		—		395
International companies	4,780		0		0		—		4,780
Investment funds	256		0		0		—		256
	$	6,449	$	2,265	$	201	$	(18)	$	8,897
Liabilities:
Commodity derivatives	$	0	$	(90)	$	(30)	$	39	$	(81)
Foreign currency exchange rate derivatives	—		(1)		—		—		(1)
Interest rate derivatives	(3)		(14)		(6)		—		(23)
	$	(3)	$	(105)	$	(36)	$	39	$	(105)


	Input Levels for Fair Value Measurements
	Level 1		Level 2		Level 3		Other(1)		Total
As of December 31, 2020
Assets:
Commodity derivatives	$	1	$	73	$	135	$	(21)	$	188
Foreign currency exchange rate derivatives	—		20		—		—		20
Interest rate derivatives	0		0		62		—		62
Mortgage loans held for sale	0		2,001		0		—		2,001
Money market mutual funds(2)	873		0		0		—		873
Debt securities:
United States government obligations	200		0		0		—		200
International government obligations	0		5		0		—		5
Corporate obligations	0		73		0		—		73
Municipal obligations	0		2		0		—		2
Agency, asset and mortgage-backed obligations	0		6		0		—		6
Equity securities:
United States companies	381		0		0		—		381
International companies	5,906		0		0		—		5,906
Investment funds	201		0		0		—		201
	$	7,562	$	2,180	$	197	$	(21)	$	9,918
Liabilities:
Commodity derivatives	$	(1)	$	(90)	$	(19)	$	56	$	(54)
Foreign currency exchange rate derivatives	—		(2)		—		—		(2)
Interest rate derivatives	(5)		(60)		0		—		(65)
	$	(6)	$	(152)	$	(19)	$	56	$	(121)

(1)Represents netting under master netting arrangements and a net cash collateral receivable of $21 million and $35 million as of March 31, 2021 and December 31, 2020, respectively.

(2)Amounts are included in cash and cash equivalents; other current assets; and noncurrent investments and restricted cash and investments on the Consolidated Balance Sheets. The fair value of these money market mutual funds approximates cost.

Derivative contracts are recorded on the Consolidated Balance Sheets as either assets or liabilities and are stated at estimated fair value unless they are designated as normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which the Company transacts. When quoted prices for identical contracts are not available, the Company uses forward price curves. Forward price curves represent the Company's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. The Company bases its forward price curves upon market price quotations, when available, or internally developed and commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent brokers, exchanges, direct communication with market participants and actual transactions executed by the Company. Market price quotations are generally readily obtainable for the applicable term of the Company's outstanding derivative contracts; therefore, the Company's forward price curves reflect observable market quotes. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to the length of the contract. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, the Company uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The estimated fair value of these derivative contracts is a function of underlying forward commodity prices, interest rates, currency rates, related volatility, counterparty creditworthiness and duration of contracts.

The Company's mortgage loans held for sale are valued based on independent quoted market prices, where available, or the prices of other mortgage whole loans with similar characteristics. As necessary, these prices are adjusted for typical securitization activities, including servicing value, portfolio composition, market conditions and liquidity.

The Company's investments in money market mutual funds and debt and equity securities are stated at fair value. When available, a readily observable quoted market price or net asset value of an identical security in an active market is used to record the fair value. In the absence of a quoted market price or net asset value of an identical security, the fair value is determined using pricing models or net asset values based on observable market inputs and quoted market prices of securities with similar characteristics.

The following table reconciles the beginning and ending balances of the Company's assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions):


	Three-Month Periods
	Ended March 31,
				Interest
		Commodity		Rate
		Derivatives		Derivatives
2021:
Beginning balance		$	116	$	62
Changes included in earnings(1)		(6)		(21)
Changes in fair value recognized in OCI		(1)		0
Changes in fair value recognized in net regulatory assets		16		0



Settlements		(1)		0

Ending balance		$	124	$	41







2020:
Beginning balance	$	97	$	14
Changes included in earnings(1)	(3)		31

Changes in fair value recognized in net regulatory assets	(40)		0
Purchases	2		0

Settlements	(4)		0

Ending balance	$	52	$	45

(1)Changes included in earnings for interest rate derivatives are reported net of amounts related to the satisfaction of the associated loan commitment.

The Company's long-term debt is carried at cost, including fair value adjustments and unamortized premiums, discounts and debt issuance costs as applicable, on the Consolidated Balance Sheets. The fair value of the Company's long-term debt is a Level 2 fair value measurement and has been estimated based upon quoted market prices, where available, or at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of the Company's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents the carrying value and estimated fair value of the Company's long-term debt (in millions):


	As of March 31, 2021				As of December 31, 2020
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	49,461	$	55,926	$	49,866	$	60,633

(9) Commitments and Contingencies

Legal Matters

The Company is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. The Company does not believe that such normal and routine litigation will have a material impact on its consolidated ~~results~~financial results. The Company is also involved in other kinds of ~~operations that would~~legal actions, some of which assert or may assert claims or seek to impose fines, penalties and other costs in substantial amounts and are described below.

California and Oregon 2020 Wildfires

In September 2020, a severe weather event resulting in high winds, low humidity and warm temperatures contributed to several major wildfires, private and public property damage, personal injuries and loss of life and widespread power outages in Oregon and Northern California. The wildfires spread across certain parts of PacifiCorp's service territory and surrounding areas across multiple counties in Oregon and California, including Siskiyou County, California; Jackson County, Oregon; Douglas County, Oregon; Marion County, Oregon; Lincoln County, Oregon; and Klamath County, Oregon burning over 500,000 acres in aggregate. Third party reports for these wildfires indicate over 2,000 structures, including residences, destroyed; several structures damaged; multiple individuals injured; and several fatalities. Fire suppression costs estimated by various agencies total approximately $150 million. Investigations into the cause and origin of each wildfire are complex and ongoing and being conducted by various entities, including the United States Forest Service, the California Public Utilities Commission, the Oregon Department of Forestry, the Oregon Department of Justice, PacifiCorp and various experts engaged by PacifiCorp.

Several lawsuits have been ~~achieved~~filed in Oregon and California, including a putative class action complaint in Oregon, on behalf of citizens and businesses who suffered damages from fires allegedly caused by PacifiCorp. The final determinations of liability, however, will only be made following comprehensive investigations and litigation processes.

In California, under inverse condemnation, courts have held that investor-owned utilities can be liable for real and personal property damages without the utility being found negligent and regardless of fault. California law also permits inverse condemnation plaintiffs to recover reasonable attorney fees and costs. In both Oregon and California, PacifiCorp has equipment in areas accessed through special use permits, easements or similar agreements that may contain provisions requiring it to pay for damages caused by its equipment regardless of fault. Even if inverse condemnation or other provisions do not apply, PacifiCorp could nevertheless be found liable for all damages proximately caused by negligence, including property and natural resource damage; fire suppression costs; personal injury and loss of life damages; and interest.

As of March 31, 2021, PacifiCorp has accrued $136 million as its best estimate of the potential losses net of expected insurance recoveries associated with the 2020 Wildfires that are considered probable of being incurred. These accruals include estimated losses for fire suppression costs, property damage, personal injury damages and loss of life damages. It is reasonably possible that PacifiCorp will incur additional losses beyond the amounts accrued; however, PacifiCorp is currently unable to estimate the range of possible additional losses that could be incurred due to the number of properties and parties involved and the lack of specific claims for all potential claimants. To the extent losses beyond the amounts accrued are incurred, additional insurance coverage is expected to be available to cover at least a portion of the losses.

Environmental Laws and Regulations

The Company is subject to federal, state, local and foreign laws and regulations regarding climate change, renewable portfolio standards, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other environmental matters that have the potential to impact the Company's current and future operations. The Company believes it is in material compliance with all applicable laws and regulations.

Hydroelectric Relicensing

PacifiCorp is a party to the 2016 amended Klamath Hydroelectric Settlement Agreement ("KHSA"), which is intended to resolve disputes surrounding PacifiCorp's efforts to relicense the Klamath Hydroelectric Project. The KHSA establishes a process for PacifiCorp, the states of Oregon and California ("States") and other stakeholders to assess whether dam removal can occur consistent with the settlement's terms. For PacifiCorp, the key elements of the settlement include: (1) a contribution from PacifiCorp's Oregon and California customers capped at $200 million plus $250 million in California bond funds; (2) complete indemnification from harms associated with dam removal; (3) transfer of the FERC license to a third-party dam removal entity, the Klamath River Renewal Corporation ("KRRC"), who would conduct dam removal; and (4) ability for PacifiCorp to operate the facilities for the benefit of customers until dam removal commences.

In September 2016, the KRRC and PacifiCorp filed a joint application with the FERC to transfer the license for the four mainstem Klamath dams from PacifiCorp to the KRRC. The FERC approved partial transfer of the Klamath license in a July 2020 order, subject to the condition that PacifiCorp remains co-licensee. Under the amended KHSA, PacifiCorp did not agree to remain co-licensee during the surrender and removal process given concerns about liability protections for PacifiCorp and its customers. In November 2020, PacifiCorp entered a memorandum of agreement (the "MOA") with the KRRC, the Karuk Tribe, the Yurok Tribe and the States to continue implementation of the KHSA. The agreement required the States, PacifiCorp and KRRC to file a new license transfer application by January 16, 2021 to remove PacifiCorp from the license for the Klamath Hydroelectric Project and add the States and KRRC as co-licensees for the purposes of surrender. On January 13, 2021, the new license transfer application was filed with the FERC, notifying it that PacifiCorp and the KRRC are not accepting co-licensee status under FERC's July 2020 order, and instead are seeking the license transfer outcome described in the new license transfer application. In addition, the MOA provides for additional contingency funding of $45 million, equally split between PacifiCorp and the States, and for PacifiCorp and the States to equally share in any additional cost overruns in the unlikely event that dam removal costs exceed the $450 million in funding to ensure dam removal is complete. The MOA also requires PacifiCorp to cover the costs associated with certain pre-existing environmental conditions.

Guarantees

The Company has entered into guarantees as part of the normal course of business and the sale of certain assets. These guarantees are not expected to have a material impact on the Company's consolidated financial results.

(10) Revenue from Contracts with Customers

Energy Products and Services

The following table summarizes the Company's energy products and services revenue from contracts with customers ("Customer Revenue") by regulated energy and nonregulated energy, with further disaggregation of regulated energy by line of business, including a reconciliation to the Company's reportable segment information included in Note 13 (in millions):


	For the Three-Month Period Ended March 31, 2021
	PacifiCorp		MidAmerican Funding		NV Energy		Northern Powergrid		BHE Pipeline Group		BHE Transmission		BHE Renewables		BHE and Other(1)		Total
Customer Revenue:
Regulated:
Retail electric	$	1,145	$	452	$	511	$	0	$	0	$	0	$	0	$	0	$	2,108
Retail gas	0		460		38		0		0		0		0		0		498
Wholesale	36		125		15		0		17		0		0		0		193
Transmission and distribution	25		15		21		263		0		172		0		0		496
Interstate pipeline	0		0		0		0		815		0		0		(41)		774
Other	23		0		0		0		2		0		0		0		25
Total Regulated	1,229		1,052		585		263		834		172		0		(41)		4,094
Nonregulated	0		10		0		10		237		8		166		187		618
Total Customer Revenue	1,229		1,062		585		273		1,071		180		166		146		4,712
Other revenue	13		5		6		27		22		0		24		40		137
Total	$	1,242	$	1,067	$	591	$	300	$	1,093	$	180	$	190	$	186	$	4,849


	For the Three-Month Period Ended March 31, 2020
	PacifiCorp		MidAmerican Funding		NV Energy		Northern Powergrid		BHE Pipeline Group		BHE Transmission		BHE Renewables		BHE and Other(1)		Total
Customer Revenue:
Regulated:
Retail electric	$	1,122	$	410	$	529	$	0	$	0	$	0	$	0	$	0	$	2,061
Retail gas	0		187		47		0		0		0		0		0		234
Wholesale	0		64		14		0		0		0		0		(1)		77
Transmission and distribution	22		15		23		233		0		169		0		0		462
Interstate pipeline	0		0		0		0		400		0		0		(48)		352
Other	26		0		1		0		0		0		0		0		27
Total Regulated	1,170		676		614		233		400		169		0		(49)		3,213
Nonregulated	0		6		1		7		0		3		159		127		303
Total Customer Revenue	1,170		682		615		240		400		172		159		78		3,516
Other revenue	36		4		7		26		1		0		19		25		118
Total	$	1,206	$	686	$	622	$	266	$	401	$	172	$	178	$	103	$	3,634

(1)The BHE and Other reportable segment represents amounts related principally to other entities, corporate functions and intersegment eliminations.

Real Estate Services

The following table summarizes the Company's real estate services Customer Revenue by line of business (in millions):


		HomeServices
	Three-Month Periods
	Ended March 31,
		2021		2020
Customer Revenue:
Brokerage		$	1,022	$	777
Franchise		18		16
Total Customer Revenue		1,040		793
Mortgage and other revenue		192		100
Total		$	1,232	$	893

Remaining Performance Obligations

The following table summarizes the Company's revenue it expects to recognize in future periods related to significant unsatisfied remaining performance obligations for fixed contracts with expected durations in excess of one year as of March 31, 2021, by reportable segment (in millions):


	Performance obligations expected to be satisfied:
	Less than 12 months		More than 12 months		Total
BHE Pipeline Group	$	2,521	$	20,918	$	23,439
BHE Transmission	513		0		513
Total	$	3,034	$	20,918	$	23,952

(11) BHE Shareholders' Equity

For the three-month period ended March 31, 2020, BHE repurchased 180,358 shares of its common stock for $126 million.

(12) Components of Other Comprehensive Income (Loss), Net

The following table shows the change in accumulated other comprehensive income (loss) attributable to BHE shareholders by each component of other comprehensive income (loss), net of applicable income tax (in millions):


	Unrecognized		Foreign		Unrealized		AOCI
	Amounts on		Currency		(Losses) Gains		Attributable
	Retirement		Translation		on Cash		To BHE
	Benefits		Adjustment		Flow Hedges		Shareholders, Net

Balance, December 31, 2019	$	(417)	$	(1,296)	$	7	$	(1,706)

Other comprehensive income (loss)	34		(548)		(33)		(547)
Balance, March 31, 2020	$	(383)	$	(1,844)	$	(26)	$	(2,253)

Balance, December 31, 2020	$	(482)	$	(1,062)	$	(8)	$	(1,552)
Other comprehensive income	7		91		14		112
Balance, March 31, 2021	$	(475)	$	(971)	$	6	$	(1,440)

(13) Segment Information

The Company's reportable segments with foreign operations include Northern Powergrid, whose business is principally in the United Kingdom, BHE Transmission, whose business includes operations in Canada, and BHE Renewables, whose business includes operations in the Philippines. Intersegment eliminations and adjustments, including the allocation of goodwill, have been made. Information related to the Company's reportable segments is shown below (in millions):


	Three-Month Periods
	Ended March 31,
		2021		2020
Operating revenue:
PacifiCorp		$	1,242	$	1,206
MidAmerican Funding		1,067		686
NV Energy		591		622
Northern Powergrid		300		266
BHE Pipeline Group		1,093		401
BHE Transmission		180		172
BHE Renewables		190		178
HomeServices		1,232		893
BHE and Other(1)		186		103
Total operating revenue		$	6,081	$	4,527





Depreciation and amortization:
PacifiCorp	$	264	$	252
MidAmerican Funding	207		176
NV Energy	136		124
Northern Powergrid	71		63
BHE Pipeline Group	118		64
BHE Transmission	58		60
BHE Renewables	60		71
HomeServices	11		11
BHE and Other(1)	2		0
Total depreciation and amortization	$	927	$	821


	Three-Month Periods
	Ended March 31,
		2021		2020
Operating income:
PacifiCorp		$	234	$	234
MidAmerican Funding		48		102
NV Energy		70		79
Northern Powergrid		151		132
BHE Pipeline Group		618		249
BHE Transmission		81		76
BHE Renewables		33		17
HomeServices		112		20
BHE and Other(1)		(14)		10
Total operating income		1,333		919
Interest expense		(530)		(483)
Capitalized interest		14		17
Allowance for equity funds		26		34
Interest and dividend income		21		20
(Losses) gains on marketable securities, net		(1,118)		27
Other, net		8		(27)
Total (loss) income before income tax benefit and equity loss		$	(246)	$	507





Interest expense:
PacifiCorp	$	107	$	102
MidAmerican Funding	78		81
NV Energy	52		58
Northern Powergrid	33		32
BHE Pipeline Group	38		14
BHE Transmission	38		38
BHE Renewables	40		42
HomeServices	1		5
BHE and Other(1)	143		111
Total interest expense	$	530	$	483


(Loss) earnings on common shares:
PacifiCorp	$	169	$	176
MidAmerican Funding	144		150
NV Energy	34		20
Northern Powergrid	104		87
BHE Pipeline Group	383		179
BHE Transmission	59		55
BHE Renewables	16		95
HomeServices	84		10
BHE and Other	(1,027)		(102)
(Loss) earnings on common shares	$	(34)	$	670


	As of
	March 31,		December 31,
	2021		2020
Assets:
PacifiCorp	$	26,956	$	26,862
MidAmerican Funding	24,098		23,530
NV Energy	14,594		14,501
Northern Powergrid	8,980		8,782
BHE Pipeline Group	19,651		19,541
BHE Transmission	9,341		9,208
BHE Renewables	11,935		12,004
HomeServices	5,186		4,955
BHE and Other(1)	6,781		7,933
Total assets	$	127,522	$	127,316

(1)The differences between the reportable segment amounts and the consolidated amounts, described as BHE and Other, relate principally to other entities, including MidAmerican Energy Services, LLC, corporate functions and intersegment eliminations.


	Three-Month Periods
	Ended March 31,
		2021		2020
Operating revenue by country:
United States		$	5,597	$	4,089
United Kingdom		300		266
Canada		177		171
Philippines and other		7		1
Total operating revenue by country		$	6,081	$	4,527


(Loss) income before income tax benefit and equity loss by country:
United States	$	(423)	$	354
United Kingdom	132		109
Canada	39		40
Philippines and other	6		4
Total (loss) income before income tax benefit and equity loss by country	$	(246)	$	507

The following table shows the change in the carrying amount of goodwill by reportable segment for the three-month period ended March 31, 2021 (in millions):


									BHE Pipeline Group
	PacifiCorp		MidAmerican Funding		NV Energy		Northern Powergrid				BHE Transmission		BHE Renewables		HomeServices
																	Total

December 31, 2020	$	1,129	$	2,102	$	2,369	$	1,000	$	1,803	$	1,551	$	95	$	1,457	$	11,506
Acquisitions	—		—		—		—		—		—		—		1		1
Foreign currency translation	0		0		0		6		0		21		0		0		27

March 31, 2021	$	1,129	$	2,102	$	2,369	$	1,006	$	1,803	$	1,572	$	95	$	1,458	$	11,534

Item 2.Management's Discussion and Analysis of Financial Condition and Results of Operations

The following is management's discussion and analysis of certain significant factors that have affected the consolidated financial condition and results of operations of the ~~combined company.~~

Three Months Ended
June 30, 2019⁽¹⁾

Six Months Ended
June 30, 2019⁽¹⁾

(millions, except EPS)

Operating Revenue

$
3,970

$
8,835

Net income attributable to Dominion Energy

392

962

Earnings Per Common Share – Basic

$
0.49

$
1.21

Earnings Per Common Share – Diluted

$
0.47

$
1.19

~~(1)~~

~~Amounts include adjustments for non-recurring costs directly related to the SCANA Combination.~~

~~Disposition of Gas Transmission & Storage Operations to BHE~~

In July 2020, Dominion Energy entered into an agreement with BHE with a total value of approximately $10 billion, comprised of approximately $4.0 billion of cash consideration (subject to customary closing adjustments) plusCompany during the assumption of Dominion Energy Gas’ long-term debt, to sell substantially all of its gas transmission and storage operations, including processing assets, as well as noncontrolling partnership interests in Iroquois, JAX LNG and White River Hub and a controlling interest in Cove Point (consisting of 100%periods included herein. Explanations include management's best estimate of the ~~general partner interest and 25%~~impact of the total limited partner interests). Upon closing, Dominion Energy Gas will become a wholly-owned subsidiary of BHE. Dominion Energy will retain a 50% noncontrolling interest in Cove Point, which will be accounted for as an equity method investment following completion of the sale, as well as the assets and obligations of the pensionweather, customer growth, usage trends and other ~~postretirement employee benefit plans associated~~factors. This discussion should be read in conjunction with the operations to be sold and relating to services provided through closing. The sale will be treated as an asset sale for tax purposes and is expected to close in the fourth quarter of 2020, contingent on clearance or approval under the Hart-Scott-Rodino Act and from the DOE, and other customary closing and regulatory conditions. Based on the recorded balances at June 30, 2020, Dominion Energy expects to recognize a pre-tax gain of approximately $1 billion upon closing, excluding the effects of any closing adjustments. If approval under the Hart-Scott-Rodino Act is not obtained by mid-September 2020, Dominion Energy may elect to exclude from this transaction Dominion Energy Questar Pipeline and certain other affiliated entities pursuant to a provision in the agreement with BHE, with an associated reduction in the cash consideration to $2.7 billion, subject to customary closing adjustments.

Dominion Energy will reclassify the assets and liabilities to be disposed of, currently reflected within Gas Transmission & Storage, as held for sale and will report the associated results of operations as discontinued operations starting in the third quarter of 2020. In addition, in the third quarter of 2020, Dominion Energy and Dominion Energy Gas expect to record pre-tax losses of approximately $225 million and $140 million, respectively, for cash flow hedges of debt-related items that are probable of not occurring.

~~Dominion Energy Gas Restructuring~~

The Dominion Energy Gas Restructuring is considered to be a reorganization of entities under common control. As a result, Dominion Energy Gas’ basis in DCP and DMLPHCII, which includes the general partner of Dominion Energy Midstream, a controlling 75% interest in Cove Point, DECG, Dominion Energy Questar Pipeline, a 50% noncontrolling interest in White River Hub and a 25.93% noncontrolling interest in Iroquois, is equal to Dominion Energy’s cost basis in the assets and liabilities of such entities since the applicable inception dates of common control. In November 2019, following completion of the Dominion Energy Gas Restructuring, DCP and DMLPHCII are wholly-owned subsidiaries of Dominion Energy Gas and therefore are consolidated by Dominion Energy Gas. The accompanyingCompany's historical unaudited Consolidated Financial Statements and Notes ~~of Dominion Energy Gas have been retrospectively adjusted~~ to include the historical results and financial position of DCP and DMLPHCII. The 25% interest in Cove Point retained by Dominion Energy, and subsequently sold to Brookfield in December 2019, and the non-Dominion Energy held interest in Dominion Energy Midstream (through January 2019) are reflected as noncontrolling interest.

The Dominion Energy Gas Restructuring includes the disposition of East Ohio and DGP by Dominion Energy Gas in November 2019. This restructuring represented a strategic shift in the operations of Dominion Energy Gas as Dominion Energy Gas’ operations consist of LNG import/export and storage and regulated gas transmission and storage operations. As a result, the accompanying Consolidated Financial Statements and Notes of Dominion Energy Gas have been retrospectively adjusted to include the historical results and financial position of East Ohio and DGP as discontinued operations until November 2019, presented within the Corporate and Other segment. As the Dominion Energy Gas Restructuring is considered to be a reorganization of entities under common control, Dominion Energy Gas has reflected the disposition as an equity transaction. The following table represents selected information regarding the results of operations of East Ohio, which are reported as discontinued operations in Dominion Energy Gas’ Consolidated Statements of Income:

Three Months Ended
June 30, 2019

Six Months Ended
June 30, 2019

(millions)

Operating revenue

$
154

$
383

Depreciation and amortization

22

43

Other operating expenses

128

277

Other income

18

37

Interest and related charges

8

18

Income tax expense

3

17

Net income from discontinued operations

$
11

$
65

~~Capital expenditures and significant noncash items relating to East Ohio included the following:~~

Six Months Ended
June 30, 2019

(millions)

Capital expenditures

$
168

Significant noncash items

Charge related to a voluntary retirement program

32

Accrued capital expenditures

8

The following table represents selected information regarding the results of operations of DGP, which are reported as discontinued operations in Dominion Energy Gas’ Consolidated Statements of Income:

Three Months Ended
June 30, 2019

Six Months Ended
June 30, 2019

(millions)

Operating revenue

$
34

$
79

Depreciation and amortization

1

2

Other operating expenses

12

56

Income tax expense

6

6

Net income from discontinued operations

$
15

$
15

~~Capital expenditures and significant noncash items of DGP included the following:~~

Six Months Ended
June 30, 2019

(millions)

Capital Expenditures

$
8

~~Note 4. Operating Revenue~~

~~The Companies’ operating revenue consists of the following:~~

Three Months Ended June 30,

Six Months Ended June 30,

2020

2019

2020

2019

(millions)

Dominion Energy

Regulated electric sales:

Residential

$
1,091

$
1,094

$
2,249

$
1,740

Commercial

728

889

1,526

1,385

Industrial

176

217

358

247

Government and other retail

193

214

412

414

Wholesale

29

41

62

89

Nonregulated electric sales

177

175

409

491

Regulated gas sales:

Residential

182

177

730

779

Commercial

63

73

254

264

Other

16

25

44

63

Nonregulated gas sales

33

71

116

318

Regulated gas transportation and storage:

FERC-regulated

247

247

528

524

State-regulated

182

166

414

379

Nonregulated gas transportation and storage

176

174

351

348

Other regulated revenues⁽¹⁾

98

82

173

126

Other nonregulated revenues⁽¹⁾⁽²⁾

79

101

167

209

Total operating revenue from contracts
   with customers

3,470

3,746

7,793

7,376

Other revenues⁽³⁾

115

224

288

452

Total operating revenue

$
3,585

$
3,970

$
8,081

$
7,828

Virginia Power

Regulated electric sales:

Residential

$
818

$
808

$
1,714

$
1,731

Commercial

546

681

1,160

1,317

Industrial

89

118

186

230

Government and other retail

177

197

380

401

Wholesale

21

29

45

66

Other regulated revenues

94

62

156

88

Other nonregulated revenues⁽¹⁾⁽²⁾

20

19

33

33

Total operating revenue from contracts
   with customers

1,765

1,914

3,674

3,866

Other revenues⁽²⁾⁽³⁾

40

24

61

37

Total operating revenue

$
1,805

$
1,938

$
3,735

$
3,903

Dominion Energy Gas

Regulated gas sales - wholesale

$
—

$
—

$
2

$
2

Nonregulated gas sales⁽²⁾

—

1

1

3

Regulated gas transportation and storage⁽²⁾

302

306

646

646

Nonregulated gas transportation and storage

175

173

350

348

Management service revenue⁽²⁾

29

45

60

88

Other regulated revenues⁽¹⁾

2

3

3

6

Other nonregulated revenues⁽¹⁾⁽²⁾

1

1

2

1

Total operating revenue from contracts
   with customers

509

529

1,064

1,094

Other revenues⁽²⁾

1

1

2

2

Total operating revenue

$
510

$
530

$
1,066

$
1,096

Amounts above include sales which are considered to be goods transferred at a point in time. Such amounts included $19 million and $— million for the three months ended June 30, 2020, $42 million and $2 million for the three months ended June 30, 2019, $58 million and $1 million for the six months ended June 30, 2020 and $93 and $3 million for the six months ended June 30, 2019, primarily consisting of NGL sales at Dominion Energy and Dominion Energy Gas, respectively. Additionally, amounts above include sales of renewable energy credits. Such amounts included $7 million and $5 million for the three months ended June 30, 2020, $4 million and $2 million for the three months ended June 30, 2019, $11 million and $8 million for the six months ended June 30, 2020 and $7 million and $3 million for the six months ended June 30, 2019, at Dominion Energy and Virginia Power, respectively.

2)	~~See Notes 10 and 19 for amounts attributable to related parties and affiliates.~~

Amounts above include alternative revenue of $39 million and $21 million at Dominion Energy and $34 million and $18 million at Virginia Power for the three months ended June 30, 2020 and 2019, respectively, and $75 million and $35 million at Dominion Energy and $51 million and $26 million at Virginia Power for the six months ended June 30, 2020 and 2019, respectively.

The table below discloses the aggregate amount of the transaction price allocated to fixed-price performance obligations that are unsatisfied (or partially unsatisfied) at the end of the reporting period and when the Companies expect to recognize this revenue. These revenues relate to contracts containing fixed prices where the Companies will earn the associated revenue over time as they stand ready to perform services provided. This disclosure does not include revenue related to performance obligations that are part of a contract with original durations of one year or less. In addition, this disclosure does not include expected consideration related to performance obligations for which the Companies elect to recognize revenue in the amount they have a right to invoice.

Revenue expected to be recognized on multi-year
contracts in place at June 30, 2020

2020

2021

2022

2023

2024

Thereafter

Total

(millions)

Dominion Energy

$
823

$
1,567

$
1,475

$
1,315

$
1,190

$
13,095

$
19,465

Virginia Power

2

1

—

—

—

—

3

Dominion Energy Gas

899

1,719

1,585

1,402

1,248

13,280

20,133

Contract assets represent an entity’s right to consideration in exchange for goods and services that the entity has transferred to a customer. At June 30, 2020 and December 31, 2019, Dominion Energy’s contract asset balances were $25 million and $28 million, respectively. Dominion Energy Gas’ contract asset balances were $35 million and $40 million at June 30, 2020 and December 31, 2019, respectively. Dominion Energy and Dominion Energy Gas’ contract assets are recorded in other deferred charges and other assets in the Consolidated Balance Sheets. Contract liabilities represent an entity’s obligation to transfer goods or services to a customer for which the entity has received consideration, or the amount that is due, from the customer. At June 30, 2020 and December 31, 2019, Dominion Energy’s contract liability balances were $109 million and $123 million, respectively. At June 30, 2020 and December 31, 2019, Virginia Power’s contract liability balances were $37 million and $24 million, respectively. At June 30, 2020 and December 31, 2019, Dominion Energy Gas’ contract liability balances were $21 million and $20 million, respectively. The Companies’ contract liabilities are recorded in other current liabilities and other deferred credits and other liabilities in the Consolidated Balance Sheets.

The Companies recognize revenue as they fulfill their obligations to provide service to their customers. During the six months ended June 30, 2020 and 2019 Dominion Energy recognized revenue of $106 million and $91 million, respectively, from the beginning contract liability balances. During the six months ended June 30, 2020 and 2019, Virginia Power recognized $24 million and $22 million, respectively, from the beginning contract liability balance. During the six months ended June 30, 2020 and 2019, Dominion Energy Gas recognized $1 million and $28 million from the beginning contract liability balance.

~~Note 5. Income Taxes~~

~~For continuing operations, including noncontrolling interests, the statutory U.S. federal income tax rate reconciles to the Companies’ effective income tax rate as follows:~~

Dominion Energy

Virginia Power

Dominion Energy Gas

Six Months Ended June 30,

2020

2019

2020

2019

2020

2019

U.S. statutory rate

21.0
%

21.0
%

21.0
%

21.0
%

21.0
%

21.0
%

Increases (reductions) resulting from:

State taxes, net of federal benefit

5.6

0.7

4.9

4.7

(255.3
)

3.0

Investment tax credits

3.9

(3.8
)

(11.3
)

(5.2
)

—

—

Production tax credits

0.3

(1.1
)

(2.0
)

(0.8
)

—

—

Reversal of excess deferred income
taxes

1.5

(6.9
)

(0.8
)

(4.2
)

(68.4
)

(0.9
)

Write-off of regulatory assets

(4.2
)

(41.6
)

—

—

189.4

—

AFUDC - equity

0.5

(1.9
)

(0.6
)

(0.1
)

(36.8
)

(0.5
)

Other, net

0.9

(0.3
)

1.1

0.4

(467.1
)
⁽¹⁾

(4.3
)
⁽¹⁾
Effective tax rate

29.5
%

(33.9
)%

12.3
%

15.8
%

(617.2
)%

18.3
%

~~(1)~~

~~Includes (276.0)% and (4.0)% relating to the absence of tax on noncontrolling interest in 2020 and 2019, respectively~~.

For the Companies’ rate-regulated entities, deferred taxes will reverse at the weighted average rate used to originate the deferred tax liability, which in some cases will be 35%. The Companies have recorded an estimate of excess deferred income tax amortization in 2020. The reversal of these excess deferred income taxes will impact the effective tax rate and rates charged to customers. See Note 13 to the Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. The Company's actual results in the ~~Companies’~~future could differ significantly from the historical results.

Berkshire Hathaway Energy's operations are organized as eight business segments: PacifiCorp, MidAmerican Funding (which primarily consists of MidAmerican Energy), NV Energy (which primarily consists of Nevada Power and Sierra Pacific), Northern Powergrid (which primarily consists of Northern Powergrid (Northeast) plc and Northern Powergrid (Yorkshire) plc), BHE Pipeline Group (which primarily consists of BHE GT&S, Northern Natural Gas and Kern River), BHE Transmission (which consists of BHE Canada (which primarily consists of AltaLink) and BHE U.S. Transmission), BHE Renewables and HomeServices. BHE, through these locally managed and operated businesses, owns four utility companies in the United States serving customers in 11 states, two electricity distribution companies in Great Britain, five interstate natural gas pipeline companies, one of which owns an LNG import, export and storage facility, in the United States, an electric transmission business in Canada, interests in electric transmission businesses in the United States, a renewable energy business primarily investing in wind, solar, geothermal and hydroelectric projects, the largest residential real estate brokerage firm in the United States and one of the largest residential real estate brokerage franchise networks in the United States. The reportable segment financial information includes all necessary adjustments and eliminations needed to conform to the Company's significant accounting policies. The differences between the reportable segment amounts and the consolidated amounts, described as BHE and Other, relate principally to other entities, corporate functions and intersegment eliminations.

Results of Operations for the First Quarter of 2021 and 2020

Overview

Operating revenue and earnings on common shares for the Company's reportable segments are summarized as follows (in millions):


	First Quarter
	2021		2020		Change
Operating revenue:
PacifiCorp	$	1,242	$	1,206	$	36	3	%
MidAmerican Funding	1,067		686		381		56
NV Energy	591		622		(31)		(5)
Northern Powergrid	300		266		34		13
BHE Pipeline Group	1,093		401		692		*
BHE Transmission	180		172		8		5
BHE Renewables	190		178		12		7
HomeServices	1,232		893		339		38
BHE and Other	186		103		83		81
Total operating revenue	$	6,081	$	4,527	$	1,554	34	%

(Loss) earnings on common shares:
PacifiCorp	$	169	$	176	$	(7)	(4)	%
MidAmerican Funding	144		150		(6)		(4)
NV Energy	34		20		14		70
Northern Powergrid	104		87		17		20
BHE Pipeline Group	383		179		204		*
BHE Transmission	59		55		4		7
BHE Renewables(1)	16		95		(79)		(83)
HomeServices	84		10		74		*
BHE and Other	(1,027)		(102)		(925)		*
(Loss) earnings on common shares	$	(34)	$	670	$	(704)	*

(1)Includes the tax attributes of disregarded entities that are not required to pay income taxes and the earnings of which are taxable directly to BHE.

* Not meaningful

Earnings on common shares decreased $704 million for the first quarter of 2021 compared to 2020. The first quarter of 2021 included a pre-tax unrealized loss of $1,124 million ($818 million after-tax) compared to a pre-tax unrealized gain in the first quarter of 2020 of $54 million ($39 million after-tax) on the Company's investment in BYD Company Limited. Excluding the impact of this item, adjusted earnings on common shares for the first quarter of 2021 was $784 million, an increase of $153 million, or 24%, compared to adjusted earnings on common shares in the first quarter of 2020 of $631 million.

The decrease in earnings on common shares for the first quarter of 2021 compared to 2020 was primarily due to the following:

•$204 million higher net income at BHE Pipeline Group, primarily due to $107 million of incremental net income from BHE GT&S, acquired in November 2020, higher gross margin on gas sales and higher transportation revenue at Northern Natural Gas, largely due to the favorable impact of the February 2021 polar vortex weather event, and the impacts of the 2020 rate case settlement at Northern Natural Gas;

•$79 million lower net income at BHE Renewables, primarily due to lower wind tax equity investment earnings from net losses on existing tax equity investments, largely due to the February 2021 polar vortex weather event, partially offset by increased income tax benefits from projects reaching commercial operation;

•$74 million higher net income at HomeServices, primarily due to higher earnings from mortgage services (63% increase in funded mortgage volume) and brokerage services (35% increase in closed transaction volume) largely attributable to the favorable interest rate environment; and

•$925 higher net loss at BHE and Other due to the $857 million unfavorable change in the after-tax unrealized position of the Company's investment in BYD Company Limited, $38 million of dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain subsidiaries of Berkshire Hathaway in October 2020, higher BHE corporate interest expense from debt issuances in March and October 2020 and higher other corporate costs, partially offset by favorable changes in the cash surrender value of corporate-owned life insurance policies.

Reportable Segment Results

PacifiCorp

Operating revenue increased $36 million for the first quarter of 2021 compared to 2020, primarily due to higher retail revenue of $20 million and higher wholesale and other revenue of $16 million. Retail revenue increased due to higher customer volumes of $15 million and price impacts of $5 million from changes in sales mix, partially offset by lower rates due to certain general rate case orders. Retail customer volumes increased 0.3%, primarily due to an increase in the average number of customers and the favorable impact of weather, partially offset by lower customer usage. Wholesale and other revenue increased primarily due to higher wholesale volumes and higher average wholesale market prices.

Net income decreased $7 million for the first quarter of 2021 compared to 2020, primarily due to higher depreciation and amortization expense, including the impacts of a depreciation study effective in January 2021, lower allowances for equity and borrowed funds used during construction of $12 million and higher property taxes of $12 million, partially offset by higher utility margin of $29 million and favorable income tax expense from the impacts of ratemaking and higher PTCs recognized due to new wind-powered generating facilities placed in-service. Utility margin increased primarily due to the higher retail and wholesale revenue and lower purchased power costs, partially offset by higher natural gas-fueled and coal-fueled generation costs and higher net amortization of deferred net power costs in accordance with established adjustment mechanisms.

MidAmerican Funding

Operating revenue increased $381 million for the first quarter of 2021 compared to 2020, primarily due to higher natural gas operating revenue of $303 million and higher electric operating revenue of $74 million. Natural gas operating revenue increased due to a higher average per-unit cost of natural gas sold, primarily due to the February 2021 polar vortex weather event resulting in higher purchased gas adjustment recoveries of $304 million (offset in cost of sales). Electric operating revenue increased due to higher retail revenue of $40 million and higher wholesale and other revenue of $32 million mainly from higher wholesale volumes. Electric retail revenue increased primarily due to $32 million higher recoveries through the energy adjustment clauses (offset primarily in cost of sales), higher customer volumes of $5 million and price impacts of $5 million from changes in sales mix. Electric retail customer volumes increased 4.9% due to the favorable impact of weather and increased usage of certain industrial customers.

Net income decreased $6 million for the first quarter of 2021 compared to 2020, primarily due to higher depreciation and amortization expense of $31 million from additional assets placed in-service and the expiration of a regulatory mechanism deferring certain depreciation expense and $28 million higher operations and maintenance expenses, partially offset by a favorable income tax benefit and favorable changes in the cash surrender value of corporate-owned life insurance policies. Higher operations and maintenance expenses included increased costs associated with additional wind-powered generating facilities placed in-service as well as higher electric and natural gas distribution costs. The favorable income tax benefit was mainly due to higher PTCs recognized from higher wind-powered generation, driven primarily by new wind projects placed in-service, partially offset by the impacts of ratemaking. Electric utility margin increased $3 million as the higher retail and wholesale revenue was largely offset by higher generation and purchased power costs.

NV Energy

Operating revenue decreased $31 million for the first quarter of 2021 compared to 2020, primarily due to lower electric operating revenue of $22 million and lower natural gas operating revenue of $9 million. Electric operating revenue decreased primarily due to lower base tariff general rates of $14 million, lower retail customer volumes, lower fully-bundled energy rates (offset in cost of sales) of $4 million and price impacts from changes in sales mix. Electric retail customer volumes, including distribution only service customers, decreased 3.2%, primarily due to the impacts of COVID-19, which resulted in lower distribution only service, industrial and commercial customer usage and higher residential customer usage, partially offset by the favorable impact of weather. Natural gas operating revenue decreased due to a lower average per-unit cost of natural gas sold (offset in cost of sales).

Net income increased $14 million for the first quarter of 2021 compared to 2020, primarily due to lower operations and maintenance expense of $22 million, primarily from lower regulatory instructed deferrals and amortizations and lower plant operations and maintenance costs, favorable changes in the cash surrender value of corporate-owned life insurance policies, lower interest expense of $7 million and lower income tax expense from the impacts of ratemaking, partially offset by lower electric utility margin of $18 million and higher depreciation and amortization expense of $13 million, mainly from the regulatory amortization of decommissioning costs and higher plant placed in-service. Electric utility margin decreased primarily due to the lower base tariff general rates at Nevada Power, lower retail customer volumes and price impacts from changes in sales mix.

Northern Powergrid

Operating revenue increased $34 million for the first quarter of 2021 compared to 2020, primarily due to $21 million from the weaker United States dollar and higher distribution revenue of $13 million, mainly from increased tariff rates of $10 million. Net income increased $17 million for the first quarter of 2021 compared to 2020, primarily due to the higher distribution revenue and $7 million from the weaker United States dollar.

BHE Pipeline Group

Operating revenue increased $692 million for the first quarter of 2021 compared to 2020, primarily due to $559 million of incremental revenue at BHE GT&S, acquired in November 2020, higher gas sales at Northern Natural Gas of $91 million and higher transportation revenue of $33 million at Northern Natural Gas, largely due to the favorable impacts of the February 2021 polar vortex weather event. Net income increased $204 million for the first quarter of 2021 compared to 2020, primarily due to $107 million of incremental net income at BHE GT&S and higher earnings of $98 million at Northern Natural Gas. Northern Natural Gas' improved performance was primarily due to higher gross margin on gas sales of $75 million, higher transportation revenue and the impacts of the 2020 rate case settlement.

BHE Transmission

Operating revenue increased $8 million for the first quarter of 2021 compared to 2020, primarily due to $10 million from the stronger United States dollar and higher revenue from the Montana-Alberta Tie-Line, acquired in May 2020, partially offset by the impacts of a regulatory decision received in November 2020 at AltaLink. Net income increased $4 million for the first quarter of 2021 compared to 2020, primarily due to higher earnings from the Montana-Alberta Tie-Line and lower non-regulated interest expense at BHE Canada.

BHE Renewables

Operating revenue increased $12 million for the first quarter of 2021 compared to 2020, primarily due to higher hydro, geothermal and solar revenues from higher generation as well as favorable pricing at the geothermal facilities. Net income decreased $79 million for the first quarter 2021 compared to 2020, primarily due to lower wind tax equity investment earnings of $93 million, partially offset by the higher operating revenue. Wind tax equity investment earnings decreased due to unfavorable results from existing tax equity investments of $138 million, primarily due to the February 2021 polar vortex weather event, partially offset by increased income tax benefits from projects reaching commercial operation.

HomeServices

Operating revenue increased $339 million for the first quarter of 2021 compared to 2020, primarily due to higher brokerage revenue of $228 million from a 35% increase in closed transaction volume and higher mortgage revenue of $92 million from a 63% increase in funded mortgage volume due to an increase in refinance activity from the favorable interest rate environment. Net income increased $74 million for the first quarter of 2021 compared to 2020, primarily due to higher earnings from mortgage services of $36 million and brokerage services of $27 million largely attributable to the favorable interest rate environment.

BHE and Other

Operating revenue increased $83 million for the first quarter of 2021 compared to 2020, primarily due to higher electricity and natural gas sales revenue at MidAmerican Energy Services, LLC, from favorable pricing offset by lower volumes. Net loss increased $925 million for the first quarter of 2021 compared to 2020, primarily due to the $857 million unfavorable change in the after-tax unrealized position of the Company's investment in BYD Company Limited, $38 million of dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain subsidiaries of Berkshire Hathaway in October 2020, higher BHE corporate interest expense from debt issuances in March and October 2020 and higher other corporate costs, partially offset by favorable changes in the cash surrender value of corporate-owned life insurance policies.

Liquidity and Capital Resources

Each of BHE's direct and indirect subsidiaries is organized as a legal entity separate and apart from BHE and its other subsidiaries. It should not be assumed that the assets of any subsidiary will be available to satisfy BHE's obligations or the obligations of its other subsidiaries. However, unrestricted cash or other assets that are available for distribution may, subject to applicable law, regulatory commitments and the terms of financing and ring-fencing arrangements for such parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to BHE or affiliates thereof. The Company's long-term debt may include provisions that allow BHE or its subsidiaries to redeem such debt in whole or in part at any time. These provisions generally include make-whole premiums. Refer to Note 18 of Notes to Consolidated Financial Statements in Item 8 of the Company's Annual Report on Form 10-K for the year ended December 31, ~~2019~~2020 for ~~more information.~~further discussion regarding the limitation of distributions from BHE's subsidiaries.

As of March 31, 2021, the Company's total net liquidity was as follows (in millions):


					MidAmerican		NV		Northern		BHE
	BHE		PacifiCorp		Funding		Energy		Powergrid		Canada		Other		Total

Cash and cash equivalents	$	418	$	43	$	38	$	103	$	83	$	71	$	520	$	1,276

Credit facilities	3,500		1,200		1,509		650		207		935		3,232		11,233
Less:
Short-term debt	—		(95)		(387)		(55)		—		(218)		(1,944)		(2,699)
Tax-exempt bond support and letters of credit	—		(218)		(370)		—		—		(2)		—		(590)
Net credit facilities	3,500		887		752		595		207		715		1,288		7,944

Total net liquidity	$	3,918	$	930	$	790	$	698	$	290	$	786	$	1,808	$	9,220
Credit facilities:
Maturity dates	2022		2022		2021, 2022		2022		2023		2021, 2024		2021, 2022

Operating Activities

Net cash flows from operating activities for the three-month periods ended March 31, 2021 and 2020 were $1.5 billion and $1.2 billion, respectively. The increase was primarily due to improved operating results and favorable income tax cash flows, partially offset by changes in working capital.

The timing of the Company's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods and assumptions used for each payment date.

Investing Activities

Net cash flows from investing activities for the three-month periods ended March 31, 2021 and 2020 were $(1.4) billion and $(1.5) billion, respectively. The change was primarily due to lower funding of tax equity investments and lower capital expenditures of $61 million. Refer to "Future Uses of Cash" for further discussion of capital expenditures.

Financing Activities

Net cash flows from financing activities for the three-month period ended March 31, 2021 was $(191) million. Sources of cash totaled $409 million and consisted of net proceeds from short-term debt. Uses of cash totaled $600 million and consisted mainly of repayments of BHE senior debt totaling $450 million, distributions to noncontrolling interests of $115 million and repayments of subsidiary debt totaling $26 million.

For a discussion of recent financing transactions, refer to Note 5 of Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

Net cash flows from financing activities for the ~~six months~~three-month period ended ~~June 30,~~March 31, 2020 ~~Dominion Energy’s effective~~was $1.4 billion. Sources of cash totaled $4.3 billion and consisted of proceeds from BHE senior debt issuances totaling $3.2 billion and subsidiary debt issuances totaling $1.1 billion. Uses of cash totaled $3.0 billion and consisted mainly of repayments of subsidiary debt totaling $1.3 billion, net repayments of short-term debt totaling $1.1 billion, repayments of BHE senior debt totaling $350 million and common stock repurchases totaling $126 million.

The Company may from time to time seek to acquire its outstanding debt securities through cash purchases in the open market, privately negotiated transactions or otherwise. Any debt securities repurchased by the Company may be reissued or resold by the Company from time to time and will depend on prevailing market conditions, the Company's liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

Future Uses of Cash

The Company has available a variety of sources of liquidity and capital resources, both internal and external, including net cash flows from operating activities, public and private debt offerings, the issuance of commercial paper, the use of unsecured revolving credit facilities, the issuance of equity and other sources. These sources are expected to provide funds required for current operations, capital expenditures, acquisitions, investments, debt retirements and other capital requirements. The availability and terms under which BHE and each subsidiary has access to external financing depends on a variety of factors, including regulatory approvals, its credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry and project finance markets, among other items.

Capital Expenditures

The Company has significant future capital requirements. Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, impacts to customers' rates; changes in environmental and other rules and regulations; outcomes of regulatory proceedings; changes in income tax ~~rate reflects a charge~~laws; general business conditions; load projections; system reliability standards; the cost and efficiency of ~~$81~~construction labor, equipment and materials; commodity prices; and the cost and availability of capital. Expenditures for certain assets may ultimately include acquisitions of existing assets.

The Company's historical and forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and other non-cash items, are as follows (in millions):


	Three-Month Periods				Annual
	Ended March 31,				Forecast
	2020		2021		2021
Capital expenditures by business:
PacifiCorp	$	366	$	439	$	1,897
MidAmerican Funding	472		298		2,200
NV Energy	163		167		854
Northern Powergrid	159		179		732
BHE Pipeline Group	120		102		1,204
BHE Transmission	56		77		279
BHE Renewables	12		18		95
HomeServices	7		8		39
BHE and Other(1)	1		7		78
Total	$	1,356	$	1,295	$	7,378





Capital expenditures by type:
Wind generation	$	273	$	97	$	1,158
Electric distribution	365		427		1,849
Electric transmission	185		157		1,006
Natural gas transmission and storage	49		85		1,032
Solar generation	—		4		295
Other	484		525		2,038
Total	$	1,356	$	1,295	$	7,378

(1)BHE and Other represents amounts related principally to other entities, corporate functions and intersegment eliminations.

The Company's historical and forecast capital expenditures consisted mainly of the following:

•Wind generation expenditures include the following:

◦Construction and acquisition of wind-powered generating facilities at MidAmerican Energy totaling $154 million for the ~~write-off~~three-month period ended March 31, 2020. MidAmerican Energy's forecast expenditures in 2021 for the construction of ~~tax-related regulatory assets~~additional wind-powered generating facilities total $391 million and include 202 MWs of wind-powered generating facilities expected to be placed in-service in 2021.

◦Repowering of wind-powered generating facilities at MidAmerican Energy totaling $24 million and $6 million for the three-month periods ended March 31, 2021 and 2020, respectively. The repowering projects entail the replacement of significant components of older turbines. Planned spending for the repowered generating facilities totals $379 million for the remainder of 2021. MidAmerican Energy expects its repowered facilities to meet Internal Revenue Service guidelines for the re-establishment of PTCs for 10 years from the date the facilities are placed in-service. The rate at which PTCs are re-established for a facility depends upon the date construction begins. Of the 1,078 MWs of current repowering projects not in-service as of March 31, 2021, 80 MWs are currently expected to qualify for 100% of the federal PTCs available for 10 years following each facility's return to service, 591 MWs are expected to qualify for 80% of such credits and 407 MWs are expected to qualify for 60% of such credits.

◦Construction of wind-powered generating facilities at PacifiCorp totaling $27 million and $89 million for the three-month periods ended March 31, 2021 and 2020, respectively, and includes the 674 MWs of new wind-powered generating facilities that were placed in-service in 2020 and 516 MWs expected to be placed in-service in 2021. The energy production from the new wind-powered generating facilities is expected to qualify for 100% of the federal PTCs available for 10 years once the equipment is placed in-service. PacifiCorp's 2019 IRP identified 1,920 MWs of new wind-powered generating resources that are expected to come online in 2024. PacifiCorp anticipates that the additional new wind-powered generation will be a mixture of owned and contracted resources. PacifiCorp anticipates costs associated with the ~~impacts~~construction of wind-powered generating facilities will total an additional $100 million for 2021.

◦Repowering existing wind-powered generating facilities at PacifiCorp totaling $5 million and $16 million for the three-month periods ended March 31, 2021 and 2020, respectively. The repowering projects entail the replacement of significant components of older turbines. Certain repowering projects were placed in service in 2019 and 2020 and the remaining repowering projects are expected to be placed in-service in 2021. The energy production from such repowered facilities is expected to qualify for 100% of the ~~cancellation~~federal PTCs available for 10 years following each facility's return to service. Planned additional spending for certain existing wind-powered generating facilities totals $6 million for 2021.

◦Acquisition and repowering of wind-powered generating facilities at PacifiCorp totaling $1 million for the ~~Atlantic Coast Pipeline Project~~three-month period ended March 31, 2021. Planned additional spending for these wind-powered generating facilities totals $44 million for 2021.

•Electric distribution includes both growth and ~~related portions of~~operating expenditures. Growth expenditures include new customer connections and enhancements to existing customer connections. Operating expenditures include ongoing distribution systems infrastructure needed at the ~~Supply Header Project. In addition, Dominion Energy Gas’ effective tax rate~~Utilities and Northern Powergrid, wildfire mitigation, damage restoration and storm damage repairs and investments in routine expenditures for distribution needed to serve existing and expected demand.

•Electric transmission includes both growth and operating expenditures. Growth expenditures include PacifiCorp's costs for the 140-mile 500-kV Aeolus-Bridger/Anticline transmission line, which is a ~~function~~major segment of PacifiCorp's Energy Gateway Transmission expansion program, placed in-service in November 2020, the ~~nominal year-to-date pre-tax income driven~~Nevada Utilities' Greenlink Nevada transmission expansion program and AltaLink's directly assigned projects from the Alberta Electric System Operator. Operating expenditures include system reinforcement, upgrades and replacements of facilities to maintain system reliability and investments in routine expenditures for transmission needed to serve existing and expected demand.

•Natural gas transmission and storage includes both growth and operating expenditures. Growth expenditures include, among other items, the Northern Natural Gas New Lisbon Expansion and Twin Cities Area Expansion projects. Operating expenditures include, among other items, asset modernization and pipeline integrity projects.

•Solar generation includes growth expenditures, including MidAmerican Energy's current plan for the construction of 117 MWs of small- and utility-scale solar generation during 2021, of which 37 MWs are expected to be placed in-service in 2021. Nevada Power's solar generation investment includes expenditures for a 150 MWs solar photovoltaic facility with an additional 100 MWs capacity of co-located battery storage, known as the Dry Lake generating facility. Commercial operation at Dry Lake is expected by ~~a charge associated~~the end of 2023.

•Other capital expenditures includes both growth and operating expenditures, including routine expenditures for generation and other infrastructure needed to serve existing and expected demand, natural gas distribution, technology, and environmental spending relating to emissions control equipment and the management of coal combustion residuals.

Other Renewable Investments

The Company has invested in projects sponsored by third parties, commonly referred to as tax equity investments. Under the terms of these tax equity investments, the Company has entered into equity capital contribution agreements with the ~~Supply Header Project~~project sponsors that require contributions. The Company has made no contributions for the three-month period ended March 31, 2021, and has commitments as ~~discussed in Note 2.~~

Inof March 2020, the CARES Act was enacted which includes several significant business tax provisions that modify or temporarily suspend certain provisions of the 2017 Tax Reform Act. The CARES Act provisions are intended31, 2021, subject to improve cash flow and liquidity by, among other things, providing a temporary five-year carryback for certain net operating losses, accelerating the refund of previously generated corporate alternative minimum tax credits and temporarily loosening the business interest limitation to 50% of adjusted taxable income for certain businesses. While Dominion Energy intends to utilize the income tax provisions of the CARES Act to accelerate the recognitionsatisfaction of certain ~~tax attributes, where applicable, they are not expected~~specified conditions, to provide equity contributions of $616 million for the remainder of 2021 pursuant to these equity capital contribution agreements as the various projects achieve commercial operation. Once a ~~material benefit.~~

~~In July 2020,~~project achieves commercial operation, the U.S. Department of Treasury issued final regulations providing guidance about the limitation on the deduction for business interest expenses and issued proposed regulations on the application of these rules to certain pass-through entities and partners in those entities under the 2017 Tax Reform Act as modified by the CARES Act. Dominion Energy is currently assessing the impact of these regulations, but expects interest expense to be deductible in 2020.

~~In connection~~Company enters into a partnership agreement with the ~~SCANA Combination, Dominion Energy committed to forgo, or limit,~~project sponsor that directs and allocates the ~~recovery of certain income tax-related regulatory assets associated with the NND Project. Dominion Energy’s 2019 effective~~operating profits and tax rate reflects deferred income tax expense of $198 million in satisfaction of this commitment. Dominion Energy’s 2019 effective tax rate also reflects the changes in consolidated state income taxes resultingbenefits from the ~~SCANA Combination.~~

project.

Contractual Obligations

As of ~~June 30, 2020,~~March 31, 2021, there have been no material changes outside the normal course of business in contractual obligations from the ~~Companies’ unrecognized tax benefits or possible changes that could reasonably be expected to occur during~~information provided in Item 7 of the ~~next twelve months. See Note 5 to the Consolidated Financial Statements in the Companies’~~Company's Annual Report on Form 10-K for the year ended December 31, 2020 other than the recent financing transactions and renewable tax equity investments previously discussed.

Quad Cities Generating Station Operating Status

Exelon Generation Company, LLC ("Exelon Generation"), the operator of Quad Cities Generating Station Units 1 and 2 ("Quad Cities Station") of which MidAmerican Energy has a 25% ownership interest, announced on June 2, 2016, its intention to shut down Quad Cities Station on June 1, 2018. In December 2016, Illinois passed legislation creating a zero emission standard, which went into effect June 1, 2017. The zero emission standard requires the Illinois Power Agency to purchase zero emission credits ("ZECs") and recover the costs from certain ratepayers in Illinois, subject to certain limitations. The proceeds from the ZECs will provide Exelon Generation additional revenue through 2027 as an incentive for continued operation of Quad Cities Station. MidAmerican Energy will not receive additional revenue from the subsidy.

The PJM Interconnection, L.L.C. ("PJM") capacity market includes a Minimum Offer Price Rule ("MOPR"). If a generation resource is subjected to a MOPR, its offer price in the market is adjusted to effectively remove the revenues it receives through a government-provided financial support program, resulting in a higher offer that may not clear the capacity market. Prior to December 19, 2019, the PJM MOPR applied only to certain new gas-fired resources. An expanded PJM MOPR to include existing resources would require exclusion of ZEC compensation when bidding into future capacity auctions, resulting in an increased risk of Quad Cities Station not receiving capacity revenues in future auctions.

On December 19, 2019, the FERC issued an order requiring the PJM to broadly apply the MOPR to all new and existing resources, including nuclear. This greatly expands the breadth and scope of the PJM's MOPR, which is effective as of the PJM's next capacity auction. While the FERC included some limited exemptions in its order, no exemptions were available to state-supported nuclear resources, such as Quad Cities Station. The FERC provided no new mechanism for accommodating state-supported resources other than the existing Fixed Resource Requirement ("FRR") mechanism under which an entire utility zone would be removed from PJM's capacity auction along with sufficient resources to support the load in such zone. In response to the FERC's order, the PJM submitted a ~~discussion~~compliance filing on March 18, 2020, wherein the PJM proposed tariff language reflecting the FERC's directives and a schedule for resuming capacity auctions. On April 16, 2020, the FERC issued an order largely denying requests for rehearing of ~~these unrecognized tax benefits.~~

~~Note 6. Earnings Per Share~~

~~The following table presents~~the FERC's December 2019 order but granting a few clarifications that required an additional PJM compliance filing, which the PJM submitted on June 1, 2020. On October 15, 2020, the FERC issued an order denying requests for rehearing of its April 16, 2020 order and accepting the PJM's two compliance filings, subject to a further compliance filing to revise minor aspects of the proposed MOPR methodology. As part of that order, the FERC also accepted the PJM's proposal to condense the schedule of activities leading up to the next capacity auction but did not specify when that schedule would commence given that a key element of the MOPR level computation remains pending before the FERC in another proceeding. In November 2020, the PJM announced that the next capacity auction will be conducted in May 2021.

On May 21, 2020, the FERC issued an order involving reforms to the PJM's day-ahead and real-time reserves markets that need to be reflected in the calculation of ~~Dominion Energy’s basic~~MOPR levels. In approving reforms to the PJM's reserves markets, the FERC also directed the PJM to develop a new methodology for estimating revenues that resources will receive for sales of energy and ~~diluted EPS:~~

Three Months Ended June 30,

Six Months Ended June 30,

2020

2019

2020

2019

(millions, except EPS)

Net income (loss) attributable to Dominion Energy

$
(1,169
)

$
54

$
(1,439
)

$
(626
)
Preferred stock dividends (see Note 16)

(16
)

—

(32
)

—

Net income (loss) attributable to Dominion Energy – Basic

(1,185
)

54

(1,471
)

(626
)
Dilutive effect of Series A Preferred Stock

—

(13
)

—

—

Net income (loss) attributable to Dominion Energy - Diluted

(1,185
)

41

(1,471
)

(626
)
Average shares of common stock outstanding – Basic &
Diluted

839.4

802.5

838.8

797.8

Net effect of dilutive securities

—

0.1

—

—

Average shares of common stock outstanding – Diluted

839.4

802.6

838.8

797.8

Earnings Per Common Share – Basic

$
(1.41
)

$
0.07

$
(1.75
)

$
(0.78
)
Earnings Per Common Share – Diluted

$
(1.41
)

$
0.05

$
(1.75
)

$
(0.78
)

Asrelated services, which will then be used in calculating a ~~result~~number of ~~a net loss~~parameters and assumptions used in the capacity market, including MOPR levels. The PJM submitted its new revenue projection methodology on August 5, 2020. On review of this compliance filing, the FERC is expected to address how these additional reforms will impact MOPR levels, the timeline for implementing the ~~three and six months ended June 30, 2020~~new revenue projection methodology, and the ~~six months ended June 30, 2019, any adjustments~~timing for commencing the capacity auction schedule.

Exelon Generation is currently working with the PJM and other stakeholders to ~~earnings or shares would~~pursue the FRR option as an alternative to the next PJM capacity auction. If Illinois implements the FRR option, Quad Cities Station could be ~~considered antidilutive and are therefore excluded~~removed from the ~~calculation~~PJM's capacity auction and instead supply capacity and be compensated under the FRR program. If Illinois cannot implement an FRR program in its PJM zones, then the MOPR will apply to Quad Cities Station, resulting in higher offers for its units that may not clear the capacity market. Implementing the FRR program in Illinois will require both legislative and regulatory changes. MidAmerican Energy cannot predict whether or when such legislative and regulatory changes can be implemented or their potential impact on the continued operation of ~~diluted EP~~Quad Cities Station.

S
.

Regulatory Matters

BHE's regulated subsidiaries and certain affiliates are subject to comprehensive regulation. The ~~2019 Equity Units are potentially dilutive securities. The forward stock purchase contracts included within the 2019 Equity Units were excluded from the calculation~~discussion below contains material developments to those matters disclosed in Item 1 of diluted EPS for the three months ended June 30, 2019, as the dilutive stock price threshold was not met. The Series A Preferred Stock included within the 2019 Equity Units is excluded from the effect of dilutive securities within diluted EPS, but a fair value adjustment is reflected within net income attributable to Dominion Energy for the calculation of diluted EPS for the three months ended June 30, 2019, based upon the expectation that the conversion will be settled in cash rather than through the

issuance of Dominion Energy common stock. The 2016 Equity Units are potentially dilutive securities, but were excluded from the calculation of diluted EPS for the three months ended June 30, 2019 as the dilutive stock price threshold was not met.

~~Note 7. Accumulated Other Comprehensive Income~~

~~Dominion Energy~~

~~The following table presents Dominion Energy’s changes in AOCI by component, net of tax:~~

Deferred
gains and
losses on
derivatives-
hedging
activities

Unrealized
gains and
losses on
investment
securities

Unrecognized
pension and
other
postretirement
benefit costs

Other
comprehensive
loss from
equity method
investees

Total

(millions)

Three Months Ended June 30, 2020

Beginning balance

$
(651
)

$
37

$
(1,402
)

$
(2
)

$
(2,018
)
Other comprehensive income before reclassifications:
   gains (losses)

2

19

(1
)

—

20

Amounts reclassified from AOCI: (gains) losses⁽¹⁾

5

(5
)

18

—

18

Net current period other comprehensive income (loss)

7

14

17

—

38

Ending balance

$
(644
)

$
51

$
(1,385
)

$
(2
)

$
(1,980
)
Three Months Ended June 30, 2019

Beginning balance

$
(290
)

$
18

$
(1,457
)

$
(2
)

$
(1,731
)
Other comprehensive income before reclassifications:
   gains (losses)

(78
)

13

113

—

48

Amounts reclassified from AOCI: (gains) losses⁽¹⁾

(21
)

(1
)

22

—

—

Net current period other comprehensive income (loss)

(99
)

12

135

—

48

Ending balance

$
(389
)

$
30

$
(1,322
)

$
(2
)

$
(1,683
)
Six Months Ended June 30, 2020

Beginning balance

$
(407
)

$
37

$
(1,421
)

$
(2
)

$
(1,793
)
Other comprehensive income before reclassifications:
   gains (losses)

(264
)

28

(1
)

—

(237
)
Amounts reclassified from AOCI: (gains) losses⁽¹⁾

27

(14
)

37

—

50

Net current period other comprehensive income (loss)

(237
)

14

36

—

(187
)
Ending balance

$
(644
)

$
51

$
(1,385
)

$
(2
)

$
(1,980
)
Six Months Ended June 30, 2019

Beginning balance

$
(235
)

$
2

$
(1,465
)

$
(2
)

$
(1,700
)
Other comprehensive income before reclassifications:
   gains (losses)

(102
)

29

113

—

40

Amounts reclassified from AOCI: (gains) losses⁽¹⁾

(52
)

(1
)

30

—

(23
)
Net current period other comprehensive income (loss)

(154
)

28

143

—

17

Ending balance

$
(389
)

$
30

$
(1,322
)

$
(2
)

$
(1,683
)

~~(1)~~

~~See table below for details about these reclassifications.~~

~~The following table presents Dominion Energy’s reclassifications out of AOCI by component:~~

Details about AOCI components

Amounts
reclassified
from AOCI

Affected line item in the
Consolidated Statements of
Income
(millions)

Three Months Ended June 30, 2020

Deferred (gains) and losses on derivatives-hedging activities:

Commodity contracts

$
(9
)

Operating revenue
Interest rate contracts

22

Interest and related charges
Foreign currency contracts

(6
)

Other income
Total

7

Tax

(2
)

Income tax expense (benefit)
Total, net of tax

$
5

Unrealized (gains) and losses on investment securities:

Realized (gains) losses on sale of securities

$
(5
)

Other income
Total

(5
)

Tax

—

Income tax expense (benefit)
Total, net of tax

$
(5
)

Unrecognized pension and other postretirement benefit costs:

Amortization of prior-service costs (credits)

$
(5
)

Other income
Amortization of actuarial losses

31

Other income
Total

26

Tax

(8
)

Income tax expense (benefit)
Total, net of tax

$
18

Three Months Ended June 30, 2019

Deferred (gains) and losses on derivatives-hedging activities:

Commodity contracts

$
(38
)

Operating revenue
Interest rate contracts

13

Interest and related charges
Foreign currency contracts

(4
)

Other income
Total

(29
)

Tax

8

Income tax expense (benefit)
Total, net of tax

$
(21
)

Unrealized (gains) and losses on investment securities:

Realized (gains) losses on sale of securities

$
(1
)

Other income
Total

(1
)

Tax

—

Income tax expense (benefit)
Total, net of tax

$
(1
)

Unrecognized pension and other postretirement benefit costs:

Amortization of prior-service costs (credits)

$
(8
)

Other income
Amortization of actuarial losses

27

Other income
Total

19

Tax

3

Income tax expense (benefit)
Total, net of tax

$
22

Details about AOCI components

Amounts
reclassified
from AOCI

Affected line item in the
Consolidated Statements of
Income
(millions)

Six Months Ended June 30, 2020

Deferred (gains) and losses on derivatives-hedging activities:

Commodity contracts

$
(16
)

Operating revenue

3

Purchased gas
Interest rate contracts

49

Interest and related charges
Total

36

Tax

(9
)

Income tax expense (benefit)
Total, net of tax

$
27

Unrealized (gains) and losses on investment securities:

Realized (gains) losses on sale of securities

$
(18
)

Other income
Total

(18
)

Tax

4

Income tax expense (benefit)
Total, net of tax

$
(14
)

Unrecognized pension and other postretirement benefit costs:

Amortization of prior-service costs (credits)

$
(11
)

Other income
Amortization of actuarial losses

61

Other income
Total

50

Tax

(13
)

Income tax expense (benefit)
Total, net of tax

$
37

Six Months Ended June 30, 2019

Deferred (gains) and losses on derivatives-hedging activities:

Commodity contracts

$
(92
)

Operating revenue

(3
)

Purchased gas
Interest rate contracts

23

Interest and related charges
Foreign currency contracts

2

Other income
Total

(70
)

Tax

18

Income tax expense (benefit)
Total, net of tax

$
(52
)

Unrealized (gains) and losses on investment securities:

Realized (gains) losses on sale of securities

$
(1
)

Other income
Total

(1
)

Tax

—

Income tax expense (benefit)
Total, net of tax

$
(1
)

Unrecognized pension and other postretirement benefit costs:

Amortization of prior-service costs (credits)

$
(13
)

Other income
Amortization of actuarial losses

54

Other income
Total

41

Tax

(11
)

Income tax expense (benefit)
Total, net of tax

$
30

~~Virginia Power~~

~~The following table presents Virginia Power’s changes in AOCI by component, net of tax:~~

Deferred gains
and losses on
derivatives-
hedging
activities

Unrealized gains
and losses on
investment
securities

Total

(millions)

Three Months Ended June 30, 2020

Beginning balance

$
(79
)

$
4

$
(75
)
Other comprehensive income before reclassifications:
   gains (losses)

1

6

7

Amounts reclassified from AOCI: (gains) losses⁽¹⁾

—

(2
)

(2
)
Net current period other comprehensive income (loss)

1

4

5

Ending balance

$
(78
)

$
8

$
(70
)
Three Months Ended June 30, 2019

Beginning balance

$
(20
)

$
3

$
(17
)
Other comprehensive income before reclassifications:
   gains (losses)

(11
)

2

(9
)
Amounts reclassified from AOCI: (gains) losses⁽¹⁾

1

(1
)

—

Net current period other comprehensive income (loss)

(10
)

1

(9
)
Ending balance

$
(30
)

$
4

$
(26
)
Six Months Ended June 30, 2020

Beginning balance

$
(34
)

$
5

$
(29
)
Other comprehensive income before reclassifications:
   gains (losses)

(44
)

4

(40
)
Amounts reclassified from AOCI: (gains) losses⁽¹⁾

—

(1
)

(1
)
Net current period other comprehensive income (loss)

(44
)

3

(41
)
Ending balance

$
(78
)

$
8

$
(70
)
Six Months Ended June 30, 2019

Beginning balance

$
(13
)

$
1

$
(12
)
Other comprehensive income before reclassifications:
   gains (losses)

(18
)

4

(14
)
Amounts reclassified from AOCI: (gains) losses⁽¹⁾

1

(1
)

—

Net current period other comprehensive income (loss)

(17
)

3

(14
)
Ending balance

$
(30
)

$
4

$
(26
)

~~(1)~~

~~See table below for details about these reclassifications. Virginia Power’s reclassifications out of AOCI were immaterial for both the three and six months ended June 30, 2019.~~

~~The following table presents Virginia Power’s reclassifications out of AOCI by component:~~

Details about AOCI components

Amounts
reclassified
from AOCI

Affected line item in the
Consolidated Statements of
Income
(millions)

Three Months Ended June 30, 2020

(Gains) losses on cash flow hedges:

Interest rate contracts

$
1

Interest and related charges
Total

1

Tax

(1
)

Income tax expense
Total, net of tax

$
—

Unrealized (gains) and losses on investment securities:

Realized (gains) losses on sale of securities

$
(4
)

Other income
Total

(4
)

Tax

2

Income tax expense
Total, net of tax

$
(2
)

Six Months Ended June 30, 2020

(Gains) losses on cash flow hedges:

Interest rate contracts

1

Interest and related charges
Total

1

Tax

(1
)

Income tax expense
Total, net of tax

$
—

Unrealized (gains) and losses on investment securities:

Realized (gains) losses on sale of securities

$
(2
)

Other income
Total

(2
)

Tax

1

Income tax expense
Total, net of tax

$
(1
)

~~Dominion Energy Gas~~

~~The following table presents Dominion Energy Gas’ changes in AOCI by component, net of tax:~~

Deferred gains
and losses on
derivatives-
hedging
activities

Unrecognized
pension costs

Total

(millions)

Three Months Ended June 30, 2020

Beginning balance

$
(166
)

$
(105
)

$
(271
)
Amounts reclassified from AOCI: (gains) losses⁽¹⁾

(2
)

2

—

Net current period other comprehensive income (loss)

(2
)

2

—

Ending balance

$
(168
)

$
(103
)

$
(271
)
Three Months Ended June 30, 2019

Beginning balance

$
(48
)

$
(143
)

$
(191
)
Other comprehensive income before reclassifications:
   gains (losses)

(24
)

29

5

Amounts reclassified from AOCI: (gains) losses⁽¹⁾

(2
)

2

—

Net current period other comprehensive income (loss)

(26
)

31

5

Ending balance

$
(74
)

$
(112
)

$
(186
)
Six Months Ended June 30, 2020

Beginning balance

$
(81
)

$
(106
)

$
(187
)
Other comprehensive income before reclassifications:
   gains (losses)

(91
)

—

(91
)
Amounts reclassified from AOCI: (gains) losses⁽¹⁾

4

3

7

Net current period other comprehensive income (loss)

(87
)

3

(84
)
Ending balance

$
(168
)

$
(103
)

$
(271
)
Six Months Ended June 30, 2019

Beginning balance

$
(25
)

$
(144
)

$
(169
)
Other comprehensive income before reclassifications:
   gains (losses)

(51
)

29

(22
)
Amounts reclassified from AOCI: (gains) losses⁽¹⁾

1

3

4

Net current period other comprehensive income (loss)

(50
)

32

(18
)
Less other comprehensive income (loss) attributable to noncontrolling interest

(1
)

—

(1
)
Ending balance

$
(74
)

$
(112
)

$
(186
)

~~(1)~~

~~See table below for details about these reclassifications.~~

~~The following table presents Dominion Energy Gas’ reclassifications out of AOCI by component:~~

Details about AOCI components

Amounts
reclassified
from AOCI

Affected line item in the
Consolidated Statements of Income
(millions)

Three Months Ended June 30, 2020

Deferred (gains) and losses on derivatives-hedging activities:

Interest rate contracts

$
4

Interest and related charges
Foreign currency contracts

(6
)

Other income
Total

(2
)

Tax

—

Income tax expense (benefit)
Total, net of tax

$
(2
)

Unrecognized pension and other postretirement benefit costs:

Actuarial losses

$
2

Other income
Total

2

Tax

—

Income tax expense (benefit)
Total, net of tax

$
2

Three Months Ended June 30, 2019

Deferred (gains) and losses on derivatives-hedging activities:

Interest rate contracts

$
2

Interest and related charges
Foreign currency contracts

(4
)

Other income
Total

(2
)

Tax

—

Income tax expense (benefit)
Total, net of tax

$
(2
)

Unrecognized pension and other postretirement benefit costs:

Actuarial losses

$
2

Other income
Total

2

Tax

—

Income tax expense (benefit)
Total, net of tax

$
2

Six Months Ended June 30, 2020

Deferred (gains) and losses on derivatives-hedging activities:

Interest rate contracts

$
6

Interest and related charges
Total

6

Tax

(2
)

Income tax expense (benefit)
Total, net of tax

$
4

Unrecognized pension and other postretirement benefit costs:

Actuarial losses

$
4

Other income
Total

4

Tax

(1
)

Income tax expense (benefit)
Total, net of tax

$
3

Six Months Ended June 30, 2019

Deferred (gains) and losses on derivatives-hedging activities:

Commodity contracts

$
(2
)

Net income from discontinued operations
Interest rate contracts

1

Interest and related charges
Foreign currency contracts

2

Other income
Total

1

Tax

—

Income tax expense (benefit)
Total, net of tax

$
1

Unrecognized pension and other postretirement benefit costs:

Actuarial losses

$
4

Other income
Total

4

Tax

(1
)

Income tax expense (benefit)
Total, net of tax

$
3

~~Note 8. Fair Value Measurements~~

~~The Companies’ fair value measurements are made in accordance with the policies discussed in Note 6 to the Consolidated Financial Statements in the Companies’~~each Registrant's Annual Report on Form 10-K for the year ended December 31, ~~2019. See Note 9~~2020 and new regulatory matters occurring in ~~this report~~2021.

PacifiCorp

Utah

In March 2020, PacifiCorp filed its annual EBA application with the UPSC requesting recovery of $37 million of deferred power costs from customers for ~~further information about~~ the ~~Companies’ derivatives~~period January 1, 2019 through December 31, 2019, reflecting the difference between base and ~~hedge accounting activities.~~

actual net power costs in the 2019 deferral period. This reflected a 1.0% increase compared to current rates. The ~~Companies enter into certain physical~~UPSC approved the request in February 2021 for rates effective March 1, 2021.

Oregon

In February 2020, PacifiCorp filed a general rate case, and ~~financial forwards, futures, options and swaps, which are considered Level 3 as they have one~~in December 2020, the OPUC approved a net rate decrease of approximately $24 million, or ~~more inputs that are not observable and are significant~~1.8%, effective January 1, 2021, accepting PacifiCorp's proposed annual credit to customers of the remaining 2017 Tax Reform benefits over a two-year period. PacifiCorp's compliance filing to reset base rates effective January 1, 2021 in response to the ~~valuation. The discounted cash flow method is used~~OPUC's order reflected a rate decrease of approximately $67 million, or 5.1%, due to ~~value Level 3 physical~~the exclusion of the impacts of repowered wind facilities, new wind facilities and ~~financial forwards, futures~~certain other new investments that had not been placed in service at the time of the filing. Additional compliance filings will be made to include these investments in rates concurrent when they are placed in service. In January 2021, the OPUC approved the second compliance filing to add the remainder of the Ekola Flats wind facility to rates, resulting in a rate increase of approximately $7 million, or 0.5%, effective January 12, 2021. In April 2021, the OPUC approved the third compliance filing to add the Foote Creek repowered wind facility and ~~swaps contracts. An option model is used~~the Pryor Mountain new wind facility to ~~value Level 3 physical options. The discounted cash flow model~~rates, resulting in a rate increase of $14 million, or 1.2%, effective April 9, 2021.

Wyoming

In September 2018, PacifiCorp filed an application for ~~forwards, futures and swaps calculates mark-to-market valuations~~depreciation rate changes with the WPSC based on ~~forward market prices, original transaction prices, volumes, risk-free~~PacifiCorp's 2018 depreciation rate study, requesting the rates become effective January 1, 2021. Updates since September 2018 include the filing of ~~return~~PacifiCorp's 2020 decommissioning studies in which a third‑party consultant was engaged to estimate decommissioning costs associated with coal-fueled generating facilities and ~~credit spreads.~~removal of Cholla Unit 4. In April 2020, PacifiCorp filed a stipulation with the WPSC resolving all issues addressed in PacifiCorp's depreciation rate study application with ratemaking treatment of certain matters to be addressed in PacifiCorp's general rate case, including depreciation for coal-fueled generating facilities and associated incremental decommissioning costs reflected in decommissioning studies and certain matters related to the repowering of PacifiCorp's wind-powered generating facilities. The ~~option model calculates mark-to-market valuations using variations of~~stipulation was approved by the Black-Scholes option model. The inputs into the models are the forward market prices, implied price volatilities, risk-free rate of return, the option expiration dates, the option strike prices, the original sales pricesWPSC during a hearing in August 2020 and ~~volumes. For Level 3 fair value measurements, certain forward market prices and implied price volatilities are considered unobservable.~~

~~The following table presents Dominion Energy’s quantitative information about Level 3 fair value measurements at June 30,~~a subsequent written order in December 2020. The ~~range and weighted average are presented in dollars~~general rate case hearing was rescheduled for ~~market price inputs and percentages for price volatility.~~

Fair Value
(millions)

Valuation Techniques

Unobservable Input

Range

Weighted
Average⁽¹⁾

Assets

Physical and financial forwards:

Natural gas⁽²⁾

$
112

Discounted cash flow

Market price (per Dth)
⁽³⁾

(2) - 3

(1
)
FTRs

18

Discounted cash flow

Market price (per MWh)
⁽³⁾

(1) - 5

1

Total assets

$
130

Liabilities

Financial forwards:

FTRs

$
5

Discounted cash flow

Market price (per MWh)
⁽³⁾

(5) - 5

—

Physical options:

Natural gas

2

Option model

Market price (per Dth)
⁽³⁾

1 - 5

2

Price volatility
⁽⁴⁾

56% - 72%

66
%
Total liabilities

$
7

~~(1)~~

~~Averages weighted by volume.~~

~~(2)~~

~~Includes basis.~~

~~(3)~~

~~Represents market prices beyond defined terms for Levels 1 and 2.~~

~~(4)~~

~~Represents volatilities unrepresented in published markets.~~

~~Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:~~

~~Significant Unobservable~~ ~~Inputs~~	~~Position~~	~~Change to Input~~	~~Impact on Fair Value~~ ~~Measurement~~
~~Market price~~	~~Buy~~	~~Increase (decrease)~~	~~Gain (loss)~~
~~Market price~~	~~Sell~~	~~Increase (decrease)~~	~~Loss (gain)~~
~~Price volatility~~	~~Buy~~	~~Increase (decrease)~~	~~Gain (loss)~~
~~Price volatility~~	~~Sell~~	~~Increase (decrease)~~	~~Loss (gain)~~

~~Recurring Fair Value Measurements~~

~~Dominion Energy~~

~~The following table presents Dominion Energy’s assets and liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions:~~

Level 1

Level 2

Level 3

Total

(millions)

At June 30, 2020

Assets

Derivatives:

Commodity

$
—

$
52

$
130

$
182

Interest rate

—

34

—

34

Investments⁽¹⁾:

Equity securities:

U.S.

3,817

—

—

3,817

Fixed income:

Corporate debt instruments

—

624

—

624

Government securities

488

746

—

1,234

Cash equivalents and other

19

12

—

31

Total assets

$
4,324

$
1,468

$
130

$
5,922

Liabilities

Derivatives:

Commodity

$
—

$
43

$
7

$
50

Interest rate

—

1,272

—

1,272

Foreign currency

—

12

—

12

Total liabilities

$
—

$
1,327

$
7

$
1,334

At December 31, 2019

Assets

Derivatives:

Commodity

$
—

$
55

$
19

$
74

Interest rate

—

11

—

11

Foreign currency

—

8

—

8

Investments⁽¹⁾:

Equity securities:

U.S.

4,195

—

—

4,195

Fixed income:

Corporate debt instruments

—

463

—

463

Government securities

473

719

—

1,192

Cash equivalents and other

19

1

—

20

Total assets

$
4,687

$
1,257

$
19

$
5,963

Liabilities

Derivatives:

Commodity

$
—

$
75

$
56

$
131

Interest rate

—

606

—

606

Foreign currency

—

3

—

3

Total liabilities

$
—

$
684

$
56

$
740

~~(1)~~

Includes investments held in the nuclear decommissioning and rabbi trusts. Excludes $296 million and $274 million of assets at June 30, 2020 and December 31, 2019, respectively, measured at fair value using NAV (or its equivalent) as a practical expedient which are not required to be categorized in the fair value hierarchy.

~~The following table presents the net change in Dominion Energy's assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category:~~

Three Months Ended

Six Months Ended

June 30,

June 30,

2020

2019

2020

2019

(millions)

Beginning balance

$
43

$
53

$
(37
)

$
64

Total realized and unrealized gains (losses):

Included in earnings:

Operating revenue

—

3

—

2

Purchased gas

—

1

—

1

Electric fuel and other energy-related purchases

(4
)

(3
)

(26
)

(7
)
Included in regulatory assets/liabilities

80

18

160

25

Settlements

4

3

26

2

Purchases

—

—

—

(10
)
Transfers out of Level 3

—

—

—

(2
)
Ending balance

$
123

$
75

$
123

$
75

The amount of total gains (losses) for the period included in
   earnings attributable to the change in unrealized gains
   (losses) relating to assets/liabilities still held at the
   reporting date:

Operating revenue

$
—

$
2

$
—

$
2

Purchased gas

—

1

—

1

Total

$
—

$
3

$
—

$
3

There were no unrealized gains or losses included in earnings in the Level 3 fair value category relating to assets/liabilities still held at the reporting date for the three and six months ended June 30, 2020 and 2019.

~~Virginia Power~~

The following table presents Virginia Power’s quantitative information about Level 3 fair value measurements at June 30, 2020. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility.

Fair Value
(millions)

Valuation Techniques

Unobservable Input

Range

Weighted
Average⁽¹⁾

Assets

Physical and financial forwards:

Natural gas⁽²⁾

$
112

Discounted cash flow

Market price (per Dth)
⁽³⁾

(2) - 2

(1
)
FTRs

18

Discounted cash flow

Market price (per MWh)
⁽³⁾

(1) - 5

1

Total assets

$
130

Liabilities

Financial forwards:

FTRs

$
5

Discounted cash flow

Market price (per MWh)
⁽³⁾

(5) - 5

—

Physical options:

Natural gas

2

Option model

Market price (per Dth)
⁽³⁾

1 - 5

2

Price volatility
⁽⁴⁾

56% - 72%

66
%
Total liabilities

$
7

~~(1)~~

~~Averages weighted by volume.~~

~~(2)~~

~~Includes basis.~~

~~(3)~~

~~Represents market prices beyond defined terms for Levels 1 and 2.~~

~~(4)~~

~~Represents volatilities unrepresented in published markets~~.

~~Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:~~

~~Significant Unobservable~~ ~~Inputs~~	~~Position~~	~~Change to Input~~	~~Impact on Fair Value~~ ~~Measurement~~
~~Market price~~	~~Buy~~	~~Increase (decrease)~~	~~Gain (loss)~~
~~Market price~~	~~Sell~~	~~Increase (decrease)~~	~~Loss (gain)~~
~~Price volatility~~	~~Buy~~	~~Increase (decrease)~~	~~Gain (loss)~~
~~Price volatility~~	~~Sell~~	~~Increase (decrease)~~	~~Loss (gain)~~

~~The following table presents Virginia Power’s assets and liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions:~~

Level 1

Level 2

Level 3

Total

(millions)

At June 30, 2020

Assets

Derivatives:

Commodity

$
—

$
3

$
130

$
133

Investments⁽¹⁾:

Equity securities:

U.S.

1,787

—

—

1,787

Fixed income:

Corporate debt instruments

—

354

—

354

Government securities

184

306

—

490

Total assets

$
1,971

$
663

$
130

$
2,764

Liabilities

Derivatives:

Commodity

$
—

$
17

$
7

$
24

Interest rate

—

980

—

980

Total liabilities

$
—

$
997

$
7

$
1,004

At December 31, 2019

Assets

Derivatives:

Commodity

$
—

$
3

$
19

$
22

Interest rate

—

2

—

2

Investments⁽¹⁾:

Equity securities:

U.S.

1,920

—

—

1,920

Fixed income:

Corporate debt instruments

—

256

—

256

Government securities

186

361

—

547

Cash equivalents and other

—

1

—

1

Total assets

$
2,106

$
623

$
19

$
2,748

Liabilities

Derivatives:

Commodity

$
—

$
47

$
56

$
103

Interest rate

—

363

—

363

Total liabilities

$
—

$
410

$
56

$
466

~~(1)~~

Includes investments held in the nuclear decommissioning trusts. Excludes $154 million and $159 million of assets at June 30, 2020 and December 31, 2019, respectively, measured at fair value using NAV (or its equivalent) as a practical expedient which are not required to be categorized in the fair value hierarchy.

~~The following table presents the net change in Virginia Power’s assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category:~~

Three Months Ended

Six Months Ended

June 30,

June 30,

2020

2019

2020

2019

(millions)

Beginning balance

$
43

$
59

$
(37
)

$
60

Total realized and unrealized gains (losses):

Included in earnings:

Electric fuel and other energy-related purchases

(4
)

(3
)

(26
)

(7
)
Included in regulatory assets/liabilities

80

18

160

26

Settlements

4

3

26

(2
)
Ending balance

$
123

$
77

$
123

$
77

There were 0 unrealized gains or losses included in earnings in the Level 3 fair value category relating to assets/liabilities still held at the reporting date for the three and six months ended June 30, 2020 and 2019.

~~Dominion Energy Gas~~

The following table presents Dominion Energy Gas’ assets and liabilities for derivatives that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions.

Level 1

Level 2

Level 3

Total

(millions)

At June 30, 2020

Liabilities

Interest rate

$
—

$
192

$
—

$
192

Foreign currency

—

12

—

12

Total liabilities

$
—

$
204

$
—

$
204

At December 31, 2019

Assets

Foreign currency

$
—

$
8

$
—

$
8

Total assets

$
—

$
8

$
—

$
8

Liabilities

Interest rate

$
—

$
83

$
—

$
83

Foreign currency

—

3

—

3

Total liabilities

$
—

$
86

$
—

$
86

~~Fair Value of Financial Instruments~~

Substantially all of the Companies’ financial instruments are recorded at fair value, with the exception of the instruments described below, which are reported at historical cost. Estimated fair values have been determined using available market information and valuation methodologies considered appropriate by management. The carrying amount of cash, restricted cash and equivalents, customer and other receivables, affiliated receivables, short-term debt, affiliated current borrowings, payables to affiliates and accounts payable are representative of fair value because of the short-term nature of these instruments. For the Companies' financial instruments that are not recorded at fair value, the carrying amounts and estimated fair values are as follows:

June 30, 2020

December 31, 2019

Carrying
Amount

Estimated
Fair
Value⁽¹⁾

Carrying
Amount

Estimated
Fair
Value⁽¹⁾

(millions)

Dominion Energy

Long-term debt⁽²⁾

$
36,060

$
42,151

$
32,055

$
36,155

Supplemental 364-Day credit facility borrowings

225

225

—

—

Junior subordinated notes⁽³⁾

3,408

3,554

4,797

4,953

Virginia Power

Long-term debt⁽³⁾

$
12,328

$
15,189

$
12,326

$
14,281

Dominion Energy Gas

Long-term debt⁽⁴⁾

$
5,523

$
5,891

$
5,520

$
5,738

~~(1)~~

Fair value is estimated using market prices, where available, and interest rates currently available for issuance of debt with similar terms and remaining maturities. All fair value measurements are classified as Level 2. The carrying amount of debt issuances with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value.

~~(2)~~

Carrying amount includes current portions included in securities due within one year and amounts which represent the unamortized debt issuance costs, discount or premium and foreign currency remeasurement adjustments. At June 30, 2020 and December 31, 2019, includes the valuation of certain fair value hedges associated with fixed rate debt of $4 million and $4 million, respectively.

~~(3)~~

~~Carrying amount includes current portions included in securities due within one year and amounts which represent the unamortized debt issuance costs, discount or premium.~~

~~(4)~~

~~Note 9. Derivatives and Hedge Accounting Activities~~

The Companies’ accounting policies, objectives and strategies for using derivative instruments are discussed in Note 2 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019. See Note 8 in this report for further information about fair value measurements and associated valuation methods for derivatives.

Derivative assets and liabilities are presented gross on the Companies’ Consolidated Balance Sheets. Dominion Energy’s derivative contracts include both over-the-counter transactions and those that are executed on an exchange or other trading platform (exchange contracts) and centrally cleared. Virginia Power and Dominion Energy Gas’ derivative contracts include over-the-counter transactions. Over-the-counter contracts are bilateral contracts that are transacted directly with a third party. Exchange contracts utilize a financial intermediary, exchange, or clearinghouse to enter, execute or clear the transactions. Certain over-the-counter and exchange contracts contain contractual rights of setoff through master netting arrangements, derivative clearing agreements and contract default provisions. In addition, the contracts are subject to conditional rights of setoff through counterparty nonperformance, insolvency or other conditions.

In general, most over-the-counter transactions and all exchange contracts are subject to collateral requirements. Types of collateral for over-the-counter and exchange contracts include cash, letters of credit, and in some cases other forms of security, none of which are subject to restrictions. Cash collateral is used in the table below to offset derivative assets and liabilities. Certain accounts receivable and accounts payable recognized on the Companies’ Consolidated Balance Sheets, as well as letters of credit and other forms of security, all of which are not included in the tables below, are subject to offset under master netting or similar arrangements and would reduce the net exposure. See Note 18 for further information regarding credit-related contingent features for the Companies’ derivative instruments.

~~Dominion Energy~~

~~Balance Sheet Presentation~~

The tables below present Dominion Energy’s derivative asset and liability balances by type of financial instrument, if the gross amounts recognized in its Consolidated Balance Sheets were netted with derivative instruments and cash collateral received or paid:

June 30, 2020

December 31, 2019

Gross Amounts Not Offset
in the Consolidated
Balance Sheet

Gross Amounts Not Offset
in the Consolidated
Balance Sheet

Gross Assets
Presented in the
Consolidated
Balance Sheet⁽¹⁾

Financial
Instruments

Cash
Collateral
Received

Net
Amounts

Gross Assets
Presented in the
Consolidated
Balance Sheet⁽¹⁾

Financial
Instruments

Cash
Collateral
Received

Net
Amounts

(millions)

Commodity contracts:

Over-the-counter

$
136

$
9

$
—

$
127

$
35

$
21

$
—

$
14

Exchange

45

20

7

18

37

21

—

16

Interest rate contracts:

Over-the-counter

34

14

—

20

11

3

—

8

Foreign currency contracts:

Over-the-counter

—

—

—

—

8

8

—

—

Total derivatives, subject to a
master netting or similar
arrangement

$
215

$
43

$
7

$
165

$
91

$
53

$
—

$
38

~~(1)~~

~~Excludes $1million and $2 million of derivative assets at June 30, 2020 and December 31, 2019, respectively, which are not subject to master netting or similar arrangements.~~

June 30, 2020

December 31, 2019

Gross Amounts Not Offset
in the Consolidated
Balance Sheet

Gross Amounts Not Offset
in the Consolidated
Balance Sheet

Gross
Liabilities
Presented in the
Consolidated
Balance Sheet⁽¹⁾

Financial
Instruments

Cash
Collateral
Paid

Net
Amounts

Gross
Liabilities
Presented in the
Consolidated
Balance Sheet⁽¹⁾

Financial
Instruments

Cash
Collateral
Paid

Net
Amounts

(millions)

Commodity contracts:

Over-the-counter

$
30

$
9

$
—

$
21

$
105

$
21

$
—

$
84

Exchange

20

20

—

—

21

21

—

—

Interest rate contracts:

Over-the-counter

1,272

14

22

1,236

606

8

35

563

Foreign currency contracts:

Over-the-counter

12

—

—

12

3

3

—

—

Total derivatives, subject to a
master netting or similar
arrangement

$
1,334

$
43

$
22

$
1,269

$
735

$
53

$
35

$
647

~~(1)~~

~~Excludes $—million and $5 million of derivative liabilities at June 30, 2020 and December 31, 2019, respectively, which are not subject to master netting or similar arrangements.~~

~~Volumes~~

The following table presents the volume of Dominion Energy’s derivative activity at June 30, 2020. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of its long and short positions.

Current

Noncurrent

Natural Gas (bcf):

Fixed price⁽¹⁾

69

32

Basis

236

538

Electricity (MWh):

Fixed price

4,964,045

2,775,850

FTRs

101,087,887

—

Liquids (Gal)⁽²⁾

26,460,000

—

Interest rate⁽³⁾

$
1,950,000,000

$
6,576,403,434

Foreign currency⁽³⁾

€
-

€
250,000,000

~~(1)~~

~~Includes options.~~

~~(2)~~

~~Includes NGLs.~~

~~(3)~~

~~Maturity is determined based on final settlement period.~~

~~AOCI~~

~~The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in Dominion Energy’s Consolidated Balance Sheet at June 30, 2020:~~

AOCI
After-Tax

Amounts Expected to be
Reclassified to Earnings
During the Next 12 Months
After-Tax

Maximum Term
(millions)

Commodities:

Gas

$
(2
)

$
(2
)

18 months
Electricity

8

8

6 months
NGL

—

—

6 months
Interest rate

(640
)

(59
)

378 months
Foreign currency

(10
)

(4
)

72 months
Total

$
(644
)

$
(57
)

The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., anticipated sales) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies and will vary from the expected amounts presented above asFebruary 2021. As a result of ~~changes~~the hearing date change, PacifiCorp filed an application in ~~market prices, interest rates and foreign currency exchange rates.~~

~~In connection~~October 2020 with the ~~agreement Dominion Energy entered~~WPSC requesting authorization to defer costs associated with impacts of the depreciation study. A hearing for this deferral application is scheduled to occur in July 2020 for the disposition of substantially all of its gas transmission and storage operations, certain cash flow hedges of debt-related items will become probable of not occurring. See Note 3 for further information.

~~Fair Value Hedges~~

For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative instrument as well as the offsetting loss or gain on the hedged item attributable to the hedged risk are recognized in current earnings and presented in the same line item. There were 0 derivative instruments designated in fair value hedges during the three and six months ended June 30, 2020. Gains and losses on derivatives in fair value hedge relationships were immaterial for the three and six months ended June 30, 2019.

~~The following table presents the amounts recorded on the balance sheet related to cumulative basis adjustments for fair value hedges:~~

Carrying Amount of the Hedged Asset
(Liability)⁽¹⁾

Cumulative Amount of Fair Value Hedging
Adjustments Included in the Carrying Amount
of the Hedged Assets (Liabilities)⁽²⁾

June 30, 2020

December 31, 2019

June 30, 2020

December 31, 2019

(millions)

Long-term debt

$
(1,154
)

$
(1,154
)

$
(4
)

$
(4
)

~~(1)~~

~~Includes $(1.1) billion and $(397) million related to discontinued hedging relationships at June 30, 2020 and December 31, 2019, respectively.~~

2021.

~~(2)~~

~~Includes $(4) million and $3 million of hedging adjustments on discontinued hedging relationships at June 30, 2020 and December 31, 2019, respectively.~~

~~Fair Value and Gains and Losses on Derivative Instruments~~

~~The following table presents the fair values of Dominion Energy’s derivatives and where they are presented in its Consolidated Balance Sheets:~~

Fair Value –
Derivatives under
Hedge
Accounting

Fair Value –
Derivatives not under
Hedge
Accounting

Total Fair Value

(millions)

June 30, 2020

ASSETS

Current Assets

Commodity

$
—

$
73

$
73

Interest rate

—

8

8

Total current derivative assets⁽¹⁾

—

81

81

Noncurrent Assets

Commodity

—

109

109

Interest rate

—

26

26

Total noncurrent derivative assets⁽²⁾

—

135

135

Total derivative assets

$
—

$
216

$
216

LIABILITIES

Current Liabilities

Commodity

$
—

$
42

$
42

Interest rate

514

25

539

Foreign currency

5

—

5

Total current derivative liabilities

519

67

586

Noncurrent Liabilities

Commodity

—

8

8

Interest rate

655

78

733

Foreign currency

7

—

7

Total noncurrent derivative liabilities

662

86

748

Total derivative liabilities

$
1,181

$
153

$
1,334

December 31, 2019

ASSETS

Current Assets

Commodity

$
30

$
37

$
67

Interest rate

1

—

1

Total current derivative assets⁽¹⁾

31

37

68

Noncurrent Assets

Commodity

1

6

7

Interest rate

10

—

10

Foreign currency

8

—

8

Total noncurrent derivative assets⁽²⁾

19

6

25

Total derivative assets

$
50

$
43

$
93

LIABILITIES

Current Liabilities

Commodity

$
6

$
77

$
83

Interest rate

321

1

322

Foreign currency

3

—

3

Total current derivative liabilities

330

78

408

Noncurrent Liabilities

Commodity

1

47

48

Interest rate

267

17

284

Total noncurrent derivative liabilities

268

64

332

Total derivative liabilities

$
598

$
142

$
740

~~(1)~~

~~Current derivative assets are presented in other current assets in Dominion Energy’s Consolidated Balance Sheets.~~

~~(2)~~

~~Noncurrent derivative assets are presented in other deferred charges and other assets in Dominion Energy’s Consolidated Balance Sheets.~~

~~The following tables present the gains and losses on Dominion Energy’s derivatives, as well as where the associated activity is presented in its Consolidated Balance Sheets and Statements of Income.~~

Derivatives in cash flow hedging relationships

Amount of Gain
(Loss) Recognized
in AOCI on
Derivatives⁽¹⁾

Amount of Gain
(Loss) Reclassified
From AOCI to
Income

Increase
(Decrease) in
Derivatives
Subject to
Regulatory
Treatment⁽²⁾

(millions)

Three Months Ended June 30, 2020

Derivative type and location of gains (losses):

Commodity:

Operating revenue

$
9

Purchased gas

—

Total commodity

$
—

$
9

$
—

Interest rate⁽³⁾

—

(22
)

14

Foreign currency⁽⁴⁾

6

6

—

Total

$
6

$
(7
)

$
14

Three Months Ended June 30, 2019

Derivative type and location of gains (losses):

Commodity:

Operating revenue

$
38

Total commodity

$
35

$
38

$
—

Interest rate⁽³⁾

(142
)

(13
)

(131
)
Foreign currency⁽⁴⁾

2

4

—

Total

$
(105
)

$
29

$
(131
)
Six Months Ended June 30, 2020

Derivative type and location of gains (losses):

Commodity:

Operating revenue

$
16

Purchased gas

(3
)

Electric fuel and other energy-related
purchases

—

Total commodity

$
—

$
13

$
—

Interest rate⁽³⁾

(336
)

(49
)

(550
)
Foreign currency⁽⁴⁾

(17
)

—

—

Total

$
(353
)

$
(36
)

$
(550
)
Six Months Ended June 30, 2019

Derivative type and location of gains (losses):

Commodity:

Operating revenue

$
92

Purchased gas

3

Total commodity

$
101

$
95

$
—

Interest rate⁽³⁾

(226
)

(23
)

(215
)
Foreign currency⁽⁴⁾

(9
)

(2
)

—

Total

$
(134
)

$
70

$
(215
)

~~(1)~~

~~Amounts deferred into AOCI have no associated effect in Dominion Energy’s Consolidated Statements of Income.~~

~~(2)~~

Represents net derivative activity deferred into and amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Dominion Energy’s Consolidated Statements of Income.

~~(3)~~

~~Amounts recorded in Dominion Energy’s Consolidated Statements of Income are classified in interest and related charges.~~

~~(4)~~

~~Amounts recorded in Dominion Energy’s Consolidated Statements of Income are classified in other income (expense).~~

Derivatives not designated as hedging instruments

Amount of Gain (Loss) Recognized
in Income on Derivatives⁽¹⁾

Three Months Ended

Six Months Ended

June 30,

June 30,

2020

2019

2020

2019

(millions)

Derivative type and location of gains (losses):

Commodity:

Operating revenue

$
(10
)

$
27

$
55

$
30

Purchased gas

—

(11
)

(14
)

(8
)

Electric fuel and other energy-related
purchases

(8
)

(3
)

(73
)

(12
)

Interest rate⁽²⁾

(25
)

—

(86
)

—

Total

$
(43
)

$
13

$
(118
)

$
10

~~(1)~~

Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Dominion Energy’s Consolidated Statements of Income.

~~(2)~~

~~Amounts recorded in Dominion Energy’s Consolidated Statements of Income are classified in interest and related charges.~~

~~Virginia Power~~

~~Balance Sheet Presentation~~

The tables below present Virginia Power’s derivative asset and liability balances by type of financial instrument, if the gross amounts recognized in its Consolidated Balance Sheets were netted with derivative instruments and cash collateral received or paid:

June 30, 2020

December 31, 2019

Gross Amounts Not Offset
in the Consolidated
Balance Sheet

Gross Amounts Not Offset
in the Consolidated
Balance Sheet

Gross Assets Presented
in the
Consolidated
Balance Sheet⁽¹⁾

Financial Instruments

Cash
Collateral
Received

Net
Amounts

Gross
Assets Presented
in the
Consolidated
Balance Sheet⁽¹⁾

Financial
Instruments

Cash
Collateral
Received

Net
Amounts

(millions)

Commodity contracts:

Over-the-counter

$
129

$
5

$
—

$
124

$
19

$
18

$
—

$
1

Interest rate contracts:

Over-the-counter

—

—

—

—

2

—

—

2

Total derivatives, subject to a
master netting or similar
arrangement

$
129

$
5

$
—

$
124

$
21

$
18

$
—

$
3

~~(1)~~

~~Excludes $4million and $3 million of derivative assets at June 30, 2020 and December 31, 2019, respectively, which are not subject to master netting or similar arrangements.~~

June 30, 2020

December 31, 2019

Gross Amounts Not Offset
in the Consolidated
Balance Sheet

Gross Amounts Not Offset
in the Consolidated
Balance Sheet

Gross
Liabilities
Presented in the
Consolidated
Balance Sheet⁽¹⁾

Financial
Instruments

Cash
Collateral
Paid

Net
Amounts

Gross
Liabilities
Presented in the Consolidated Balance Sheet⁽¹⁾

Financial
Instruments

Cash
Collateral
Paid

Net
Amounts

(millions)

Commodity contracts:

Over-the-counter

$
5

$
5

$
—

$
—

$
59

$
18

$
—

$
41

Interest rate contracts:

Over-the-counter

980

—

—

980

363

—

—

363

Total derivatives, subject to a
master netting or similar
arrangement

$
985

$
5

$
—

$
980

$
422

$
18

$
—

$
404

~~(1)~~

~~Excludes $19million and $44 million of derivative liabilities at June 30, 2020 and December 31, 2019, respectively, which are not subject to master netting or similar arrangements.~~

~~Volumes~~

The following table presents the volume of Virginia Power’s derivative activity at June 30, 2020. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of its long and short positions.

Current

Noncurrent

Natural Gas (bcf):

Fixed price⁽¹⁾

38

8

Basis

143

507

Electricity (MWh):

FTRs

101,087,887

—

Interest rate⁽²⁾

$
900,000,000

$
1,150,000,000

~~(1)~~

~~Includes options.~~

~~(2)~~

~~Maturity is determined based on final settlement period.~~

~~AOCI~~

~~The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in Virginia Power’s Consolidated Balance Sheet at June 30, 2020:~~

AOCI
After-Tax

Amounts Expected to be
Reclassified to Earnings
During the Next 12
Months After-Tax

Maximum Term
(millions)

Interest rate

$
(78
)

$
(1
)

378 months
Total

$
(78
)

$
(1
)

The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., interest payments) in earnings, thereby achieving the realization of interest rates contemplated by the underlying risk management strategies and will vary from the expected amounts presented above as a result of changes in interest rates.

~~Fair Value and Gains and Losses on Derivative Instruments~~

~~The following table presents the fair values of Virginia Power’s derivatives and where they are presented in its Consolidated Balance Sheets:~~

Fair Value –
Derivatives under
Hedge
Accounting

Fair Value –
Derivatives not under
Hedge
Accounting

Total Fair Value

(millions)

June 30, 2020

ASSETS

Current Assets

Commodity

$
—

$
31

$
31

Total current derivative assets⁽¹⁾

—

31

31

Noncurrent Assets

Commodity

—

102

102

Total noncurrent derivative assets⁽²⁾

—

102

102

Total derivative assets

$
—

$
133

$
133

LIABILITIES

Current Liabilities

Commodity

$
—

$
23

$
23

Interest rate

455

—

455

Total current derivative liabilities

455

23

478

Noncurrent Liabilities

Commodity

—

1

1

Interest rate

525

—

525

Total noncurrent derivatives liabilities⁽³⁾

525

1

526

Total derivative liabilities

$
980

$
24

$
1,004

December 31, 2019

ASSETS

Current Assets

Commodity

$
—

$
20

$
20

Total current derivative assets⁽¹⁾

—

20

20

Noncurrent Assets

Commodity

—

2

2

Interest rate

2

—

2

Total noncurrent derivative assets⁽²⁾

2

2

4

Total derivative assets

$
2

$
22

$
24

LIABILITIES

Current Liabilities

Commodity

$
—

$
58

$
58

Interest rate

185

—

185

Total current derivatives liabilities⁽⁴⁾

185

58

243

Noncurrent Liabilities

Commodity

—

45

45

Interest rate

178

—

178

Total noncurrent derivatives liabilities⁽³⁾

178

45

223

Total derivative liabilities

$
363

$
103

$
466

~~(1)~~

~~Current derivative assets are presented in other current assets in Virginia Power’s Consolidated Balance Sheets.~~

~~(2)~~

~~Noncurrent derivative assets are presented in other deferred charges and other assets in Virginia Power’s Consolidated Balance Sheets.~~

~~(3)~~

~~Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Virginia Power’s Consolidated Balance Sheets.~~

~~(4)~~

~~Current derivative liabilities are presented in other current liabilities in Virginia Power’s Consolidated Balance Sheets.~~

~~The following tables present the gains and losses on Virginia Power’s derivatives, as well as where the associated activity is presented in its Consolidated Balance Sheets and Statements of Income:~~

~~(1)~~

~~Amounts deferred into AOCI have no associated effect in Virginia Power’s Consolidated Statements of Income.~~

~~(2)~~

Represents net derivative activity deferred into and amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Virginia Power’s Consolidated Statements of Income.

~~(3)~~

~~Amounts recorded in Virginia Power’s Consolidated Statements of Income are classified in interest and related charges.~~

~~(1)~~

Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Virginia Power’s Consolidated Statements of Income.

~~(2)~~

~~Amounts recorded in Virginia Power’s Consolidated Statements of Income are classified in electric fuel and other energy-related purchases.~~

~~Dominion Energy Gas~~

~~Balance Sheet Presentation~~

The tables below present Dominion Energy Gas’ derivative asset and liability balances by type of financial instrument, if the gross amounts recognized in its Consolidated Balance Sheets were netted with derivative instruments and cash collateral received or paid:

June 30, 2020

December 31, 2019

Gross Amounts Not Offset
in the Consolidated
Balance Sheet

Gross Amounts Not Offset
in the Consolidated
Balance Sheet

Gross Assets
Presented in the
Consolidated
Balance Sheet

Financial
Instruments

Cash
Collateral
Received

Net
Amounts

Gross Assets
Presented in the
Consolidated
Balance Sheet

Financial
Instruments

Cash
Collateral
Received

Net
Amounts

(millions)

Foreign currency contracts:

Over-the-counter

$
—

$
—

$
—

$
—

$
8

$
8

$
—

$
—

Total derivatives, subject to a
master netting or similar
arrangement

$
—

$
—

$
—

$
—

$
8

$
8

$
—

$
—

June 30, 2020

December 31, 2019

Gross Amounts Not Offset
in the Consolidated
Balance Sheet

Gross Amounts Not Offset
in the Consolidated
Balance Sheet

Gross
Liabilities Presented
in the Consolidated
Balance Sheet

Financial
Instruments

Cash
Collateral
Paid

Net
Amounts

Gross
Liabilities Presented
in the Consolidated
Balance Sheet

Financial
Instruments

Cash
Collateral
Paid

Net
Amounts

(millions)

Interest rate contracts:

Over-the-counter

$
192

$
—

$
—

$
192

$
83

$
5

$
—

$
78

Foreign currency contracts:

Over-the-counter

12

—

—

12

3

3

—

—

Total derivatives, subject to a
master netting or similar
arrangement

$
204

$
—

$
—

$
204

$
86

$
8

$
—

$
78

~~Volumes~~

The following table presents the volume of Dominion Energy Gas’ derivative activity at June 30, 2020. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of its long and short positions.

Current

Noncurrent

Interest rate⁽¹⁾

$
750,000,000

$
550,000,000

Foreign currency⁽¹⁾

€
-

€
250,000,000

~~(1)~~

~~Maturity is determined based on final settlement period.~~

~~AOCI~~

~~The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in Dominion Energy Gas’ Consolidated Balance Sheet at June 30, 2020:~~

AOCI
After-Tax

Amounts Expected
to be Reclassified to
Earnings During the
Next 12 Months
After-Tax

Maximum Term
(millions)

Interest rate

$
(158
)

$
(11
)

294 months
Foreign currency

(10
)

(4
)

72 months
Total

$
(168
)

$
(15
)

The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., interest payments) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies and will vary from the expected amounts presented above as a result of changes in interest rates and foreign currency exchange rates.

In connection with the agreement Dominion Energy entered in July 2020 for the disposition of substantially all of its gas transmission and storage operations, certain cash flow hedges of debt-related items will become probable of not occurring. See Note 3 for further information.

~~Fair Value and Gains and Losses on Derivative Instruments~~

~~The following tables present the fair values of Dominion Energy Gas’ derivatives and where they are presented in its Consolidated Balance Sheets:~~

Fair Value-
Derivatives
Under Hedge
Accounting

Fair Value-Derivatives
Not Under Hedge
Accounting

Total Fair Value

(millions)

June 30, 2020

LIABILITIES

Current Liabilities

Interest rate

$
58

$
13

$
71

Foreign currency

5

—

5

Total current derivative liabilities⁽²⁾

63

13

76

Noncurrent Liabilities

Interest rate

121

—

121

Foreign currency

7

—

7

Total noncurrent derivative liabilities⁽³⁾

128

—

128

Total derivative liabilities

$
191

$
13

$
204

December 31, 2019

ASSETS

Noncurrent Assets

Foreign currency

$
8

$
—

$
8

Total noncurrent derivative assets⁽¹⁾

8

—

8

Total derivative assets

$
8

$
—

$
8

LIABILITIES

Current Liabilities

Interest rate

$
30

$
—

$
30

Foreign currency

3

—

3

Total current derivative liabilities⁽²⁾

33

—

33

Noncurrent Liabilities

Interest rate

53

—

53

Total noncurrent derivative liabilities⁽³⁾

53

—

53

Total derivative liabilities

$
86

$
—

$
86

~~(1)~~

~~Noncurrent derivatives assets are presented in other deferred charges and other assets in Dominion Energy Gas’ Consolidated Balance Sheets.~~

~~(2)~~

~~Current derivative liabilities are presented in other current liabilities in Dominion Energy Gas’ Consolidated Balance Sheets.~~

~~(3)~~

~~Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Dominion Energy Gas’ Consolidated Balance Sheets.~~

The following table presents the gains and losses on Dominion Energy Gas’ derivatives, as well as where the associated activity is presented in its Consolidated Balance Sheets and Statements of Income:

Derivatives in cash flow hedging relationships

Amount of Gain
(Loss) Recognized in AOCI on
Derivatives⁽¹⁾

Amount of Gain
(Loss) Reclassified From AOCI
to Income

(millions)

Three Months Ended June 30, 2020

Derivative type and location of gains (losses):

Interest rate⁽²⁾

$
(4
)

$
(4
)
Foreign currency⁽³⁾

5

6

Total

$
1

$
2

Three Months Ended June 30, 2019

Derivative type and location of gains (losses):

Commodity:

Net income from discontinued operations

$
—

Total commodity

$
3

$
—

Interest rate⁽²⁾

(36
)

(2
)
Foreign currency⁽³⁾

1

4

Total

$
(32
)

$
2

Six Months Ended June 30, 2020

Derivative type and location of gains (losses):

Interest rate⁽²⁾

(105
)

(6
)
Foreign currency⁽³⁾

(17
)

—

Total

$
(122
)

$
(6
)
Six Months Ended June 30, 2019

Derivative type and location of gains (losses):

Commodity:

Net income from discontinued operations

$
2

Total commodity

$
2

$
2

Interest rate⁽²⁾

(60
)

(1
)
Foreign currency⁽³⁾

(10
)

(2
)
Total

$
(68
)

$
(1
)

~~(1)~~

~~Amounts deferred into AOCI have no associated effect in Dominion Energy Gas’ Consolidated Statements of Income.~~

~~(2)~~

~~Amounts recorded in Dominion Energy Gas’ Consolidated Statements of Income are classified in interest and related charges.~~

~~(3)~~

~~Amounts recorded in Dominion Energy Gas’ Consolidated Statements of Income are classified in other income.~~

Derivatives not designated as hedging instruments

Amount of Gain (Loss) Recognized in Income on Derivatives

Three Months Ended

Six Months Ended

June 30,

June 30,

2020

2019

2020

2019

(millions)

Derivative type and location of gains (losses):

Interest rate⁽¹⁾

$
—

$
—

$
(8
)

$
—

Total

$
—

$
—

$
(8
)

$
—

~~(1)~~

~~Amounts recorded in Dominion Energy Gas’ Consolidated Statements of Income are classified in interest and related charges.~~

~~Note 10. Investments~~

~~Dominion Energy~~

~~Equity and Debt Securities~~

~~Rabbi Trust Securities~~

~~Equity and fixed income securities and cash equivalents in Dominion Energy’s rabbi trusts and classified as trading totaled $121million and $120 million at June 30, 2020 and December 31, 2019, respectively.~~

~~Decommissioning Trust Securities~~

Dominion Energy holds equity and fixed income securities, insurance contracts and cash equivalents in nuclear decommissioning trust funds to fund future decommissioning costs for its nuclear plants. Dominion Energy’s decommissioning trust funds are summarized below:

Amortized
Cost

Total
Unrealized
Gains

Total
Unrealized
Losses

Allowance for Credit Losses

Fair
Value

(millions)

June 30, 2020

Equity securities:⁽¹⁾

U.S.

$
1,701

$
2,221

$
(71
)

$
—

$
3,851

Fixed income securities:⁽²⁾

Corporate debt instruments

577

48

(1
)

—

624

Government securities

1,119

62

(1
)

—

1,180

Common/collective trust funds

146

2

—

—

148

Insurance contracts

223

—

—

—

223

Cash equivalents and other⁽³⁾

(8
)

2

(2
)

—

(8
)
Total

$
3,758

$
2,335

$
(75
)
⁽⁴⁾
$
—

⁽⁵⁾
$
6,018

December 31, 2019

Equity securities:⁽¹⁾

U.S.

$
1,807

$
2,451

$
(20
)

$
—

$
4,238

Fixed income securities:⁽²⁾

Corporate debt instruments

434

29

—

—

463

Government securities

1,108

39

(2
)

—

1,145

Common/collective trust funds

115

4

—

—

119

Insurance contracts

214

—

—

—

214

Cash equivalents and other⁽³⁾

13

—

—

—

13

Total

$
3,691

$
2,523

$
(22
)
⁽⁴⁾
$
—

$
6,192

~~(1)~~

U~~nrealized gains and losses on equity securities are included in other income and the nuclear decommissioning trust regulatory liability.~~

~~(2)~~

Unrealized gains and losses on fixed income securities are included in AOCI and the nuclear decommissioning trust regulatory liability. Effective January 2020, changes in allowance for credit losses are included in other income.

~~(3)~~

~~Includes pending purchases of securities of $35 million and $1 million at June 30, 2020 and December 31, 2019, respectively~~.

~~(4)~~

~~The fair value of securities in an unrealized loss position was $181 million and $298 millionat June 30, 2020 and December 31, 2019, respectively.~~

~~(5)~~

The allowance for credit losses associated with fixed income securities decreased from March 31, 2020 by $21 million. These recoveries are a result of improvements in credit spreads experienced in the market between March 31, 2020 and June 30, 2020.

~~The portion of unrealized gains and losses that relates to equity securities held within Dominion Energy’s nuclear decommissioning trusts is summarized below:~~

Three Months Ended June 30,

Six Months Ended June 30,

2020

2019

2020

2019

(millions)

Net gains (losses) recognized during the period

$
610

$
156

$
(288
)

$
570

Less: Net (gains) losses recognized during the period
on securities sold during the period

(5
)

(25
)

9

(44
)
Unrealized gains (losses) recognized during the period
on securities still held at June 30, 2020 and 2019⁽¹⁾

$
605

$
131

$
(279
)

$
526

~~(1)~~

~~Included in other income and the nuclear decommissioning trust regulatory liability.~~

~~The fair value of Dominion Energy’s fixed income securities with readily determinable fair values held in nuclear decommissioning trust funds at June 30, 2020 by contractual maturity is as follows:~~

Amount

(millions)

Due in one year or less

$
212

Due after one year through five years

486

Due after five years through ten years

485

Due after ten years

769

Total

$
1,952

~~Presented below is selected information regarding Dominion Energy’s equity and fixed income securities with readily determinable fair values held in nuclear decommissioning trust funds.~~

Three Months Ended June 30,

Six Months Ended June 30,

2020

2019

2020

2019

(millions)

Proceeds from sales

$
1,058

$
376

$
1,660

$
882

Realized gains⁽¹⁾

74

56

140

99

Realized losses⁽¹⁾

61

27

130

50

~~(1)~~

~~Includes realized gains and losses recorded to the nuclear decommissioning trust regulatory liability.~~

~~Virginia Power~~

Virginia Power holds equity and fixed income securities and cash equivalents in nuclear decommissioning trust funds to fund future decommissioning costs for its nuclear plants. Virginia Power’s decommissioning trust funds are summarized below:

Amortized
Cost

Total
Unrealized
Gains

Total
Unrealized
Losses

Allowance for Credit Losses

Fair
Value

(millions)

June 30, 2020

Equity securities:⁽¹⁾

U.S.

$
901

$
1,028

$
(46
)

$
—

$
1,883

Fixed income securities:⁽²⁾

Corporate debt instruments

328

26

—

—

354

Government securities

467

23

(1
)

—

489

Common/collective trust funds

57

—

—

—

57

Cash equivalents and other⁽³⁾

(1
)

—

—

—

(1
)
Total

$
1,752

$
1,077

$
(47
)
⁽⁴⁾
$
—

⁽⁵⁾
$
2,782

December 31, 2019

Equity securities:⁽¹⁾

U.S.

$
894

$
1,144

$
(11
)

$
—

$
2,027

Fixed income securities:⁽²⁾

Corporate debt instruments

241

15

—

—

256

Government securities

534

14

(2
)

—

546

Common/collective trust funds

51

—

—

—

51

Cash equivalents and other

1

—

—

—

1

Total

$
1,721

$
1,173

$
(13
)
⁽⁴⁾
$
—

$
2,881

~~(1)~~

~~Unrealized gains and losses on equity securities are included in other income and the nuclear decommissioning trust regulatory liability.~~

~~(2)~~

~~Unrealized gains and losses on fixed income securities are included in AOCI and the nuclear decommissioning trust regulatory liability~~. ~~Effective January 2020, changes in allowance for credit losses are included in other income.~~

~~(3)~~

~~Includes pending purchasesof securities of $1 million at June 30, 2020.~~

~~(4)~~

~~The fair value of securities in an unrealized loss position was $74 million and $185 millionat June 30, 2020 and December 31, 2019, respectively.~~

~~(5)~~

The allowance for credit losses associated with fixed income securities decreased from March 31, 2020 by $12 million. These recoveries are a result of improvements in credit spreads experienced in the market between March 31, 2020 and June 30, 2020.

~~The portion of unrealized gains and losses that relates to equity securities held within Virginia Power’s nuclear decommissioning trusts is summarized below:~~

Three Months Ended June 30,

Six Months Ended June 30,

2020

2019

2020

2019

(millions)

Net gains (losses) recognized during the period

$
269

$
70

$
(154
)

$
256

Less: Net (gains) losses recognized during the period
on securities sold during the period

(3
)

(7
)

3

(8
)
Unrealized gains (losses) recognized during the period
on securities still held at June 30, 2020 and 2019⁽¹⁾

$
266

$
63

$
(151
)

$
248

~~(1)~~

~~Included in other income and the nuclear decommissioning trust regulatory liability.~~

~~The fair value of Virginia Power’s fixed income securities with readily determinable fair values held in nuclear decommissioning trust funds at June 30, 2020 by contractual maturity is as follows:~~

Amount

(millions)

Due in one year or less

$
79

Due after one year through five years

227

Due after five years through ten years

273

Due after ten years

321

Total

$
900

~~Presented below is selected information regarding Virginia Power’s equity and fixed income securities with readily determinable fair values held in nuclear decommissioning trust funds.~~

Three Months Ended June 30,

Six Months Ended June 30,

2020

2019

2020

2019

(millions)

Proceeds from sales

$
236

$
194

$
530

$
447

Realized gains⁽¹⁾

24

15

55

25

Realized losses⁽¹⁾

17

3

48

12

~~(1)~~

~~Includes realized gains and losses recorded to the nuclear decommissioning trust regulatory liability.~~

~~Equity Method Investments~~

~~Dominion Energy~~

~~Dominion Energy’s equity earnings (losses) on its investments totaled $(2.2) billion~~ and $80 million for the six months ended June 30, 2020 and 2019, respectively. Dominion Energy received distributions of $46 million and $57 million for the six months ended June 30, 2020 and 2019, respectively. At June 30, 2020 and December 31, 2019, the net difference between the carrying amount of Dominion Energy’s investments and its share of underlying equity in net assets was $96 million and $110 million, respectively. At June 30, 2020, these differences are comprised of $175 million of equity method goodwill that is not being amortized and a net $79 million basis difference primarily attributable to Dominion Energy’s investments in Fowler Ridge and an unfunded commitment made to Align RNG. At December 31, 2019, these differences are comprised of $159 million of equity method goodwill that is not being amortized and a net $49 million basis difference from Dominion Energy’s investments in Fowler Ridge, which is being amortized over the useful lives of the underlying assets, in Atlantic Coast Pipeline, which is being amortized over the term of its credit facility, and an unfunded commitment made to Align RNG.

~~Atlantic Coast Pipeline~~

In September 2014, Dominion Energy, along with Duke Energy and Southern, announced the formation of Atlantic Coast Pipeline for the purpose of constructing an approximately 600-mile natural gas pipeline running from West Virginia through Virginia to North Carolina. Subsidiaries and affiliates of Dominion Energy, Duke Energy and Southern had planned to be customers of the pipeline under 20-year contracts.

In March 2020, ~~Dominion~~PacifiCorp filed a general rate case with the WPSC which reflected recovery of Energy ~~completed~~Vision 2020 investments, updated depreciation rates, incremental decommissioning costs associated with coal-fueled facilities and rate design modernization proposals. The application also requested a revision to the ~~acquisition from Southern~~ECAM to eliminate the sharing band and requested authorization to discontinue operations and recover costs associated with the early retirement of its 5% membership interest in Atlantic Coast Pipeline and its 100% ownership interest in Pivotal LNG, Inc., for $184 million in aggregate, subject to certain purchase price adjustments. Pivotal LNG, Inc. includes a 50% noncontrolling interest in JAX LNG. Following completionCholla Unit 4. The proposed increase reflects several rate mitigation measures that include use of the ~~acquisition, Dominion Energy owns a 53% noncontrolling membership interest in Atlantic Coast Pipeline with Duke Energy owning~~remaining 2017 Tax Reform benefits to buy down plant balances, including Cholla Unit 4, and spreading the ~~remaining interest.~~

Atlantic Coast Pipeline continues to be reflected as an equity method investment as the power to direct the activities most significant to Atlantic Coast Pipeline is shared with Duke Energy. As a result, Dominion Energy has the ability to exercise significant influence, but not control, over the investee.

~~The Atlantic Coast Pipeline Project had been the subject of challenges in federal courts including, among others, challenges~~recovery of the ~~Atlantic Coast Pipeline Project’s biological opinion and incidental take statement, permits providing right of way crossings~~depreciation of certain ~~federal lands,~~coal-fueled generation units over time periods that extend beyond the ~~Army Corps~~depreciable lives proposed in the depreciation rate study. In September 2020, PacifiCorp filed its rebuttal testimony that modified its requested increase in base rates from $7 million to $9 million, or 1.3%, and reflected an update to the rate mitigation measures for using the 2017 Tax Reform benefits. The WPSC determined that the rebuttal testimony filed constituted a material and substantial change to the original application and vacated the hearing that was scheduled for October 2020. The WPSC re-noticed PacifiCorp's case and rescheduled the hearings. The hearings began February 2021 and were completed in March 2021. The WPSC decision is pending. PacifiCorp has requested a rate effective date of ~~Engineers 404 permit,~~July 1, 2021.

In April 2021, PacifiCorp filed its annual ECAM and RRA application with the ~~air permit for a compressor station at Buckingham, Virginia,~~WPSC requesting to refund $15 million of deferred net power costs and the FERC order approving the CPCN. Each of these challenges alleged non-compliance on the part of federal and state permitting authorities and adverse ecological consequences if the Atlantic Coast Pipeline Project was permittedRECs to ~~proceed. Since December 2018, notable developments in these challenges included a stay in December 2018 issued by the U.S. Court of Appeals~~customers for the ~~Fourth Circuit~~period January 1, 2020 through December 31, 2020, reflecting the difference between base and actual net power costs in the ~~same court’s~~2020 deferral period. This reflects a 2.4% decrease compared to current rates. PacifiCorp has requested an interim rate effective date of July ~~2019 vacatur~~1, 2021.

Idaho

In March 2021, PacifiCorp filed its annual ECAM application with the IPUC requesting recovery of $14 million for deferred costs in 2020. This filing includes recovery of the biological opinion and incidental take statement (which stay and subsequent vacatur halted most project construction activity), the U.S. Court of Appeals for the Fourth Circuit decisions vacating the permits to cross certain federal forests and the air permit for a compressor station at Buckingham, Virginia, the U.S. Court of Appeals for the Fourth Circuit’s remanddifference in actual net power costs to the ~~Army Corps of Engineers of Atlantic Coast Pipeline’s Huntington District 404 verification and the U.S. Court of Appeals~~base level in rates, an adder for ~~the Fourth Circuit’s remand to the National Park Service of Atlantic Coast Pipeline’s Blue Ridge Parkway right-of-way. In June 2019, the Solicitor General~~recovery of the ~~U.S.~~Lake Side 2 resource, changes in PTCs, RECs, and ~~Atlantic Coast Pipeline filed petitions requesting~~a resource tracking mechanism to match costs with the benefits of new wind and wind repowering projects until they are reflected in base rates. This reflects a 1.1% decrease compared to current rates.

California

California Senate Bill 901 requires electric utilities to prepare and submit wildfire mitigation plans that describe the ~~Supreme Court of~~utilities' plans to prevent, combat and respond to wildfires affecting their service territories. PacifiCorp submitted its 2021 California Wildfire Mitigation Plan Update in March 2021.

FERC Show Cause Order

On April 15, 2021, the U.S. hear the case regarding the Appalachian Trail crossing and in June 2020, the Supreme Court of the U.S. ruled in favor of the Atlantic Coast Pipeline, reversing the lower court’s decision and remanding the case back to the U.S. Court of Appeals for the Fourth Circuit.

The project also faced new and serious challenges from uncertainty related to NWP 12, specifically, from the decision of the U.S. District Court for the District of Montana in April 2020 vacating an NWP 12 issued by the Army Corps of Engineers, including among other things gas pipelines, followed by a U.S. Court of Appeals for the Ninth Circuit ruling in May 2020 denying a stay of that decision. In July 2020, the Supreme Court of the U.S.FERC issued an order ~~allowing other new oil~~to show cause and ~~gas pipeline projects~~notice of proposed penalty related to ~~use the NWP 12 process pending appeal~~allegations made by FERC Office of Enforcement staff that PacifiCorp failed to ~~the U.S. Court of Appeals for the Ninth Circuit; however, that did not decrease the uncertainty~~comply with certain North American Electric Reliability Corporation (the "NERC") reliability standards associated with ~~an eventual ruling.~~facility ratings on PacifiCorp's bulk electric system. The ~~Montana district court decision was viewed~~order directs PacifiCorp to show cause as ~~likely~~ to ~~prompt similar challenges in other federal circuit courts related to permits issued under NWP 12, including for the Atlantic Coast Pipeline Project.~~

~~In July 2020,~~why it should not be assessed a civil penalty of $42 million as a result of the ~~continued permitting delays, growing legal uncertainties~~alleged violations. The allegations are related to PacifiCorp's response to a 2010 industry-wide effort directed by the NERC to identify and remediate certain discrepancies resulting from transmission facility design and actual field conditions, including transmission line clearances. PacifiCorp will file a response to the ~~need to incur significant capital expenditures to maintain project timing before such uncertainties could be resolved, Dominion~~allegations with the FERC.

MidAmerican Energy ~~and Duke Energy announced~~

Natural Gas Purchased for Resale

In February 2021, severe cold weather over the ~~cancellation~~central United States caused disruptions in natural gas supply from the southern part of the ~~Atlantic Coast Pipeline Project.~~

~~As a result~~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. To mitigate the impact to customers, the IUB ordered the recovery of these higher costs to be applied to natural gas sales over the period April 2021 through April 2022. While sufficient liquidity is available to MidAmerican Energy, the increased costs and longer recovery period resulted in higher working capital requirements during the three-month period ended March 31, 2021.

NV Energy (Nevada Power and Sierra Pacific)

Price Stability Tariff

In November 2018, the Nevada Utilities made filings with the PUCN to implement the Customer Price Stability Tariff ("CPST"). The Nevada Utilities have designed the CPST to provide certain customers, namely those eligible to file an application pursuant to Chapter 704B of the determination of the probable abandonment of the Atlantic Coast Pipeline Project in June 2020, Atlantic Coast Pipeline has provided to Dominion Energy that it recorded net losses of $4.4 billion and $4.3 billion for the three and six months ended June 30, 2020, respectively, compared to net income of $61 million and $114 million for the three and six months ended June 30, 2019, respectively, and that it did not record revenue for any period. As a result, Dominion Energy has recorded within earnings

(loss) from equity method investees a loss of $2.3 billion for both the three and six months ended June 30, 2020 compared to income of $29 million and $53 million for the three and six months ended June 30, 2019, respectively. At June 30, 2020, Dominion Energy has recorded a liability of $1.0 billion within other current liabilities in its Consolidated Balance Sheet, as a result of its share of equity losses exceeding its investment which reflects Dominion Energy’s obligations on behalf of Atlantic Coast Pipeline related to its credit facility and AROs.

~~In October 2017, Dominion Energy entered into a guarantee agreement to support a portion of Atlantic Coast Pipeline’s obligation under a $3.4 billion revolving credit facility~~Nevada Revised Statutes, with a ~~stated maturity date of~~ ~~October 2021~~. As of June 30, 2020, Atlantic Coast Pipeline had borrowed $1.8 billion against the revolving credit facility. In July 2020, the capacity of the revolving credit facility was reduced from $3.4 billion to $1.9 billion. Dominion Energy’s Consolidated Balance Sheets include a liability of $14 million associated with this guarantee agreement at December 31, 2019. The $1.0 billion liability at June 30, 2020 discussed above includes a $48 million adjustment related to this guarantee agreementmarket-based pricing option that ~~is reflected within equity as a cumulative effect of a change in accounting principle upon adoption of the new credit loss standard in January 2020.~~

Dominion Energy recorded contributions of $13 million and $33 million during the three months ended June 30, 2020 and 2019, respectively, and $29 million and $128 million during the six months ended June 30, 2020 and 2019, respectively, to Atlantic Coast Pipeline. At June 30, 2020 and December 31, 2019, Dominion Energy had $5 million and $7 million, respectively, of contributions payable to Atlantic Coast Pipeline included within other current liabilities in the Consolidated Balance Sheets.

Dominion Energy expects to incur additional losses from Atlantic Coast Pipeline as it completes wind-down activities. While Dominion Energy is unable to precisely estimate the amounts to be incurred by Atlantic Coast Pipeline, the portion of such amounts attributable to Dominion Energy is not expected to be material to Dominion Energy’s results of operations, financial position or statement of cash flows. In connection with the sale of Dominion Energy’s gas transmission and storage operations to BHE discussed in Note 3, Dominion Energy expects to reflect the results of its equity method investment in Atlantic Coast Pipeline as discontinued operations effective in the third quarter of 2020.

~~Blue Racer~~

In the first quarter of 2019, Dominion Energy received $151 million of additional consideration, including applicable interest, in connection with the sale of Dominion Energy’s 50% limited partnership interest in Blue Racer in December 2018, as discussed in Note 9 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019.

~~Fowler Ridge~~

In July 2020, Dominion Energy entered into an agreement to sell its 50% noncontrolling partnership interest in Fowler Ridge to BP and to terminate a long-term power, capacity and renewable energy credit contract for a net payment by Dominion Energy of $150 million. The transaction is expected to close in the third quarter of 2020, subject to approval by FERC. Dominion Energy expects to record a loss of approximately $220 million ($170 million after-tax), consisting of a loss on the contract termination partially offset by a gain on the sale of the partnership interest.

~~Dominion Energy Gas~~

~~Dominion~~ Energy Gas’ equity earnings totaled $23 million and $22 million for the six months ended June 30, 2020 and 2019, respectively. Dominion Energy Gas received distributions of $25 million and $30 million for the six months ended June 30, 2020 and 2019, respectively. At June 30, 2020 and December 31, 2019, the carrying amount of Dominion Energy Gas’ investment of $310 million and $312 million, respectively, exceeded its share of underlying equity in net assets by $146 million. The difference reflects equity method goodwill and is not being amortized.

~~Atlantic Coast Pipeline~~

DETI provides services to Atlantic Coast Pipeline which totaled $17 million and $26 million for the three months ended June 30, 2020 and 2019, respectively, and $37 million and $57 million for the six months ended June 30, 2020 and 2019, respectively, included in operating revenue in Dominion Energy and Dominion Energy Gas’ Consolidated Statements of Income. Amounts receivable related to these services were $7 million at both June 30, 2020 and December 31, 2019, respectively, composed entirely of accrued unbilled revenue, included in other receivables in Dominion Energy and Dominion Energy Gas’ Consolidated Balance Sheets.

~~Note 11. Property, Plant and Equipment~~

~~Acquisitions of Solar Projects~~

Other than the items discussed below, there have been no updates to acquisitions of solar projects by Dominion Energy or Virginia Power from those discussed in Note 10 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019.

~~The following table presents acquisitions by Virginia Power of solar projects. Virginia Power expects to claim federal investment tax credits on the projects.~~

Date Agreement Entered

Date Agreement Closed

Project Location

Project Name

Project Cost (millions)⁽¹⁾

Date of Commercial Operations

MW Capacity

May 2020

May 2020

Virginia

Pumpkinseed

$
130

Expected 2022

60

~~(1)~~

~~Includes acquisition cost.~~

~~The following table presents acquisitions by Dominion Energy of solar projects. Dominion Energy has claimed or expects to claim federal investment tax credits on the projects.~~

Date Agreement Entered

Date Agreement Closed

Project Location

Project Name

Project Cost (millions)⁽¹⁾

Date of Commercial Operations

MW Capacity

August 2019

August 2019

Virginia

Myrtle

$
32

June 2020

15

May 2020

May 2020

South Carolina

Blackville

15

Expected 2020

7

May 2020

May 2020

South Carolina

Denmark

15

Expected 2020

6

May 2020

Expected August 2020

South Carolina

Yemassee

20

Expected 2020

10

May 2020

Expected August 2020

South Carolina

Trask

25

Expected 2020

12

June 2020

June 2020

Ohio

Hardin I

250

Expected 2020

150

July 2020

July 2020

Virginia

Madison

125

Expected 2021

62

~~(1)~~

~~Includes acquisition cost.~~

In addition to the facilities discussed above, Dominion Energy has also entered into various agreements to install solar facilities, primarily at schools in Virginia, with in-service dates in 2020 or 2021. Through July 2020, Dominion Energy anticipates a total projected cost of approximately $35 million under these agreements with an associated aggregate generation capacity of 18 MW.

~~Acquisition of Gathering and Processing Assets~~

In March 2020, Wexpro closed on an agreement with a natural gas gathering systems operator to purchase existing natural gas gathering systems including pipelines, compressors and dehydration equipment for total consideration of $38 million. These facilities gather natural gas in Colorado, Utah and Wyoming.

~~Note 12. Regulatory Assets and Liabilities~~

~~Regulatory assets and liabilities include the following:~~

June 30, 2020

December 31, 2019

(millions)

Dominion Energy

Regulatory assets:

Deferred cost of fuel used in electric generation⁽¹⁾

$
—

$
48

Deferred project costs and DSM programs for gas utilities⁽²⁾

49

21

Unrecovered gas costs⁽³⁾

42

102

Deferred rate adjustment clause costs for Virginia electric utility⁽⁴⁾⁽⁵⁾

58

109

Deferred nuclear refueling outage costs⁽⁶⁾

60

68

NND Project costs⁽⁷⁾

138

138

PJM transmission rates⁽⁸⁾

21

121

Other

248

272

Regulatory assets-current

616

879

Pension and other postretirement benefit costs⁽⁹⁾

1,392

1,431

Deferred rate adjustment clause costs for Virginia electric utility^{(4)(5)(10)(11)}

409

235

PJM transmission rates⁽⁸⁾

154

85

Deferred project costs for gas utilities⁽²⁾

557

521

Interest rate hedges⁽¹²⁾

1,302

741

AROs and related funding⁽¹³⁾

312

311

Cost of reacquired debt⁽¹⁴⁾

252

262

NND Project costs⁽⁷⁾

2,434

2,503

Ash pond and landfill closure costs⁽¹⁵⁾

2,139

1,016

Other

487

582

Regulatory assets-noncurrent

9,438

7,687

Total regulatory assets

$
10,054

$
8,566

Regulatory liabilities:

Deferred cost of fuel used in electric generation⁽¹⁾

$
111

$
—

Provision for future cost of removal and AROs⁽¹⁶⁾

142

142

Reserve for refunds and rate credits to electric utility customers⁽¹⁷⁾

134

143

Cost-of-service impact of 2017 Tax Reform Act⁽¹⁸⁾

35

4

Income taxes refundable through future rates⁽¹⁹⁾

140

77

Monetization of guarantee settlement⁽²⁰⁾

67

67

Other

120

64

Regulatory liabilities-current

749

497

Income taxes refundable through future rates⁽¹⁹⁾

4,988

5,088

Provision for future cost of removal and AROs⁽¹⁶⁾

2,253

2,302

Nuclear decommissioning trust⁽²¹⁾

1,372

1,471

Monetization of guarantee settlement⁽²⁰⁾

936

970

Reserve for refunds and rate credits to electric utility customers⁽¹⁷⁾

588

656

Overrecovered other postretirement benefit costs⁽²²⁾

212

189

Other

331

325

Regulatory liabilities-noncurrent

10,680

11,001

Total regulatory liabilities

$
11,429

$
11,498

~~(1)~~

~~Reflects deferred fuel expenses for the Virginia, North Carolina and South Carolina jurisdictions of Dominion Energy’s electric generation operations.~~

~~(2)~~

~~Primarily~~reflects amounts expected to be collected from or owed to gas customers in Dominion Energy’s service territories associated with current and prospective rider projects, including CEP, PIR and pipeline integrity management. See Note 13 for more information.

~~(3)~~

~~Reflects unrecovered or overrecovered gas costs at regulated gas operations, which are recovered or refunded through filings with the applicable regulatory authority.~~

~~(4)~~

Reflects deferrals under Virginia Power’s electric transmission FERC formula rate and the deferral of costs associated with certain current and prospective rider projects, net of income taxes refundable from the 2017 Tax Reform Act for Virginia Power. See Note 13 for more information.

~~(5)~~

As a result of actions from the Virginia Commission in the first quarter of 2019 regarding the ratemaking treatment of excess deferred taxes from the adoption of the 2017 Tax Reform Act for all existing rate adjustment clauses, Virginia Power recorded a $29 million ($22 million after-tax) charge in operating revenue in the Consolidated Statements of Income for amounts which are probable of being returned to customers.

~~(6)~~

Legislation enacted in Virginia in April 2014 requires Virginia Power to defer operation and maintenance costs incurred in connection with the refueling of any nuclear-powered generating plant. These deferred costs will be amortized over the refueling cycle, not to exceed 18 months.

~~(7)~~

Reflects expenditures by DESC associated with the NND Project, which pursuant to the SCANA Merger Approval Order, will be recovered from DESC electric service customers over a 20-year period ending in 2039. See Note 3 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019 for more information.

~~(8)~~

~~Reflects amounts to be recovered through retail rates in Virginia for payments Virginia Power will make to PJM over a~~ ~~ten-year~~ ~~period ending 2028 under the terms of a FERC settlement agreement in May 2018 resolving a PJM cost allocation matter.~~

~~(9)~~

Represents unrecognized pension and other postretirement employee benefit costs expected to be recovered or refunded through future rates generally over the expected remaining service period of plan participants by certain of Dominion Energy's rate-regulated subsidiaries.

~~(10)~~

During the first quarter of 2019, Virginia Power recorded a charge of $17 million ($13 million after-tax) in impairment of assets and other charges to write-off the balance of a regulatory asset for which it is no longer seeking recovery.

~~(11)~~

During the second quarter of 2020, Virginia Power recorded a charge of $16 million ($15 million after-tax) in impairment of assets and other charges to write off the balance of a regulatory asset for which it is no longer seeking recovery.

~~(12)~~

Reflects interest rate hedges recoverable from or refundable to customers. Certain of these instruments are settled and any related payments are being amortized into interest expense over the life of the related debt, which has a weighted-average useful life of approximately 27 years as of June 30, 2020.

~~(13)~~

Represents deferred depreciation and accretion expense related to legal obligations associated with the future retirement of generation, transmission and distribution properties. The AROs primarily relate to DESC’s electric generating facilities, including Summer, and are expected to be recovered over the related property lives and periods of decommissioning which may range up to approximately 105 years.

~~(14)~~Costs of the reacquisition of debt are deferred and amortized as interest expense over the would-be remaining life of the reacquired debt. The reacquired debt costs had a weighted-average life of approximately 26 years as of June 30, 2020.

~~(15)~~

Primarily reflects legislation enacted in Virginia in March 2019 which requires any CCR unit located at certain Virginia Power stations to be closed by removing the CCRs to an approved landfill or through recycling for beneficial reuse. Subject to approval by the Virginia Commission, amounts are expected to be collected over a period between 15 and 18 years commencing no earlier than 2021.Virginia Power is entitled to collect carrying costs once expenditures have been made. See Note 23 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019 for additional information.~~As a result of the March 2020 planned early retirement of certain facilities, amounts recoverable through riders were reclassified from property, plant and equipment.~~

~~(16)~~

Rates charged to customers by Dominion Energy’s regulated businesses include a provision for the cost of future activities to remove assets that are expected to be incurred at the time of retirement.

~~(17)~~

Reflects amounts previously collected from retail electric customers of DESC for the NND Project to be credited over an estimated 11-year period effective February 2019, in connection with the SCANA Merger Approval Order. See Notes 3 and 13 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019 for more information.

~~(18)~~

Balance refundable to customers related to the decrease in revenue requirements for recovery of income taxes at the Companies’ regulated electric generation and electric and natural gas distribution operations. See Notes 3 and 13 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019 for more information.

~~(19)~~

Amounts recorded to pass the effect of reduced income taxes from the 2017 Tax Reform Act to customers in future periods, which will primarily reverse at the weighted average tax rate that was used to build the reserves over the remaining book life of the property, net of amounts to be recovered through future rates to pay income taxes that become payable when rate revenue is provided to recover AFUDC equity.

~~(20)~~

Reflects amounts to be refunded to DESC electric service customers over a 20-year period ending in 2039 associated with the monetization of a bankruptcy settlement agreement. See Note 3 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019 for more information.

~~(21)~~

Primarily reflects a regulatory liability representing amounts collected from Virginia jurisdictional customers and placed in external trusts (including income, losses and changes in fair value thereon, as applicable) for the future decommissioning of Dominion Energy’s utility nuclear generation stations, in excess of the related AROs.

~~(22)~~

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

June 30, 2020

December 31, 2019

(millions)

Virginia Power

Regulatory assets:

Deferred cost of fuel used in electric generation⁽¹⁾

$
—

$
48

Deferred rate adjustment clause costs⁽²⁾⁽³⁾

58

109

Deferred nuclear refueling outage costs⁽⁴⁾

60

68

PJM transmission rates⁽⁵⁾

21

121

Other

58

87

Regulatory assets-current

197

433

Deferred rate adjustment clause costs^(2)(3)(6)(7)

409

235

PJM transmission rates⁽⁵⁾

154

85

Interest rate hedges⁽⁸⁾

956

404

Ash pond and landfill closure costs⁽⁹⁾

2,139

1,016

Other

122

123

Regulatory assets-noncurrent

3,780

1,863

Total regulatory assets

$
3,977

$
2,296

Regulatory liabilities:

Deferred cost of fuel used in electric generation⁽¹⁾

$
111

$
—

Provision for future cost of removal⁽¹⁰⁾

103

103

Income taxes refundable through future rates⁽¹¹⁾

54

54

Other

28

10

Regulatory liabilities-current

296

167

Income taxes refundable through future rates⁽¹¹⁾

2,425

2,438

Nuclear decommissioning trust⁽¹²⁾

1,372

1,471

Provision for future cost of removal⁽¹⁰⁾

993

1,054

Deferred cost of fuel used in electric generation⁽¹⁾

3

30

Other

161

81

Regulatory liabilities-noncurrent

4,954

5,074

Total regulatory liabilities

$
5,250

$
5,241

~~(1)~~

~~Reflects deferred fuel expenses for the Virginia and North Carolina jurisdictions of Virginia Power’s generation operations.~~

~~(2)~~

~~(3)~~

~~(4)~~

~~(5)~~

~~(6)~~

~~(7)~~

~~(8)~~

~~(9)~~

Primarily reflects legislation enacted in Virginia in March 2019 which requires any CCR unit located at certain Virginia Power stations to be closed by removing the CCR to an approved landfill or through recycling for beneficial reuse. Subject to approval by the Virginia Commission, amounts are expected to be collected over a period between 15 and 18 years commencing no earlier than 2021. Virginia Power is entitled to collect carrying costs once expenditures have been made. See Note 23 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019 for additional information. As a result of the March 2020 planned early retirement of certain facilities, amounts recoverable through riders were reclassified from property, plant and equipment.

~~(10)~~

~~Rates charged to customers by Virginia Power's regulated businesses include a provision for the cost of future activities to remove assets that are expected to be incurred at the time of retirement.~~

~~(11)~~

Amounts recorded to pass the effect of reduced income taxes from the 2017 Tax Reform Act to customers in future periods, which will reverse at the weighted average tax rate that was used to build the reserves over the remaining book life of the property, net of amounts to be recovered through future rates to pay income taxes that become payable when rate revenue is provided to recover AFUDC equity.

(12) Primarily reflects a regulatory liability representing amounts collected from Virginia jurisdictional customers and placed in external trusts (including income, losses and changes in fair value thereon) for the future decommissioning of Virginia Power’s utility nuclear generation stations, in excess of the related AROs.

June 30, 2020

December 31, 2019

(millions)

Dominion Energy Gas

Regulatory assets:

Unrecovered gas costs⁽¹⁾

$
2

$
2

Other

7

6

Regulatory assets-current⁽²⁾

9

8

Interest rate hedges⁽³⁾

32

32

Other

5

8

Regulatory assets-noncurrent⁽⁴⁾

37

40

Total regulatory assets

$
46

$
48

Regulatory liabilities:

Provision for future cost of removal and AROs⁽⁵⁾

$
18

$
18

Overrecovered gas costs⁽¹⁾

6

8

Other

13

15

Regulatory liabilities-current⁽⁶⁾

37

41

Income taxes refundable through future rates⁽⁷⁾

566

560

Provision for future cost of removal and AROs⁽⁵⁾

93

95

Overrecovered other postretirement benefit costs⁽⁸⁾

151

133

Other

10

12

Regulatory liabilities-noncurrent⁽⁹⁾

820

800

Total regulatory liabilities

$
857

$
841

~~(1)~~

~~Reflects unrecovered or overrecovered gas costs at regulated gas operations, which are recovered or refunded through filings with FERC.~~

~~(2)~~

~~Current regulatory assets are presented in other current assets in Dominion Energy Gas’ Consolidated Balance Sheets.~~

~~(3)~~

~~(4)~~

~~Noncurrent regulatory assets are presented in other deferred charges and other assets in Dominion Energy Gas’ Consolidated Balance Sheets.~~

~~(5)~~

Rates charged to customers by Dominion Energy Gas' regulated businesses include a provision for the cost of future activities to remove assets that are expected to be incurred at the time of retirement.

~~(6)~~

~~Current regulatory liabilities are presented in other current liabilities in Dominion Energy Gas’ Consolidated Balance Sheets.~~

~~(7)~~

~~(8)~~

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

~~(9)~~

~~Noncurrent regulatory liabilities are presented in other deferred credits and other liabilities in Dominion Energy Gas’ Consolidated Balance Sheets.~~

At June 30, 2020, Dominion Energy, Virginia Power and Dominion Energy Gas’ regulatory assets include $4.8 billion, $3.4 billion and $44 million, respectively, on which they do not expect to earn a return during the applicable recovery period. With the exception of certain items discussed above, the majority of these expenditures are expected to be recovered within the next two years.

~~Note 13. Regulatory Matters~~

~~Regulatory Matters Involving Potential Loss Contingencies~~

As a result of issues generated in the ordinary course of business, the Companies are involved in various regulatory matters. Certain regulatory matters may ultimately result in a loss; however, as such matters are in an initial procedural phase, involve uncertainty as to the outcome of pending reviews or orders, and/or involve significant factual issues that need to be resolved, it is not possible for the Companies to estimate a range of possible loss. For regulatory matters that the Companies cannot estimate, a statement to this effect is made in the description of the matter. Other matters may have progressed sufficiently through the regulatory process such that the Companies are able to estimate a range of possible loss. For regulatory matters that the Companies are able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. Any estimated range is based on ~~currently~~renewable resources. The CPST provides for an energy rate that would replace the Base Tariff Energy Rate and DEAA. The goal is to have an energy rate that yields an all-in effective rate that is competitive with market options available ~~information, involves elements of judgment~~to such customers. In February 2019, the PUCN granted several intervenors the ability to participate in the proceeding. In June 2019, the Nevada Utilities withdrew their filings. In May 2020, the Nevada Utilities refiled the CPST incorporating the considerations raised by the PUCN and ~~significant uncertainties~~other intervenors and may not represent the Companies’ maximum possible loss exposure. The circumstances of such regulatory matters will change from time to time and actual results may vary significantly from the current estimate. For current matters not specifically reported below,

~~management does not anticipate that the outcome from such matters would have~~ a ~~material effect on the Companies’ financial position, liquidity or results of operations.~~

~~FERC – Gas~~

~~DETI~~

In July 2017, FERC audit staff communicated to DETI that it had substantially completed an audit of DETI’s compliance with the accounting and reporting requirements of FERC’s Uniform System of Accounts and provided a description of matters and preliminary recommendations.hearing was held in September 2020. In November 2017, the FERC audit staff issued its audit report which could have the potential to result in adjustments which could be material to Dominion Energy and Dominion Energy Gas’ results of operations. In December 2017, DETI provided its response to the audit report. DETI reached resolution of certain matters with FERC in the fourth quarter of 2018. Pending final resolution of the audit process and a determination by FERC, management is unable to estimate the potential impact of the remaining finding and no amounts have been recognized.

~~2017 Tax Reform Act~~

Other than the items discussed below, which are pending or have been resolved during the period, there have been no changes to the 2017 Tax Reform Act matters discussed in Note 13 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019.

In March 2019, Questar Gas filed with the Utah and Wyoming Commissions as to the impact of excess deferred income taxes resulting from the 2017 Tax Reform Act. Questar Gas proposed to return the 2018 amortization of excess deferred income taxes to customers and to incorporate the remaining excess deferred income tax impact in its next general rate cases in each jurisdiction. In March 2020, the ~~Utah Commission~~PUCN issued an order approving ~~Questar Gas’ proposal~~the tariff with modified pricing and directing the Nevada Utilities to ~~refund~~develop a methodology by which all eligible participants may have the January 2019 through February 2020 amortization of excess deferred income taxes over 12 months beginning in June 2020. In April 2020, at the request of the Wyoming Commission, this matter was considered in conjunction with the base rate case that was filed in November 2019. In June 2020, the Wyoming Commission approved a proposal to share the benefits of deferred income taxes for the period January 2018 through August 2020 with customers over a one-year period beginning in September 2020. In addition, new base rates that go into effect in September 2020 will include the prospective impacts of sharing excess deferred income taxes with customers.

In October 2018, the Ohio Commission issued an order requiring rate-regulated utilities to file an application reflecting the impact of the 2017 Tax Reform Act on current rates by January 1, 2019. In December 2018, East Ohio filed its application proposing an approach to establishing rates and charges by and through which to return tax reform benefits to its customers. In December 2019, the Ohio Commission issued an order approving customer credits of approximately $600 million that will be shared with customers primarily over the remaining book life of the property to which the excess deferred income taxes relate. In addition, East Ohio will reduce rates approximately $19 million per year to account for the 2017 Tax Reform Act’s impact on its equity return component of rates charged to customers. A tax savings credit, which passes through the reduction in the federal income tax rate under the 2017 Tax Reform Act to customers in accordance with the settlement agreement approved by the Ohio Commission, became effective with the first billing cycle in April 2020.

~~Other Regulatory Matters~~

Other than the following matters, there have been no significant developments regarding the pending regulatory matters disclosed in Note 13 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019.

~~Virginia Regulation~~

~~Virginia 2020 Legislation~~

In April 2020, the Governor of Virginia signed into law the VCEA, which along with related legislation forms a comprehensive framework affecting Virginia Power’s operations. The VCEA replaces Virginia’s voluntary renewable energy portfolio standard for Virginia Power with a mandatory program setting annual renewable energy portfolio standard requirements based on the percentage of total electric energy sold by Virginia Power, excluding existing nuclear generation and certain new carbon-free resources, reaching 100% by the end of 2045. The VCEA includes related requirements concerning deployment of wind, solar and energy storage resources, as well as provides for certain measures to increase net-metering, including an allocation for low-income customers, incentivizes energy efficiency programs and directs Virginiaopportunity to participate in the CPST program up to a ~~carbon trading program. While the legislation affects several portions of Virginia Power’s operations, key provisions of the GTSA remain in effect, including the triennial review structure~~

and timing, the use of the customer credit reinvestment offset and the $50 million cap on revenue reductions in the first triennial review proceeding. Key provisions of the VCEA and related legislation passed include the following:

~~FossilFuel Electric Generation~~: The legislation mandates Chesterfield Power Station Units 5 & 6 and Yorktown Power Station Unit 3 to be retired by the end of 2024, Altavista, Southampton and Hopewell to be retired by the end of 2028 and Virginia Power’s remaining fossil fuel units to be retired by the end of 2045, unless the retirement of such generating units will compromise grid reliability or security. The legislation also imposes a temporary moratorium on CPCNs for fossil fuel generation, unless the resources are needed for grid reliability. In addition, the Virginia Commission shall determine the amortization period for recovery of any appropriate costs due to the early retirement of any electric generation facilities, which could result in the reversal of previous retirement costs deemed recovered during the review period ending 2020. As discussed in Note 2, Virginia Power had recorded charges for early retirement of certain coal- and -oil fired generating units in the first quarters of 2020 and 2019. Virginia Power also revised the depreciable lives of Altavista, Southampton and Hopewell for the mandated retirement to the end of 2028, which will not have a material impact to Virginia Power’s results of operations or cash flows given the existing regulatory framework.

~~Renewable Generation:~~ The legislation provides a detailed renewable energy portfolio standard to achieve 100% zero-carbon generation by the end of 2045, excluding existing nuclear generation and certain new carbon-free resources. Components include requirements to petition the Virginia Commission for approval to construct or acquire new generating capacity to reach 16.1 GW of installed solar and onshore wind by the end of 2035, which includes specific requirements for utility-scale solar of 3.0 GW by the end of 2024, up to 15.0 GW by the end of 2035 and 1.1 GW of small-scale solar by the end of 2035. The legislation deems 2,700 MW of energy storage, including up to 800 MW for any one project which may include a pumped storage facility, by the end of 2035 to be in the public interest. The legislation also deems the construction or purchase of an offshore wind facility constructed off the Virginia coast with a capacity of up to 5,200 MW before 2035 to be in the public interest and provides certain presumptions facilitating cost recovery. The costs of such a facility constructed by the utility with a capacity between 2,500 and 3,000 MW will be presumed reasonably and prudently incurred if the Virginia Commission finds that the project meets competitive procurement requirements, the projected cost of the facility does not exceed a specified industry benchmark and the utility commences construction by the end of 2023 or has a plan for the facility to be in service by the end of 2027. The Virginia Commission must approve all projects to meet those requirements.

~~Energy Efficiency:~~The legislation includes an energy efficiency target of 5% energy savings, as measured from a 2019 baseline, through verifiable energy efficiency programs by the end of 2025 with future targets to be set by the Virginia Commission. Virginia Power has the opportunity to offset the lost revenues with margins on program spend if certain targets are achieved and can also seek recovery of the lost revenues associated with energy efficiency programs if such reductions are found to have caused Virginia Power to earn more than 50 basis points below a fair rate of return on its rates for generation and distribution services.

~~Carbon trading program~~: The legislation directs Virginia Power to participate in a market-based carbon trading program consistent with RGGI through 2050. All costs of the carbon trading program are recoverable through an environmental rider.

~~Low-income customers~~: The legislation includes the establishment of a percentage of income payment program to be administered by the Virginia Department of Housing and Community Development and the Virginia Department of Social Services. To fund the program, Virginia Power will remit amounts collected from customers under a universal service fee established and set by the Virginia Commission. As such, this program will not affect Virginia Power’s results of operations, financial position or cash flows.

~~Virginia Power expects to incur significant costs, including capital expenditures, to comply~~limit with the ~~legislative requirements discussed above. The legislation allows~~same proportion of governmental entities' and non-governmental entities' MWh reserved for ~~cost recovery under the existing or modified regulatory framework through rate adjustment clauses, rates for generation and distribution services or Virginia Power’s fuel factor,~~potentially interested customers as approved by the Virginia Commission. Costs allocated to the North Carolina jurisdiction will be recovered, subject to approval by the North Carolina Commission, in accordance with the existing regulatory framework.

filed. In May 2020 and July 2020, Virginia Power entered into and closed on separate agreements to acquire Grassfield Solar, Norge Solar and Sycamore Solar. The projects are expected to cost approximately $170 million in aggregate once constructed, including the initial acquisition cost. The facilities are expected to generate 82 MW combined and be placed into service by the end of 2022. Virginia Power expects to file with the Virginia Commission ~~for CPCNs to construct and operate these projects as well as a rider to recover the costs associated with the recovery of certain renewable generation facilities in Virginia by the end of 2020~~.

~~Grid Transformation and Security Act of 2018~~

In July 2018, Virginia Power filed a petition with the Virginia Commission for approval of the first three years of its ten-year plan for electric distribution grid transformation projects as authorized by the GTSA. During the first three years of the plan, Virginia Power proposed to focus on the following seven foundational components of the overall grid transformation plan: (i) smart meters; (ii)

customer information platform; (iii) reliability and resilience; (iv) telecommunications infrastructure; (v) cyber and physical security; (vi) predictive analytics; and (vii) emerging technology. The total estimated capital investment during 2019-2021 was $816 million and the proposed operations and maintenance expenses were $102 million. In January 2019, the Virginia Commission issued its final order approving capital spending for the first three years of the plan totaling $68 million on cyber and physical security and related telecommunications infrastructure (Phase IA). The Virginia Commission declined to approve the remainder of the proposed components for the first three years of the plan, the proposed spending for which was not found reasonable and prudent based on the record in the proceeding.

In September 2019, Virginia Power filed a revised plan which includes six components: (i) smart meters; (ii) customer information platform; (iii) grid improvement projects; (iv) telecommunications infrastructure; (v) cyber security; and (vi) a smart charging electric vehicle infrastructure pilot program (Phase IB). For Phase IB, the total proposed capital investment during 2019 – 2021 was $503 million and the proposed operations and maintenance investment was $78 million. In MarchDecember 2020, the Virginia Commission issued an order approving $212 million of costs related to a new customer information platform, targeted grid hardening and corridor improvements, an electric vehicle Smart Charging Infrastructure Pilot Program, cyber security, stakeholder engagement and customer education and denied the costs associated with AMI, self-healing grid and certain other grid hardening projects alleging that Virginia Power did not prove the reasonableness and prudency of these costs. In April 2020, Virginia PowerNevada Utilities filed a petition for reconsideration of the ~~Virginia Commission’s~~pricing ordered by the PUCN. In January 2021, the PUCN issued an order reaffirming its order from November 2020 and denying the petition for a rehearing. In the first quarter of 2021, the Nevada Utilities filed an update to the CPST program per the November 2020 order and ~~requested clarification of certain matters, including the Smart Charging Infrastructure Pilot Program. Additionally, Virginia Power requested clarification of certain matters relating to~~ an AMI time-of-use rate and the smart charging electric vehicle infrastructure pilot program. Subsequently, in April 2020, the Virginia Commission denied in full Virginia Power’s petition for reconsideration; however, it stated that its March 2020 order contained all necessary approvals for the smart charging electric vehicle infrastructure pilot program. Virginia Power intends to file a revised plan that will address the elements needed for a comprehensive plan, as outlined by the Virginia Commission in its order.

~~Solar Facility Projects~~

~~In July 2019, Virginia Power filed an application~~updated CPST tariff with the ~~Virginia Commission for a CPCN to construct Sadler Solar, which is estimated to cost approximately $146 million, excluding financing costs. Sadler Solar~~PUCN. An order is expected ~~to commence commercial operations, subject to regulatory approvals associated with the project,~~ in the ~~fourth~~second quarter of ~~2020. Virginia Power also applied for approval~~2021.

Natural Disaster Protection Plan

The Nevada Utilities submitted their initial natural disaster protection plan to the PUCN and filed their first application seeking recovery of Rider US-4 associated with this project with a proposed $9 million total revenue requirement for the rate year beginning June 1, 2020. In January 2020, the Virginia Commission issued a final order granting the CPCN to construct Sadler Solar, subject to a 20- year performance guarantee of the facility at a 22% solar capacity factor when normalized for force majeure events. In March 2020, the Virginia Commission approved a $7 million total annual revenue requirement.

~~Virginia Fuel Expenses~~

In2019 expenditures in February 2020, Virginia Power filed its annual fuel factor with the Virginia Commission to recover an estimated $1.2 billion in Virginia jurisdictional projected fuel expenses for the rate year beginning July 1, 2020 and a projected over-recovery of approximately $81 million for the prior year balance as of June 30, 2020. Virginia Power requested that the new fuel factor rate be implemented on an interim basis two months early, beginning on May 1, 2020. In March 2020, the Virginia Commission approved the interim rates. Virginia Power’s proposed fuel rate represents a fuel revenue decrease of approximately $393 million when applied to projected kilowatt-hour sales for the rate year beginning May 1, 2020. In June 2020, a hearing was held and an order was issued in August 2020 that granted the ~~Virginia Commission~~joint application, made minor adjustments to the budget and approved the 2019 costs for recovery starting in October 2020. In October 2020, intervening parties filed petitions for reconsideration. Intervenors have filed a ~~revised fuel~~petition for judicial review with the District Court in November 2020. In December 2020, the PUCN issued a second modified final order approving the natural disaster protection plan, as modified, and reopened its investigation and rulemaking on Senate Bill 329 to address rate ~~based on an updated projected over-recovery of $103 million~~design issues raised by intervenors. The comment period for the ~~prior year balance as~~reopened investigation and rulemaking ended in early February 2021 and an order is expected in the second quarter of ~~June 30, 2020.~~

~~Rate Adjustment Clauses~~

~~Below is a discussion of significant riders associated with various Virginia Power projects:~~

•

The Virginia Commission previously approved Rider T1 concerning transmission rates. In May 2020, Virginia Power proposed a $1.0 billion total revenue requirement consisting of $474 million for the transmission component of Virginia Power’s base rates and $529 million for Rider T1 for the rate year beginning September 1, 2020. This total revenue requirement represents a $73 million increase versus the revenues to be produced during the rate year under current rates. In July 2020, the Virginia Commission approved the filing.

•

The Virginia Commission previously approved Riders C1A, C2A and C3A in connection with cost recovery for DSM programs. In December 2019, Virginia Power filed a petition to approve an additional 10 new energy efficiency programs and 1 new demand response DSM program for five years, subject to future extension, with a $186 million cost cap, and proposed a total $60 million revenue requirement for the rate year beginning September 1, 2020. This total revenue requirement represents an $11 million increase over the previous year. In July 2020, the Virginia Commission approved the filing.

•

The Virginia Commission previously approved Rider U in conjunction with cost recovery to move certain electric distribution facilities underground as authorized by Virginia legislation. In June 2020, Virginia Power proposed an $80 total revenue requirement consisting of $44 million for previously approved phases and $36 million for phase five costs for Rider U for the rate year beginning April 1, 2021. ~~This total revenue requirement represents a $28 million increase over the previous year. This matter is pending~~.

~~Additional significant riders associated with various Virginia Power projects are as follows:~~

Rider Name

Application Date

Approval Date

Rate Year
Beginning

Total Revenue
Requirement
(millions)

Increase (Decrease)
Over Previous Year
(millions)

Rider US-3

July 2019

March 2020

June 2020

$
28

$
18

Rider BW

October 2019

June 2020

September 2020

99

(20
)
Rider US-2

October 2019

July 2020

September 2020

10

(5
)
Rider B

June 2020

Pending

April 2021

24

(8
)
Rider GV

June 2020

Pending

April 2021

154

22

Rider R

June 2020

Pending

April 2021

59

15

Rider S

June 2020

Pending

April 2021

194

(1
)
Rider W

June 2020

Pending

April 2021

120

14

Rider US-3

July 2020

Pending

June 2021

39

10

Rider US-4

July 2020

Pending

June 2021

12

4

~~Electric Transmission Projects~~

In ~~December 2019, Virginia Power~~March 2021, the Nevada Utilities filed an application ~~with~~seeking recovery of the ~~Virginia Commission~~2020 expenditures, approval for ~~a CPCN~~an update to ~~construct a new Evergreen Mills switching station and add approximately one mile of overhead 230 kV double circuit transmission lines from both~~ the existing Brambleton-Yardley Ridge line and Brambleton-Poland Road line in Loudoun County, Virginia, estimated to cost approximately $30 million. In May 2020, the Virginia Commission issued an order approving in part and denying in part the petition. The Virginia Commission approved Virginia Power’s request to construct the new Evergreen Mills switching station and the new 230 kV double circuit transmission line from the existing Brambleton-Yardley Ridge line with a total estimated cost of $25 million.

~~Additional Virginia Power electric transmission projects approved and applied for are as follows:~~

Description and Location
of Project

Application
Date

Approval
Date

Type of
Line

Miles of
Lines

Cost Estimate
(millions)
Rebuild and operate five segments between the Loudoun and Ox substations

August 2019

June 2020

230 kV

19

70
Rebuild and operate two lines in Chesterfield County, Virginia

January 2020

June 2020

230 kV

3

15
Bristers-Ladysmith Rebuild Project in the counties of Fauquier, Stafford, Spotsylvania, and Caroline, Virginia

May 2020

Pending

500 kV

37

110

~~North Carolina Regulation~~

~~North Carolina Base Rate Case~~

In March 2019, Virginia Power filed its base rate case and schedules with the North Carolina Commission. Virginia Power proposed a non-fuel, base rate increase of $27 million effective November 1, 2019 on an interim basis subject to refund, with any permanent ratesinitial natural disaster protection plan that was ordered by the ~~North Carolina Commission effective January 1, 2020. The base rate increase was proposed~~PUCN and filed their first amendment to ~~recover~~ the ~~significant investments in generation,~~2020 natural disaster protection plan.

Northern Powergrid Distribution Companies

In December 2020, GEMA, through Ofgem, published its final determinations for transmission and gas distribution ~~infrastructure~~networks in Great Britain. These determinations do not apply directly to Northern Powergrid, but aspects of the proposals are capable of application at Northern Powergrid's next price control, ("ED2"), which will begin in April 2023. Regarding allowed return on capital, Ofgem determined a cost of equity of 4.55% (plus inflation calculated using the United Kingdom's consumer price index including owner occupiers' housing costs ("CPIH")). In March 2021, all the transmission and gas distribution networks lodged appeals with the Competition and Markets Authority against Ofgem's determination for the ~~benefit~~cost of ~~North Carolina customers. Virginia Power presented an earned return~~equity.

In December 2020, in respect of ~~7.52% based upon~~electricity distribution, GEMA published its decision on the methodology it will use to set the ED2 price control and prices from April 2023 to March 2028. This confirmed that Ofgem will apply many aspects of the proposals from the transmission and gas distribution price controls to electricity distribution.

GEMA published a fully-adjusted test period, compared to its authorized 9.90% return, and proposed a 10.75% ROE. In September 2019, Virginia Power revised its filing to reduce the non-fuel base rate increase to $24 million. In January 2020, the North Carolina Commission approved a 9.75% ROE and disallowed certain costs associated with coal ash remediation at Chesterfield power station. In February 2020, the North Carolina Commission issued its final order relating to base rates. In July 2020, Virginia Power filed a notice of appeal and exceptions to the Supreme Court of North Carolina, arguingseparate decision in March 2021, confirming that the ~~North Carolina Commission committed reversible error on certain issues relating to~~financial aspects in respect of electricity distribution would broadly follow the ~~ratemaking treatment of certain coal ash remediation costs. This matter is pending.~~

~~Pipeline Integrity~~transmission and ~~Safety Program~~

~~The North Carolina Commission has authorized PSNC to use~~gas distribution methodology, setting a tracker mechanism to recover the incurred capital investment and associated costs of complying with federal standards for pipeline integrity and safety requirements that are not in current base rates. In February 2020, the North Carolina Commission approved PSNC’s request to increase the integrity management annual revenue requirement to $28 million, an increase of $7 million over its previous filing, effective March 2020.

~~South Carolina Regulation~~

~~South Carolina Electric Base Rate Case~~

~~Pursuant to the SCANA Merger Approval Order,~~ ~~DESC will not file an application~~working assumption for a general rate case with the South Carolina Commission with a requested effective date for new rates earlier than January 2021. In April 2020, the South Carolina Commission issued an order vacating the portioncost of equity at 4.65% (plus CPIH), ahead of the ~~SCANA Merger Approval Order requiring that new retail electric rates be implemented~~final determinations in late 2022. When placed on a comparable footing, by ~~January 1, 2021. In July 2020, DESC filed a notice~~adjusting for differences in the assumed equity ratio and the measure of ~~intent with~~inflation used, the ~~South Carolina Commission to file~~working assumption for ~~an increase to base rates for retail electric service no earlier~~ED2 is approximately 150 basis points lower than ~~30 days following~~ the ~~notice.~~ ~~The net lost revenue recovery portion~~current cost of ~~the DSM rider would be adjusted lower simultaneously with any approved retail electric base rate increases~~equity.

~~DSM Programs~~

DESC has approval for a DSM rider through which it recovers expenditures related to its DSM programs. In January 2020, DESC filed an application with the South Carolina Commission seeking approval to recover $40 million of costs and net lost revenues associated with these programs, along with an incentive to invest in such programs. In April 2020, the South Carolina Commission approved the filing.

~~Cost of Fuel~~

In February 2020, DESC filed a proposal with the South Carolina Commission to decrease the total fuel cost component of retail electric rates. DESC’s proposed decrease would reduce annual base fuel component recoveries by $44 million and is projected to return to customers the existing over-collected balance while recovering DESC’s current base fuel costs over the 12-month period beginning with the first billing cycle of May 2020. In addition, DESC proposed an increase to its variable environmental and distributed energy resource components. In April 2020, the South Carolina Commission approved the filing.

~~Electric Transmission Projects~~

In 2020, DESC began several electric transmission projects in connection with two new nuclear plants under development by Southern. These transmission projects are required to be in place prior to these plants beginning operations to maintain reliability. DESC anticipates the projects to go into service in phases, costing approximately $75 million in aggregate. In February 2020, DESC filed an application with the South Carolina Commission requesting approval to construct and operate 28 miles of 230 kV transmission lines in Aiken County, South Carolina estimated to cost approximately $30 million. In June 2020, the South Carolina Commission approved the filing.

~~Natural Gas Rates~~

In June 2020, DESC filed with the South Carolina Commission its monitoring report for the 12-month period ended March 31, 2020 with a total revenue requirement of $409 million. This represents a $9 million overall annual increase to its natural gas rates under the terms of the Natural Gas Rate Stabilization Act effective with the first billing cycle of November 2020. This matter is pending.

~~Ohio Regulation~~

~~PIR Program~~

In 2008, East Ohio began PIR, aimed at replacing approximately 25% of its pipeline system. In April 2020, the Ohio Commission approved East Ohio’s application to adjust the PIR recovery for 2019 costs. The filing reflects gross plant investment for 2019 of $209 million, cumulative gross plant investment of $1.8 billion and an annual revenue requirement of $218 million.

BHE Pipeline Group

~~West Virginia Regulation~~

~~PREP~~

In May 2020, Hope filed a PREP application with the West Virginia Commission requesting approval to recover PREP costs related to $39 million and $54 million of projected capital investment for 2020 and 2021, respectively. The application also includes a true-up of PREP costs related to the 2019 actual capital investment of $27 million and sets forth $13 million of annual PREP costs to be recovered in proposed rates effective November 1, 2020. This matter is pending.

~~Wyoming Regulation~~

~~Wyoming Base Rate Case~~

In November 2019, Questar Gas filed its base rate case and schedules with the Wyoming Commission. Questar Gas proposed a non-fuel, base rate increase of $4 million effective September 2020. The base rate increase was proposed to replace aging infrastructure and expand its system. Questar Gas presented an earned return of 7.46%, based upon a fully-adjusted test period, compared to its authorized 9.5% return, and proposed a 10.5% ROE. In June 2020, the Wyoming Commission approved a base rate increase of $2 million annually, with rates effective September 1, 2020. This revenue requirement increase is based on an approved ROE of 9.35%.

~~FERC – Gas~~

~~Cove Point~~

BHE GT&S

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 ~~approximately~~ $182 million. In February 2020, the FERC approved suspending the changes in rates for five months following the proposed effective date, until August 1, 2020, subject to refund.

In ~~February~~November 2020, Cove Point ~~submitted its~~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 ~~electric power cost adjustment~~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 ~~requesting approval to recover $28 million.~~in January 2021. In March 2021, the FERC approved the ~~adjustment~~stipulation and agreement and the rate refunds to customers were processed in ~~March 2020.~~

~~Overthrust~~

late April.

BHE Transmission

AltaLink

Tariff Refund Application

In ~~May 2020, Overthrust~~January 2021, driven by the pandemic and economic shutdown that has negatively impacted all Albertans, AltaLink filed an application with the AUC that requested approval of tariff relief measures totaling C$350 million over the three-year period, 2021 to ~~request FERC authorization~~2023. The tariff relief measures consist of a proposed refund to ~~construct, operate~~customers of C$150 million of previously collected future income taxes and ~~maintain~~C$200 million of surplus accumulated depreciation. The future income tax refund would be evenly distributed over the ~~Wamsutter West Expansion project~~two-year period, 2021 to 2022, with C$75 million included in each year. The accumulated depreciation surplus would be refunded over the three-year period, 2021 to 2023, with C$60 million included in 2021 and 2022, and C$80 million in 2023. If approved by the AUC, these tariff relief measures would have saved customers an estimated C$317 million over the three-year period, 2021 to 2023.

In March 2021, the AUC issued a decision on AltaLink's Tariff Refund Application and approved a 2021 tariff refund in the amount of C$230 million and a net 2021 tariff reduction of C$224 million, which provides Alberta ratepayers with immediate tariff relief in 2021. The approved 2021 tariff refund includes a refund of C$150 million of previously collected future income tax and a refund of C$80 million of accumulated depreciation surplus. Tariff relief measures for years 2022 and 2023 will be proposed in AltaLink's 2022-2023 GTA.

2019-2021 General Tariff Application

In August 2018, AltaLink filed its 2019-2021 GTA with the AUC, delivering on the first three years of its commitment to keep rates lower or flat at the approved 2018 revenue requirement of C$904 million for customers for the next five years. In addition, AltaLink proposed to provide ~~120,000 Dth per day~~a further tariff reduction over the three year period by refunding previously collected accumulated depreciation surplus of ~~new capacity flowing east~~an additional C$31 million. In April 2019, AltaLink filed an update to ~~west from~~its 2019-2021 GTA primarily to reflect its 2018 actual results and the ~~Wamsutter interconnect~~impact of the AUC's decision on AltaLink's 2014-2015 Deferral Accounts Reconciliation Application. The application requested the approval of revised revenue requirements of C$879 million, C$882 million and C$885 million for 2019, 2020 and 2021, respectively.

In July 2019, AltaLink filed a 2019-2021 partial negotiated settlement application with the AUC. The application consisted of negotiated reductions that resulted in a net decrease of C$38 million to the ~~Opal interconnect.~~three year total revenue requirement applied for in AltaLink's 2019-2021 GTA updated in April 2019. However, this was offset by AltaLink's request for an additional C$20 million of forecast transmission line clearance capital as part of an excluded matter. The ~~project facilities are expected~~2019-2021 negotiated settlement agreement excluded certain matters related to ~~commence commercial operations~~the new salvage study and salvage recovery approach, additional capital spending and incremental asset retirements. AltaLink's salvage proposal is estimated to save customers C$267 million between 2019 and 2023. Excluded matters were examined by the AUC in a hearing held in November 2019, with written arguments filed in January 2020.

In April 2020, the AUC issued its decision with respect to AltaLink's 2019-2021 GTA. The AUC approved the negotiated settlement agreement as filed and rendered its decision and directions on the excluded matters. The AUC declined to approve AltaLink's proposed salvage methodology at that time, but indicated it would initiate a generic proceeding to review the matter on an industry-wide basis. The AUC approved, on a placeholder basis, C$13 million of the additional C$20 million AltaLink requested for forecast transmission line clearance capital. The remaining C$7 million of capital investment was reviewed in AltaLink's subsequent compliance filing. Also, C$3 million of forecast operating expenses and C$4 million of forecast capital expenditures related to fire risk mitigation were approved, with an additional C$31 million of capital expenditures reviewed in the ~~fourth quarter~~compliance filing. Finally, the AUC approved C$6 million of retirements for towers and fixtures.

In July 2020, the AUC approved AltaLink's compliance filing establishing revised revenue requirements of C$895 million for 2019, C$894 million for 2020 and ~~are expected~~C$898 million for 2021, exclusive of the assets transferred to ~~cost $10 million. FERC approved~~ the ~~application~~PiikaniLink Limited Partnership and the KainaiLink Limited Partnership.

The AUC deferred its decision on AltaLink's proposed salvage methodology included in AltaLink's 2019-2021 GTA, pending a generic proceeding to consider the broader implications. This generic proceeding was closed and in July ~~2020.~~

~~DETI~~

~~In January 2018, DETI~~2020, AltaLink filed an application ~~to request FERC authorization to construct and operate certain facilities located in Ohio and Pennsylvania~~with the AUC for the ~~Sweden Valley project.~~review and variance of the AUC's decision with respect to AltaLink's proposed salvage methodology. In ~~June 2019, DETI withdrew~~September 2020, the AUC granted this review on the basis that there were changed circumstances that could lead the AUC to materially vary or rescind the majority hearing panel's findings on AltaLink's proposed salvage methodology. In October 2020, AltaLink filed responses to information requests from the AUC, written argument was filed by intervening parties and written reply argument was filed by AltaLink. In November 2020, the AUC issued its ~~application~~decision on AltaLink's review and variance application. The AUC decided to vary the original decision and approve AltaLink's proposed net salvage method and the revised transmission tariffs as filed, effective December 2020. The new salvage methodology decreased the amount of salvage pre-collection resulting in reductions to AltaLink's revenue requirement from customers by C$24 million, C$27 million and C$31 million for the ~~project due~~years 2019, 2020 and 2021, respectively. AltaLink delivered on the first three years of its commitment to ~~certain regulatory delays. As~~customers to keep rates flat for five years by obtaining the necessary AUC approvals. AltaLink's approved 2019-2021 GTA maintains customer rates below the 2018 level of C$904 million from 2019 to 2021.

In March 2021, the AUC approved AltaLink's Tariff Refund Application resulting in a revised revenue requirement of C$873 million and revised transmission tariff of C$633 million for 2021.

2022-2023 General Tariff Application

In April 2021, AltaLink filed its 2022-2023 GTA delivering on the last two years of its commitment to keep rates flat for customers at or below the 2018 level of C$904 million for the five-year period from 2019 to 2023. The two-year application achieves flat tariffs continuing to transition to the AUC-approved salvage recovery method, continuing the use of the flow-through income tax method, and adding only a 1% increase to operations and maintenance expense, with the exception of salaries and wages and other expenses. In addition, similar to the C$80 million refund of the previously collected accumulated depreciation surplus approved by the AUC for 2021, AltaLink proposed to provide further similar tariff reductions over the two years by refunding an additional C$60 million per year. The application requested the approval of transmission tariff of C$824 million and C$847 million for 2022 and 2023, respectively.

2022 Generic Cost of Capital Proceeding

In December 2020, the AUC initiated the 2022 generic cost of capital proceeding. This proceeding will consider the return on equity and deemed equity ratios for 2022 and one or more additional test years. Due to the existing uncertainty as a result of the ~~project abandonment, during~~ongoing COVID-19 pandemic, before establishing a process schedule, the ~~second~~commission has requested participants to submit comments that address the following: (i) the continuation of the currently approved return on equity and deemed equity ratios for a further period of time; (ii) the appropriate test period for the proceeding; (iii) the scope of the proceeding, including whether a formula-based approach to return on equity should be utilized; (iv) the considerations to take into account when establishing the process for the proceeding; and (v) the avoidance of duplicative evidence and greater coordination and collaboration between parties.

In January 2021, AltaLink submitted a letter to the AUC stating that due to ongoing capital market volatility and other COVID-19 related uncertainties there are reasonable grounds for extending the currently approved 2021 return on equity and deemed equity ratio on a final basis for 2022. AltaLink further stated there is insufficient time to complete a full generic cost of capital proceeding in 2021, in order to issue a decision prior to the beginning of 2022 and a formula-based approach should not be considered at this time. AltaLink suggested that a proceeding could be restarted in the third quarter of 2021, for 2023 and subsequent years.

In March 2021, the AUC issued its decision with respect to setting the return on equity and deemed equity ratios for AltaLink. The AUC approved an equity return of 8.5% and an equity ratio of 37% for 2022, based on continuing economic and market uncertainties, the unsettled nature of capital markets, and the need for certainty and stability for Alberta ratepayers.

In April 2021, the Utilities Consumer Advocate filed an application with the Court of Appeal of Alberta requesting permission to appeal the AUC's decision that set the return on equity of 8.5% and equity ratio of 37% on a final basis for 2022. In the appeal, the Utilities Consumer Advocate alleges that the AUC erred by failing to fulfil its statutory obligation of establishing a fair return and by failing to apply procedural fairness.

2019 ~~DETI recorded a charge~~Deferral Accounts Reconciliation Application

In October 2020, AltaLink filed its application with the AUC, which includes ten projects with total gross capital additions of ~~$13~~C$129 million, ~~($10~~including applicable AFUDC. In December 2020, AltaLink provided responses to AUC information requests, interveners filed written argument and AltaLink filed reply argument.

In March 2021, the AUC issued its decision on AltaLink's 2019 Deferral Accounts Reconciliation Application. The AUC approved C$128.0 million ~~after-tax), included~~of the C$128.5 million of gross capital project additions, disallowing C$0.5 million of capital costs. The AUC also approved the other deferral accounts for taxes other than income taxes, long-term debt and annual structure payments as filed. AltaLink filed its compliance filing in ~~impairment of assets~~April 2021.

Environmental Laws and Regulations

Each Registrant is subject to federal, state, local and foreign laws and regulations regarding climate change, RPS, air and water quality, emissions performance standards, coal combustion byproduct disposal, hazardous and solid waste disposal, protected species and other ~~charges~~environmental matters that have the potential to impact each Registrant's current and future operations. In addition to imposing continuing compliance obligations, these laws and regulations provide regulators with the authority to levy substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state, local and international agencies. Each Registrant believes it is in ~~Dominion Energy~~material compliance with all applicable laws and ~~Dominion Energy Gas’ Consolidated Statements~~regulations, although many laws and regulations are subject to interpretation that may ultimately be resolved by the courts. The discussion below contains material developments to those matters disclosed in Item 1 of ~~Income.~~

~~Note 14. Leases~~

~~Other than the items discussed below, there have been no significant changes regarding the Companies’ leases as described in Note 15 to the Consolidated Financial Statements in the Companies’~~each Registrant's Annual Report on Form 10-K for the year ended December 31, ~~2019.~~

~~Dominion Energy’s Consolidated Statements~~2020, and new environmental matters occurring in 2021.

Climate Change

In December 2015, an international agreement was negotiated by 195 nations to create a universal framework for coordinated action on climate change in what is referred to as the Paris Agreement. The Paris Agreement reaffirms the goal of ~~Income include $53 million~~limiting global temperature increase well below 2 degrees Celsius, while urging efforts to limit the increase to 1.5 degrees Celsius; establishes commitments by all parties to make nationally determined contributions and ~~$85 million~~pursue domestic measures aimed at achieving the commitments; commits all countries to submit emissions inventories and report regularly on their emissions and progress made in implementing and achieving their nationally determined commitments; and commits all countries to submit new commitments every five years, with the expectation that the commitments will get more aggressive. In the context of the Paris Agreement, the United States agreed to reduce GHG emissions 26% to 28% by 2025 from 2005 levels. After more than 55 countries representing more than 55% of global GHG emissions submitted their ratification documents, the Paris Agreement became effective November 4, 2016. On June 1, 2017, President Trump announced the United States would begin the process of withdrawing from the Paris Agreement. The United States completed its withdrawal from the Paris Agreement on November 4, 2020. President Biden accepted the terms of the climate agreement January 20, 2021, and the United States completed its reentry February 19, 2021. At a Climate Leaders Summit held April 22 through April 23, 2021, President Biden announced new climate goals to cut GHG 50%-52% economy-wide by 2030 compared to 2005 levels, and to reach 100% carbon pollution-free electricity by 2035. Additional details on how the United States will implement these goals is anticipated to be released through fall 2021.

Clean Air Act Regulations

The Clean Air Act is a federal law administered by the EPA that provides a framework for protecting and improving the ~~three~~nation's air quality and ~~six months ended June 30, 2020, respectively,~~controlling sources of air emissions. The implementation of new standards is generally outlined in SIPs, which are a collection of regulations, programs and ~~$53 million~~policies to be followed. SIPs vary by state and $82 million for the three and six months ended June 30, 2019, respectively, of rental revenue included in operating revenue. Dominion Energy’s Consolidated Statements of Income include $27 million and $50 million for the three and six months ended June 30, 2020, respectively, and $24 million and $47 million for the three and six months ended June 30, 2019, respectively, of depreciation expense included in depreciation, depletion and amortization, related to facilitiesare subject to ~~power purchase agreements under which Dominion Energy is~~public hearings and EPA approval. Some states may adopt additional or more stringent requirements than those implemented by the ~~lessor.~~

~~Corporate Office Leasing Arrangement~~

EPA. The major Clean Air Act programs most directly affecting the Registrants' operations as described below.

~~In December 2019, Dominion Energy signed an agreement with~~

GHG Performance Standards

Under the Clean Air Act, the EPA may establish emissions standards that reflect the degree of emissions reductions achievable through the best technology that has been demonstrated, taking into consideration the cost of achieving those reductions and any non-air quality health and environmental impact and energy requirements. On August 3, 2015, the EPA issued final new source performance standards, establishing a ~~lessor, as amended in May 2020, to construct~~standard of 1,000 pounds of carbon dioxide per MWh for large natural gas-fueled generating facilities and ~~lease a~~1,400 pounds of carbon dioxide per MWh for new corporate office property in Richmond, Virginia. The lessor is providing equity and has obtained financing commitments from debt investors, totaling $465 million, to fund the estimated project costs. If Dominion Energy ultimately proceedscoal-fueled generating facilities with the ~~project~~"Best System of Emission Reduction" reflecting highly efficient supercritical pulverized coal facilities with partial carbon capture and sequestration or integrated gasification combined-cycle units that are co-fired with natural gas or pre-combustion slipstream capture of carbon dioxide. The new source performance standards were appealed to the D.C. Circuit and oral argument was scheduled for April 17, 2017. However, oral argument was deferred and the court held the case in abeyance for an indefinite period of time. On December 6, 2018, the EPA announced revisions to new source performance standards for new and reconstructed coal-fueled units. EPA proposes to revise carbon dioxide emission limits for new coal-fueled facilities to 1,900 pounds per MWh for small units and 2,000 pounds per MWh for large units. The EPA would define the best system of emission reduction for new and modified units as the most efficient demonstrated steam cycle, combined with best operating practices. On January 12, 2021, EPA finalized a rule focused solely on a significant contribution finding for purposes of regulating source categories' GHG emissions. The final rule sets no specific regulatory standards and contains no regulatory text, nor does it address what constitutes the best system of emission reduction for new, modified and reconstructed electric generating units. EPA confirms in the "significant contribution" rule that electric generating units remain a listed source category under Clean Air Act Section 111(b), reaching that conclusion through ~~completion,~~ the ~~project~~introduction of an emissions threshold framework by which a source category is deemed to contribute significantly to dangerous air pollution due to their GHG emissions if the amount of those emissions exceeds 3% of total GHG emissions in the United States. Under this methodology, no other source category would qualify for regulation. The significant contribution rule will take effect 60 days after publication in the Federal Register but is expected to be ~~completed~~quickly revisited by ~~September 2024. Dominion Energy has been appointed to act as~~ the ~~construction agent for~~Biden administration. Because the ~~lessor, during which time Dominion Energy~~significant contribution rule did not alter the emission limits or technology requirements of the 2015 rule, any new fossil-fueled generating facilities will ~~request cash draws from the lessor and debt investors to fund all project costs. If the project is terminated under certain events, Dominion Energy could~~ be required to ~~pay up to 100%~~meet the GHG new source performance standards. The D.C. Circuit vacated the significant contribution rule April 5, 2021, remanding it for further proceedings.

National Ambient Air Quality Standards

Under the authority of the ~~then funded amount.~~

~~The lease term will commence once construction is substantially complete~~Clean Air Act, the EPA sets minimum NAAQS for six principal pollutants, consisting of carbon monoxide, lead, NOx, particulate matter, ozone and SO2, considered harmful to public health and the environment. Areas that achieve the standards, as determined by ambient air quality monitoring, are characterized as being in attainment, while those that fail to meet the standards are designated as being nonattainment areas. Generally, sources of emissions in a nonattainment area that are determined to contribute to the nonattainment are required to reduce emissions. Currently, with the exceptions described in the following paragraphs, air quality monitoring data indicates that all counties where the relevant Registrant's major emission sources are located are in attainment of the current NAAQS.

In June 2010, the EPA finalized a new NAAQS for SO2. Under the 2010 rule, areas must meet a one-hour standard of 75 parts per billion utilizing a three-year average. The rule utilizes source modeling in addition to the installation of ambient monitors where SO2 emissions impact populated areas. Attainment designations were due by June 2012; however, citing a lack of sufficient information to make the designations, the EPA did not issue its final designations until July 2013 and determined, at that date, that a portion of Muscatine County, Iowa was in nonattainment for the one-hour SO2 standard. MidAmerican Energy's Louisa coal-fueled generating facility is ~~able~~located just outside of Muscatine County, south of the violating monitor. In its final designation, the EPA indicated that it was not yet prepared to conclude that the emissions from the Louisa coal-fueled generating facility contribute to the monitored violation or to other possible violations, and that in a subsequent round of designations, the EPA will make decisions for areas and sources outside Muscatine County. MidAmerican Energy does not believe a subsequent nonattainment designation will have a material impact on the Louisa coal-fueled generating facility. Although the EPA's July 2013 designations did not impact PacifiCorp's nor the Nevada Utilities' generating facilities, the EPA's assessment of SO2 area designations will continue with the deployment of additional SO2 monitoring networks across the country. On February 25, 2019, the EPA issued a decision to retain the 2010 SO2 NAAQS without revision.

The Sierra Club filed a lawsuit against the EPA in August 2013 with respect to the one-hour SO2 standards and its failure to make certain attainment designations in a timely manner. In March 2015, the United States District Court for the Northern District of California ("Northern District of California") accepted as an enforceable order an agreement between the EPA and Sierra Club to resolve litigation concerning the deadline for completing the designations. The Northern District of California's order directed the EPA to complete designations in three phases: the first phase by July 2, 2016; the second phase by December 31, 2017; and the final phase by December 31, 2020. The first phase of the designations require the EPA to designate two groups of areas: 1) areas that have newly monitored violations of the 2010 SO2 standard; and 2) areas that contain any stationary source that, according to the EPA's data, either emitted more than 16,000 tons of SO2 in 2012 or emitted more than 2,600 tons of SO2 and had an emission rate of at least 0.45 lbs/SO2 per million British thermal unit in 2012 and, as of March 2, 2015, had not been announced for retirement. MidAmerican Energy's George Neal Unit 4 and the Ottumwa Generating Station (in which MidAmerican Energy has a majority ownership interest, but does not operate), are included as units subject to the first phase of the designations, having emitted more than 2,600 tons of SO2 and having an emission rate of at least 0.45 lbs/SO2 per million British thermal unit in 2012. States may submit to the EPA updated recommendations and supporting information for the EPA to consider in making its determinations. Iowa submitted documentation to the EPA in April 2016 supporting its recommendation that Des Moines, Wapello and Woodbury Counties be ~~occupied~~designated as being in attainment of the standard. In July 2016, the EPA's final designations were published in the Federal Register indicating portions of Muscatine County, Iowa were in nonattainment with the 2010 SO2 standard, Woodbury County, Iowa was unclassifiable, and ~~end~~Des Moines and Wapello Counties were unclassifiable/attainment. On March 26, 2021, the EPA issued the last of its final designations for the 2010 primary SO2 standard. Included in this round was designation of Converse County, Wyoming as an Attainment/Unclassifiable area. PacifiCorp's Dave Johnston generating facility is located in Converse County. No further action by PacifiCorp is required.

Cross-State Air Pollution Rule

The EPA promulgated an initial rule in March 2005 to reduce emissions of NOx and SO2, precursors of ozone and particulate matter, from down-wind sources in the eastern United States, including Iowa, to reduce emissions by implementing a plan based on a market-based cap-and-trade system, emissions reductions, or both. After numerous appeals, the CSAPR was promulgated to address interstate transport of SO2 and NOx emissions in 27 eastern and Midwestern states.

The first phase of the rule was implemented January 1, 2015. In November 2015, the EPA released a proposed rule that would further reduce NOx emissions in 2017. The final "CSAPR Update Rule" was published in the Federal Register in October 2016 and required additional reductions in NOx emissions beginning in May 2017. On December ~~2027. At~~6, 2018, EPA finalized a rule to close out the CSAPR, having determined that the CSAPR Update for the 2008 ozone NAAQS fully addressed Clean Air Act interstate transport obligations of 20 eastern states. EPA determined that 2023 is an appropriate future analytic year to evaluate remaining good neighbor obligations and that there will be no remaining nonattainment or maintenance receptors with respect to the 2008 ozone NAAQS in the eastern United States in that year. Accordingly, the 20 CSAPR Update-affected states would not contribute significantly to nonattainment in, or interfere with maintenance of, any other state with regard to the 2008 ozone NAAQS. Both the CSAPR Update and the CSAPR Close-Out rules were challenged in the D.C. Circuit. The D.C. Circuit ruled September 13, 2019, that because the EPA allowed upwind States to continue to significantly contribute to downwind air quality problems beyond statutory deadlines, the CSAPR Update Rule provided only a partial remedy that did not fully address interstate ozone transport, and remanded the CSAPR Update Rule back to the EPA. The D.C. Circuit issued an opinion October 1, 2019, finding that because the CSAPR Close-Out Rule relied on the same faulty reasoning as the CSAPR Update rule, the CSAPR Close-Out Rule must be vacated. On October 15, 2020, the EPA proposed to tighten caps on emissions of NOx from power plants in 12 states in the CSAPR trading program in response to the D.C. Circuit's decision to vacate the CSAPR Update rule. The rule is intended to fully resolve 21 upwind states' remaining good neighbor obligations under the 2008 ozone NAAQS. Additional emissions reductions are required at power plants in 12 states, including Illinois; the EPA predicts that emissions from the remaining nine states, including Iowa and Texas, will not significantly contribute to downwind states' ability to attain or maintain the ozone standard. The EPA accepted comment on the proposal through December 15, 2020. On March 15, 2021, the EPA finalized the Revised CSAPR Update largely as proposed. Significant new compliance obligations are not anticipated as a result of the rule.

Regional Haze

The EPA's Regional Haze Rule, finalized in 1999, requires states to develop and implement plans to improve visibility in designated federally protected areas ("Class I areas"). Some of PacifiCorp's coal-fueled generating facilities in Utah, Wyoming, Arizona and Colorado and certain of Nevada Power's and Sierra Pacific's fossil-fueled generating facilities are subject to the Clean Air Visibility Rules. In accordance with the federal requirements, states are required to submit SIPs that address emissions from sources subject to BART requirements and demonstrate progress towards achieving natural visibility requirements in Class I areas by 2064.

The state of Utah issued a regional haze SIP requiring the installation of SO2, NOx and particulate matter controls on Hunter Units 1 and 2, and Huntington Units 1 and 2. In December 2012, the EPA approved the SO2 portion of the Utah regional haze SIP and disapproved the NOx and particulate matter portions. Subsequently, the Utah Division of Air Quality completed an alternative BART analysis for Hunter Units 1 and 2, and Huntington Units 1 and 2. In January 2016, the EPA published two alternative proposals to either approve the Utah SIP as written or reject the Utah SIP relating to NOx controls and require the installation of SCR controls at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years. EPA's final action on the Utah regional haze SIP was effective August 4, 2016. The EPA approved in part and disapproved in part the Utah regional haze SIP and issued a federal implementation plan ("FIP") requiring the installation of SCR controls at Hunter Units 1 and 2 and Huntington Units 1 and 2 within five years of the effective date of the rule. PacifiCorp and other parties filed requests with the EPA to reconsider and stay that decision, as well as filed motions for stay and petitions for review with the Tenth Circuit Court of Appeals ("Tenth Circuit") asking the court to overturn the EPA's actions. In July 2017, the EPA issued a letter indicating it would reconsider its FIP decision. In light of the EPA's grant of reconsideration and the EPA's position in the litigation, the Tenth Circuit held the litigation in abeyance and imposed a stay of the compliance obligations of the FIP for the number of days the stay is in effect while the EPA conducts its reconsideration process. To support the reconsideration, PacifiCorp undertook additional air quality modeling using the Comprehensive Air Quality Model with Extensions dispersion model. On January 14, 2019, the state of Utah submitted a SIP revision to the EPA, which includes the updated modeling information and additional analysis. On June 24, 2019, the Utah Air Quality Board unanimously voted to approve the Utah regional haze SIP revision, which incorporates a BART alternative into Utah's regional haze SIP. The BART alternative makes the shutdown of PacifiCorp's Carbon plant enforceable under the SIP and removes the requirement to install SCR technology on Hunter Units 1 and 2 and Huntington Units 1 and 2. The Utah Division of Air Quality submitted the SIP revision to the EPA for approval at the end of 2019. In January 2020, the ~~initial lease term, Dominion Energy can (i) extend the term of the lease for an additional five years, subject to the~~EPA published its proposed approval of the ~~participants, at current market terms, (ii) purchase~~Utah Regional Haze SIP Alternative, which makes the ~~property for an amount equal to the project costs or, (iii) subject to certain terms and conditions, sell the property on behalf~~shutdown of the ~~lessor~~Carbon plant federally enforceable and adopts as BART the existing NOx controls and emission limits on the Hunter and Huntington plants. The proposed approval withdraws the FIP requirements to ~~a third party using commercially reasonable efforts to obtain~~install SCR on Hunter Units 1 and 2 and Huntington Units 1 and 2. The EPA released the ~~highest cash purchase price~~final rule approving the Utah Regional Haze SIP Alternative on October 28, 2020. With the approval, the EPA also finalized its withdrawal of the FIP requirements for the ~~property. If~~Hunter and Huntington plants. The Utah Regional Haze SIP Alternative took effect December 28, 2020. As a result of these actions, the ~~project is sold~~Tenth Circuit dismissed the Utah regional haze petitions on January 11, 2021. On January 19, 2021, Heal Utah, National Parks Conservation Association, Sierra Club and Utah Physicians for a Healthy Environment filed a petition for review of the Utah Regional Haze SIP Alternative in the Tenth Circuit. PacifiCorp and the ~~proceeds from~~state of Utah moved to intervene in the ~~sale are insufficient to repay~~litigation, which has been stayed pending the ~~investors for~~Biden administration's review of the ~~project costs, Dominion Energy may be required~~rule.

Critical Accounting Estimates

Certain accounting measurements require management to make ~~a payment to the lessor, up to 83% of project costs, for the difference between the project costs~~estimates and sale proceeds. Dominion Energy is not considered the owner during construction for financial accounting purposes and, therefore, will not reflect the construction activity in its consolidated financial statements. Dominion Energy expects to recognize a right-of-use asset and a corresponding finance lease liability at the commencement of the lease term. Dominion Energyjudgments concerning transactions that will be ~~considered~~settled several years in the ~~owner of the leased property for tax purposes, and as a result, will be entitled to tax deductions for depreciation and interest expense.~~

~~Note 15. Variable Interest Entities~~

~~There have been no significant changes regarding the entities the Companies consider VIEs as described in Note 16 to~~future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of judgment and uncertainty and will likely change in the ~~Companies’~~future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, derivatives, impairment of goodwill and long-lived assets, pension and other postretirement benefits, income taxes and revenue recognition - unbilled revenue. For additional discussion of the Company's critical accounting estimates, see Item 7 of the Company's Annual Report on Form 10-K for the year ended December 31, ~~2019.~~

~~Dominion Energy~~

~~At June 30,~~2020. There have been no significant changes in the Company's assumptions regarding critical accounting estimates since December 31, 2020.

PacifiCorp and its subsidiaries

Consolidated Financial Section

PART I

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

PacifiCorp

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of PacifiCorp and subsidiaries ("PacifiCorp") as of March 31, 2021, the related consolidated statements of operations, changes in shareholders' equity and cash flowsfor the three-month periods ended March 31, 2021 and 2020, and ~~December 31, 2019, Dominion Energy’s securities due within one year included $32 million and $31 million, respectively, and long-term debt included $258 million and $267 million~~the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of ~~debt issued by SBL Holdco, a VIE, net of issuance costs,~~any material modifications that ~~is nonrecourse to Dominion Energy and is secured by SBL Holdco’s interest in certain merchant solar facilities.~~

~~Virginia Power~~

Virginia Power had a long-term power and capacity contract with 1 non-utility generator with an aggregate summer generation capacity of approximately 218 MW. In May 2019, Virginia Power entered into an agreement and paid $135 million to terminate the remaining contract with the non-utility generator, effective April 2019. A $135 million ($100 million after-tax) charge was recorded in impairment of assets and other charges in Virginia Power’s Consolidated Statements of Income for the three and six months ended June 30, 2019. Virginia Power paid $13 million for electric capacity and $1 million for electric energyshould be made to the ~~non-utility generator~~accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the ~~six months ended June 30, 2019.~~

~~Dominion Energy Gas~~

~~Dominion Energy Gas purchased shared services from DECGS and DEQPS~~United States of $3 million and $7 million for the three months ended June 30, 2020, $5 million and $11 million for the three months ended June 30, 2019, $7 million and $14 million for the six months ended June 30, 2020, and $9 million and $20 million for the six months ended June 30, 2019, respectively. Dominion Energy Gas’ Consolidated Balance Sheets included amounts due to both DECGS and DEQPS of $18 million and $15 million at June 30, 2020 and December 31, 2019, respectively.

~~Virginia Power and Dominion Energy Gas~~

Virginia Power and Dominion Energy Gas purchased shared services from DES, an affiliated VIE, of $86 million and $27 million for the three months ended June 30, 2020, respectively, and $129 million and $39 million for the three months ended June 30, 2019, $179 million and $58 million for the six months ended June, 30, 2020 and $218 million and $67 million for the six months ended June 30, 2019, respectively. Virginia Power’s Consolidated Balance Sheets include amounts due to DES of $92 million and $102 million at June 30, 2020 and December 31, 2019, respectively, recorded in payables to affiliates. Dominion Energy Gas’ Consolidated Balance Sheets include amounts due to DES of $38 million and $27 million at June 30, 2020 and December 31, 2019, respectively, recorded in payables to affiliates.

America.

~~Note 16. Significant Financing Transactions~~

~~Credit Facilities and Short-term Debt~~

The Companies use short-term debt to fund working capital requirements and as a bridge to long-term debt financings. The levels of borrowing may vary significantly during the course of the year, depending upon the timing and amount of cash requirements not satisfied by cash from operations. In addition, Dominion Energy utilizes cash and letters of credit to fund collateral requirements. Collateral requirements are impacted by commodity prices, hedging levels, Dominion Energy’s credit ratings and the credit quality of its counterparties.

~~Dominion Energy~~

~~At June 30, 2020, Dominion Energy’s commercial paper and letters of credit outstanding, as well as its capacity available under the credit facility, were as follows:~~

Facility
Limit

Outstanding
Commercial
Paper

Outstanding
Letters of
Credit

Facility
Capacity
Available

(millions)

Joint revolving credit facility⁽¹⁾

$
6,000

$
210

$
103

$
5,687

~~(1)~~

This credit facility matures in March 2023 and can be used by the borrowers under the credit facility to support bank borrowings and the issuance of commercial paper, as well as to support up to a combined $2.0 billion of letters of credit.

~~In addition to the credit facility mentioned above, Dominion Energy also has a credit facility which had an original stated maturity date of~~ ~~June 2020~~ and allowed Dominion Energy to issue up to approximately $21 million in letters of credit. In May 2020, the credit facility was amended to increase the facility capacity to approximately $30 million and extend the maturity date to ~~June 2022. At June 30, 2020, Dominion Energy had $21 million in letters of credit outstanding under this agreement.~~

In March 2020, Dominion Energy entered into a $900 million 364-Day Revolving Credit Agreement. The agreement bears interest at a variable rate. At June 30, 2020, $225 million was outstanding under the agreement. The proceeds from these borrowings were used to provide for general working capital and other general corporate purposes. The maximum allowed total debt to total capital ratio under the agreement is consistent with such allowed ratio under Dominion Energy’s joint revolving credit facility.

DESC and Questar Gas’ short-term financings are supported through access as co-borrowers to the joint revolving credit facility discussed above with Dominion Energy, Virginia Power and Dominion Energy Gas. At June 30, 2020, the sub-limits for DESC and Questar Gas were $500 million and $250 million, respectively.

In January 2020, DESC and GENCO applied to FERC for a two-year short-term borrowing authorization. In March 2020, FERC granted DESC authority through March 2021 to issue short-term indebtedness (pursuant to Section 204 of the Federal Power Act) in amounts not to exceed $2.2 billion outstanding with maturity dates of one year or less. In addition, in March 2020, FERC granted GENCO authority through March 2021 to issue short-term indebtedness not to exceed $200 million outstanding with maturity dates of one year or less.

~~In addition to the credit facilities mentioned above, SBL Holdco has $30 million of credit facilities which had an original stated maturity date of December 2017 with automatic~~ ~~one-year~~ renewals through the maturity of the SBL Holdco term loan agreement in 2023. Dominion Solar Projects III, Inc. has $25 million of credit facilities which had an original stated maturity date of May 2018 with automatic ~~one-year~~ ~~renewals through the maturity of the Dominion Solar Projects III, Inc. term loan agreement in 2024. At June 30, 2020, 0 amounts were outstanding under either of these facilities.~~

~~In March 2020, Dominion Energy borrowed $500 million under a 364-Day Term Loan Credit Agreement that bears interest at a variable rate.~~ The proceeds were used to provide for general working capital and other general corporate purposes. These borrowings are presented within securities due within one year in Dominion Energy’s Consolidated Balance Sheets at June 30, 2020. The maximum allowed total debt to total capital ratio under the agreement is consistent with such allowed ratio under Dominion Energy’s joint revolving credit facility.

~~In April 2020, Dominion Energy borrowed $625 million under a 364-Day Term Loan Credit Agreement that bore interest at a variable rate.~~ ~~The proceeds were used to provide for general working capital and other general corporate purposes. In June 2020, Dominion Energy repaid the outstanding balance in full.~~

amount that may be outstanding at any one time to $1.0 billion. The notes are offered on a continuous basis and bear interest at a floating rate per annum determined by the Dominion Energy Reliability Investment Committee, or its designee, on a weekly basis. The notesWe have no stated maturity date, are non-transferable and may be redeemed in whole or in part by Dominion Energy or at the investor’s option at any time. At June 30, 2020 and December 31, 2019, Dominion Energy’s Consolidated Balance Sheets include $176 million and $75 million, respectively, presented within short-term debt. The proceeds are used for general corporate purposes and to repay debt.

~~Virginia Power~~

Virginia Power’s short-term financing is supported through its access as co-borrower to the joint revolving credit facility. This credit facility can be used for working capital, as support for the combined commercial paper programs of the borrowers under the credit facility and for other general corporate purposes.

At June 30, 2020, Virginia Power’s share of commercial paper and letters of credit outstanding under its joint credit facility with Dominion Energy, Dominion Energy Gas, Questar Gas and DESC was as follows:

Facility
Limit⁽¹⁾

Outstanding
Commercial
Paper

Outstanding
Letters of
Credit

(millions)

Joint revolving credit facility⁽¹⁾

$
6,000

$
—

$
9

~~(1)~~

The full amount of the facility is available to Virginia Power, less any amounts outstanding to co-borrowers Dominion Energy, Dominion Energy Gas, Questar Gas and DESC. The sub-limit for Virginia Power is set within the facility limit but can be changed at the option of the borrowers under the credit facility multiple times per year. At June 30, 2020, the sub-limit for Virginia Power was $1.5 billion. If Virginia Power has liquidity needs in excess of its sub-limit, the sub-limit may be changed or such needs may be satisfied through short-term intercompany borrowings from Dominion Energy. This credit facility matures in March 2023 and can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $2.0 billion (or the sub-limit, whichever is less) of letters of credit.

~~Dominion Energy Gas~~

Dominion Energy Gas’ short-term financing is supported through its access as co-borrower to the joint revolving credit facility. This credit facility can be used for working capital, as support for the combined commercial paper programs of the borrowers under the credit facility and for other general corporate purposes.

At June 30, 2020, Dominion Energy Gas' share of commercial paper and letters of credit outstanding under its joint credit facility with Dominion Energy, Virginia Power, Questar Gas and DESC was as follows:

Facility
Limit⁽¹⁾

Outstanding
Commercial
Paper

Outstanding
Letters of
Credit

(millions)

Joint revolving credit facility⁽¹⁾

$
1,500

$
—

$
—

~~(1)~~

A maximum of $1.5 billion of the facility is available to Dominion Energy Gas, assuming adequate capacity is available after giving effect to uses by co-borrowers Dominion Energy, Virginia Power, Questar Gas and DESC. The sub-limit for Dominion Energy Gas is set within the facility limit but can be changed at the option of the borrowers under the credit facility multiple times per year. At June 30, 2020, the sub-limit for Dominion Energy Gas was $750 million. If Dominion Energy Gas has liquidity needs in excess of its sub-limit, the sub-limit may be changed or such needs may be satisfied through short-term intercompany borrowings from Dominion Energy. This credit facility matures in March 2023 and can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion (or the sub-limit, whichever is less) of letters of credit.

~~Long-term Debt~~

~~Unless otherwise noted, the proceeds of long-term debt issuances were used for general corporate purposes and/or to repay short-term debt.~~

In February 2020, Dominion Energy redeemed the remaining principal outstanding of $111 million and $286 million of its June 2006 hybrids and its September 2006 hybrids, respectively, both which would have otherwise matured in 2066. All purchases were

conducted in compliance with the applicable RCC, each of which was terminated in February 2020. Expenses related to the early redemption of the hybrids were $10 million reflected within interest and related charges in the Consolidated Statements of Income for the six months ended June 30, 2020.

In March 2020, SCANA redeemed its floating rate senior notes at the remaining principal balance of $66 million plus accrued interest. The notes would have otherwise matured in June 2034. Expenses related to the early redemption of the senior notes were $7 million reflected within interest and related charges in the Consolidated Statements of Income for the six months ended June 30, 2020.

In March 2020, SCANA redeemed the remaining principal outstanding of $183 million of its 4.75% medium-term notes and $155 million of its 4.125% medium-term notes plus accrued interest and make-whole premiums. The notes would have otherwise matured in May 2021 and February 2022, respectively. Total expenses related to the early redemption of the medium-term notes were $14 million reflected within interest and related charges in the Consolidated Statements of Income for the six months ended June 30, 2020.

~~In March 2020, Dominion Energy issued $400 million of 3.30% senior notes and $350 million of 3.60% senior notes that mature in 2025 and 2027, respectively.~~

~~In March 2020, PSNC issued, through private placement, $200 million of 4.05% senior notes that mature in 2030.~~

~~In April 2020, Dominion Energy issued $1.5 billion of 3.375% senior notes that mature in 2030.~~

In April 2020, Dominion Energy purchased and canceled $7 million of its 2.579% junior subordinated notes that mature in July 2020. In June 2020, Dominion Energy prepaid the remaining balance of $993 million.

In June 2020, East Ohio issued, through private placement, $500 million of 1.30% senior notes, $500 million of 2.00% senior notes and $800 million of 3.00% senior notes that mature in 2025, 2030 and 2050, respectively. East Ohio used the proceeds from this offering to repay intercompany promissory notes with Dominion Energy Gas and a portion of its intercompany revolving credit agreement balance with Dominion Energy.

In June 2020, Virginia Power remarketed 1 series of tax-exempt bonds, with an aggregate outstanding principal of $105 million to new investors. The bonds will bear interest at a coupon rate of 1.20% until May 2024, after which they will bear interest at a market rate to be determined at that time.

~~Derivative Restructuring~~

In June 2020, Dominion Energy amended a portfolio of interest rate swaps with a notional value of $2.0 billion, extending the mandatory termination dates from 2020 and 2021 to December 2024. The transaction is viewed as a non-cash financing activity with an embedded interest rate swap. As a result, in June 2020, Dominion Energy recorded $326 million in other long-term debt, representing the net present value of the initial fair value measurement of the new contract with an imputed interest rate of 1.19%, in its Consolidated Balance Sheets with an embedded interest rate derivative that had a fair value of zero at inception.

~~Noncontrolling Interest in Dominion Energy Midstream~~

In January 2019, Dominion Energy and Dominion Energy Midstream closed on an agreement and plan of merger pursuant to which Dominion Energy acquired each outstanding common unit representing limited partner interests in Dominion Energy Midstream not already owned by Dominion Energy through the issuance of 22.5 million shares of common stock valued at $1.6 billion. Under the terms of the agreement and plan of merger, each publicly held outstanding common unit representing limited partner interests in Dominion Energy Midstream was converted into the right to receive 0.2492 shares of Dominion Energy common stock. Immediately prior to the closing, each Series A Preferred Unit representing limited partner interests in Dominion Energy Midstream was converted into common units representing limited partner interests in Dominion Energy Midstreampreviously audited, in accordance with the ~~terms~~standards of ~~Dominion Energy Midstream’s partnership agreement.~~ the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of PacifiCorp as of December 31, 2020, and the related consolidated statements of operations, comprehensive income, changes in shareholders' equity, and cash flows for the year then ended (not presented herein); and in our report dated February 26, 2021, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet as of December 31, 2020, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

~~In June 2019, Dominion Energy issued $1.6 billion of 2019 Equity Units, initially in the form of 2019 Series A Corporate Units.~~

~~As a result of issues generated in the ordinary course of business, the Companies are involved in legal proceedings before various courts and are periodically~~

The following is a list of exhibits filed as ~~follows:~~

~~Primary Operating Segment~~	~~Description of Operations~~	~~Dominion~~ ~~Energy~~	~~Virginia~~ ~~Power~~	~~Dominion~~ ~~Energy~~ ~~Gas~~
~~Dominion Energy Virginia~~	~~Regulated electric distribution~~	X	X
	~~Regulated electric transmission~~	X	X
	~~Regulated electric generation fleet~~⁽¹⁾	X	X
~~Gas Transmission & Storage~~	~~Regulated gas transmission and storage~~⁽²⁾	X		X
	~~LNG terminalling and storage~~	X		X
	~~Nonregulated retail energy marketing~~	X
~~Gas Distribution~~	~~Regulated gas distribution and storage~~⁽³⁾	X
~~Dominion Energy South~~ ~~Carolina~~	~~Regulated electric distribution~~	X
	~~Regulated electric transmission~~	X
	~~Regulated electric generation fleet~~	X
	~~Regulated gas distribution and storage~~	X
~~Contracted Generation~~	~~Merchant electric generation fleet~~	X

~~(1)~~

I~~ncludes Virginia Power’s nonjurisdictional generation operations.~~

part of this Quarterly Report.

~~(2)~~

~~Includes gathering and processing activities.~~

~~(3)~~

~~Includes Wexpro’s gas development and production operations.~~

165

~~In addition~~

Exhibit No.Description

BERKSHIRE HATHAWAY ENERGY

4.1Fiscal Agency Agreement, dated as of April 9 , 20 21 , by and between Northern Natural Gas Company and The Bank of New York Mellon Trust Company, N.A., Fiscal Agent, relating to the ~~operating segments above, the Companies also report a Corporate and Other segment.~~

~~Dominion Energy~~

~~The Corporate and Other Segment of Dominion Energy~~ includes its corporate, service company and other functions (including unallocated debt). In addition, Corporate and Other includes specific items attributable to Dominion Energy’s operating segments that are not included$55 0,000,000 in profit measures evaluated by executive management in assessing the segments’ performance or in allocating resources. As discussed in Note 1 in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019, in December 2019, Dominion Energy realigned its segments which resulted in the formation of five primary operating segments. The information for the six months ended June 30, 2019 presented herein has been recast to reflect the current segment presentation.

In the six months ended June 30, 2020, Dominion Energy reported after-tax net expenses of $3.1 billion for specific items in the Corporate and Other segment, with $2.9 billion of net expenses attributable to its operating segments. In the six months ended June 30, 2019, Dominion Energy reported after-tax net expenses of $2.1 billion for specific items in the Corporate and Other segment, with $1.8 billion of net expenses attributable to its operating segments.

~~The net expense for specific items attributable to Dominion Energy’s operating segments in 2020 primarily related to the impact~~principal amount of the ~~following items:~~

•3.40 % Senior Notes due 20 5 1 .

$2.8 billion ($2.2 billion after-tax) of charges associated with the cancellation of the Atlantic Coast Pipeline Project and the related portions of the Supply Header Project, attributable to Gas Transmission & Storage;

•	~~A $751 million ($564 million after-tax) charge primarily related to the planned early retirement of certain Virginia Power electric generation facilities, attributable to Dominion Energy Virginia; and~~

•	~~A $145 million ($115 million after-tax) loss related to investments in nuclear decommissioning trust funds, attributable to:~~

•

~~Contracted Generation ($100 million after-tax) and;~~

•15.1Awareness Letter of Independent Registered Public Accounting Firm.

~~Dominion Energy Virginia ($15 million after-tax).~~

~~The net expense for specific items attributable~~31.1 Principal Executive Officer Certification Pursuant to ~~Dominion Energy’s operating segments in 2019 primarily related to the impact~~Section 302 of the ~~following items:~~Sarbanes-Oxley Act of 2002.

•	~~A $1.0 billion ($756~~ ~~million after-tax) charge for refunds of amounts previously collected from retail electric customers of DESC for the NND Project, attributable to Dominion Energy South Carolina;~~

•	$446 million ($339 million after-tax) of merger and integration-related costs associated with the SCANA Combination, including a $425 million ($317 million after-tax) charge related to a voluntary retirement program, attributable to:

•

~~Dominion Energy Virginia ($145 million after-tax);~~

•31.2Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

~~Gas Transmission & Storage ($39 million after-tax);~~

•32.1Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

~~Gas Distribution ($53 million after-tax);~~

•32.2Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

~~Dominion Energy South Carolina ($64 million after-tax) and;~~

•

~~Contracted Generation ($38 million after-tax).~~

•	~~A $369 million ($275 million after-tax) charge related to the early retirement of certain Virginia Power electric generation facilities, attributable to Dominion Energy Virginia;~~

•	~~$278 million ($209 million after-tax) of charges associated with litigation acquired in the SCANA Combination, attributable to Dominion Energy South Carolina;~~

•	A $198 million tax charge for $264 million of income tax-related regulatory assets acquired in the SCANA Combination for which Dominion Energy committed to forgo recovery, attributable to Dominion Energy South Carolina;

•	~~A $160 million ($119 million after-tax) charge related to Virginia Power’s planned early retirement of certain automated meter reading infrastructure, attributable to Dominion Energy Virginia;~~

•	~~A $135 million ($100 million after-tax) charge related to Virginia Power’s contract termination with a non-utility generator, attributable to Dominion Energy Virginia; and~~

•	A $114 million ($86 million after-tax) charge for property, plant and equipment acquired in the SCANA Combination primarily for which Dominion Energy committed to forego recovery, attributable to Dominion Energy South Carolina; partially offset by

•	~~A $336 million ($251 million after-tax) net gain related to investments in nuclear decommissioning trust funds, attributable to:~~

•

~~Contracted Generation ($222 million after-tax) and;~~

PACIFICORP

15.2Awareness Letter of Independent Registered Public Accounting Firm.

31.3Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.4Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.3Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.4Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

BERKSHIRE HATHAWAY ENERGY AND PACIFICORP

95Mine Safety Disclosures Required by the Dodd-Frank Wall Street Reform and Consumer Protection Act .

MIDAMERICAN ENERGY

15.3Awareness Letter of Independent Registered Public Accounting Firm.

31.5Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.6Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.5Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.6Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

MIDAMERICAN FUNDING

31.7Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.8Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.7Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.8Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

NEVADA POWER

15.4Awareness Letter of Independent Registered Public Accounting Firm.

31.9Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.10Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 .

32.9Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.10Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 .

166

SIERRA PACIFIC

31.11Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.12Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.11Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.12Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

EASTERN ENERGY GAS

31.13P rincipal Executive Officer Certif ication Pursuant to Section 302 of the Sarbanes -Oxley Act of 2002.

31.14Principal Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.13Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.14Principal Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

ALL REGISTRANTS

101•

~~Dominion Energy Virginia ($29 million after-tax); and~~

•	A $113 million ($84 million after-tax) benefit from the revision of future ash pond and landfill closure costs as a result of Virginia legislation enacted in March 2019, attributable to Dominion Energy Virginia.

The following ~~table presents segment~~financial information ~~pertaining to Dominion Energy’s operations:~~

Dominion
Energy
Virginia

Gas
Transmission
& Storage

Gas
Distribution

Dominion
Energy
South
Carolina

Contracted
Generation

Corporate
and Other

Adjustments
& Eliminations

Consolidated
Total

(millions)

Three Months Ended June 30, 2020

Total revenue from external customers

$
1,818

$
528

$
400

$
634

$
238

$
(32
)

$
(1
)

$
3,585

Intersegment revenue

(4
)

49

2

1

5

262

(315
)

—

Total operating revenue

1,814

577

402

635

243

230

(316
)

3,585

Net income (loss) attributable to Dominion Energy

437

184

87

75

21

(1,973
)

—

(1,169
)
Three Months Ended June 30, 2019

Total revenue from external customers

$
1,945

$
664

$
397

$
701

$
249

$
(18
)

$
32

$
3,970

Intersegment revenue

(2
)

91

3

2

4

386

(484
)

—

Total operating revenue

1,943

755

400

703

253

368

(452
)

3,970

Net income (loss) attributable to Dominion Energy

393

177

66

95

13

(690
)

—

54

Six Months Ended June 30, 2020

Total revenue from external customers

$
3,756

$
1,172

$
1,287

$
1,347

$
524

$
(4
)

$
(1
)

$
8,081

Intersegment revenue

(7
)

106

5

2

9

541

(656
)

—

Total operating revenue

3,749

1,278

1,292

1,349

533

537

(657
)

8,081

Net income (loss) attributable to Dominion Energy

866

405

312

169

80

(3,271
)

—

(1,439
)
Six Months Ended June 30, 2019

Total revenue from external customers

$
3,946

$
1,647

$
1,314

$
1,390

$
601

$
(1,070
)

$
—

$
7,828

Intersegment revenue

(6
)

146

7

2

7

663

(819
)

—

Total operating revenue

3,940

1,793

1,321

1,392

608

(407
)

(819
)

7,828

Net income (loss) attributable to Dominion Energy

754

399

271

166

115

(2,331
)

—

(626
)

~~Intersegment sales and transfers for Dominion Energy are based on contractual arrangements and may result in intersegment profit or loss that is eliminated in consolidation.~~

~~Virginia Power~~

~~The Corporate and Other Segment of Virginia Power~~ primarily includes specific items attributable to its operating segment that are not included in profit measures evaluated by executive management in assessing the segment’s performance or in allocating resources. As discussed in Note 1 in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019, in December 2019, Virginia Power realigned its segments which resulted in the formation of one primary operating segment. The information for the six months ended June 30, 2019 presented herein has been recast to reflect the current segment presentation.

In the six months ended June 30, 2020, Virginia Power reported after-tax net expenses of $654 million for specific items in the Corporate and Other segment, all of which was attributable to its operating segment. In the six months ended June 30, 2019, Virginia Power reported after-tax expense of $652 million for specific items in the Corporate and Other segment, with $607 million of net expenses attributable to its operating segment.

The net expense for specific items attributable to Virginia Power’s operating segment in 2020 primarily related to a $751 million ($559 million after-tax) charge related to the planned early retirement of certain electric generation facilities.

~~The net expenses for specific items in 2019 primarily related to the impact of the following items:~~

•	~~A $369 million ($275 million after-tax) charge related to the early retirement of certain electric generation facilities;~~

•	~~A $192 million ($143 million after-tax) charge related to a voluntary retirement program;~~

•	~~A $160 million ($119 million after-tax) charge related to the planned early retirement of certain automated meter reading infrastructure;~~

•	~~A $135 million ($100 million after-tax) charge related to a contract termination with a non-utility generator; and~~

•	~~A $62 million ($46 million after-tax) charge related the abandonment of a project at an electric generating facility; partially offset by~~

•	~~A $113 million ($84 million after-tax) benefit from the revision of future ash pond and landfill closure costs as a result of Virginia legislation enacted in March 2019.~~

~~The following table presents segment information pertaining to Virginia Power’s operations:~~

Dominion
Energy
Virginia

Corporate
and Other

Consolidated
Total

(millions)

Three Months Ended June 30, 2020

Operating revenue

$
1,805

$
—

$
1,805

Net income

435

55

490

Three Months Ended June 30, 2019

Operating revenue

$
1,938

$
—

$
1,938

Net income (loss)

393

(293
)

100

Six Months Ended June 30, 2020

Operating revenue

$
3,735

$
—

$
3,735

Net income (loss)

862

(652
)

210

Six Months Ended June 30, 2019

Operating revenue

$
3,932

$
(29
)

$
3,903

Net income (loss)

751

(631
)

120

~~Dominion Energy Gas~~

~~The Corporate and Other Segment of Dominion Energy Gas~~ primarily includes specific items attributable to Dominion Energy Gas’ operating segment that are not included in profit measures evaluated by executive management in assessing the segment’s performance or in allocating resources and the effect of certain items recorded at Dominion Energy Gas as a result of Dominion Energy’s basis in the net assets contributed. In addition, Corporate and Other includes the net impact of discontinued operations, which are discussed in Note 3. As discussed in Note 1 in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019, in December 2019, Dominion Energy Gas realigned its segments which resulted in the formation of one primary operating segment. The information for six months ended June 30, 2019 presented herein has been recast to reflect the current segment presentation.

In the six months ended June 30, 2020, Dominion Energy Gas reported after-tax net expenses of $365 million for specific items in the Corporate and Other segment, all of which was attributable to its operating segment. In the six months ended June 30, 2019, Dominion Energy Gas reported after-tax net expenses of $44 million for specific items in the Corporate and Other segment, with $43 million of net expenses attributable to its operating segment.

The net expense for specific items attributable to Dominion Energy Gas’ operating segment in 2020 primarily related to a $482 million ($359 million after-tax) charge associated with the Supply Header Project.

The net expense for specific items attributable to Dominion Energy Gas’ operating segment in 2019 primarily related to a $42 million ($31 million after-tax) charge related to a voluntary retirement program.

~~The following table presents segment information pertaining to Dominion Energy Gas’ operations:~~

Gas
Transmission
& Storage

Corporate
and Other

Consolidated
Total

(millions)

Three Months Ended June 30, 2020

Operating revenue

$
510

$
—

$
510

Net income (loss) attributable to Dominion Energy Gas

163

(361
)

(198
)
Three Months Ended June 30, 2019

Operating revenue

$
530

$
—

$
530

Net income from discontinued operations

—

26

26

Net income attributable to Dominion Energy Gas

116

3

119

Six Months Ended June 30, 2020

Operating revenue

$
1,066

$
—

$
1,066

Net income (loss) attributable to Dominion Energy Gas

337

(366
)

(29
)
Six Months Ended June 30, 2019

Operating revenue

$
1,096

$
—

$
1,096

Net income from discontinued operations

—

80

80

Net income attributable to Dominion Energy Gas

254

55

309

~~ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS~~

~~OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

MD&A discusses Dominion Energy’s results of operations and general financial condition and Virginia Power and Dominion Energy Gas’ results of operations. MD&A should be read in conjunction with the Companies’ Consolidated Financial Statements. Virginia Power and Dominion Energy Gas meet the conditions to file under the reduced disclosure format, and therefore have omitted certain sections of MD&A.

~~Contents of MD&A~~

~~MD&A consists of the following information:~~

•	~~Forward-Looking Statements~~

•	~~Accounting Matters – Dominion Energy~~

•	~~Dominion Energy~~

•

~~Results of Operations~~

•

~~Segment Results of Operations~~

•	~~Virginia Power~~

•

~~Results of Operations~~

•	~~Dominion Energy Gas~~

•

~~Results of Operations~~

•	~~Liquidity and Capital Resources – Dominion Energy~~

•	~~Future Issues and Other Matters – Dominion Energy~~

~~Forward-Looking Statements~~

This report contains statements concerning the Companies’ expectations, plans, objectives, future financial performance and other statements that are not historical facts. These statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. In most cases, the reader can identify these forward-looking statements by such words as “anticipate,” “estimate,” “forecast,” “expect,” “believe,” “should,” “could,” “plan,” “may,” “continue,” “target” or other similar words.

~~The Companies make forward-looking statements with full knowledge that risks and uncertainties exist that may cause actual results to differ materially~~ from predicted results. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Additionally, other factors may cause actual results to differ materially from those indicated in any forward-looking statement. These factors include but are not limited to:

•	~~Unusual weather conditions and their effect on energy sales to customers and energy commodity prices;~~

•	Extreme weather events and other natural disasters, including, but not limited to, hurricanes, high winds, severe storms, earthquakes, flooding, climate changes and changes in water temperatures and availability that can cause outages and property damage to facilities;

•	The impact of extraordinary external events, such as the current pandemic health event resulting from COVID-19, and their collateral consequences, including extended disruption of economic activity in our markets;

•	~~Federal, state and local legislative and regulatory developments, including changes in federal and state tax laws and regulations;~~

•	~~Risks of operating businesses in regulated industries that are subject to changing regulatory structures;~~

•	Changes to regulated electric rates collected by Dominion Energy and Virginia Power and regulated gas distribution, transportation and storage rates, including LNG storage, collected by Dominion Energy and Dominion Energy Gas;

•	Changes in rules for RTOs and ISOs in which Dominion Energy and Virginia Power join and/or participate, including changes in rate designs, changes in FERC’s interpretation of market rules and new and evolving capacity models;

•	~~Risks associated with Virginia Power’s membership and participation in PJM, including risks related to obligations created by the default of other participants;~~

•

Risks associated with entities in which Dominion Energy and Dominion Energy Gas share ownership with third parties, including risks that result from lack of sole decision making authority, disputes that may arise between Dominion Energy and Dominion Energy Gas and third party participants and difficulties in exiting these arrangements;

•	~~Changes in future levels of domestic and international natural gas production, supply or consumption;~~

•	~~Fluctuations in future volumes of LNG imports or exports from the U.S. and other countries worldwide or demand for, purchases of, and prices related to natural gas or LNG;~~

•	~~Timing and receipt of regulatory approvals necessary for planned construction or growth projects and compliance with conditions associated with such regulatory approvals;~~

•	The inability to complete planned construction, conversion or growth projects at all, or with the outcomes or within the terms and time frames initially anticipated, including as a result of increased public involvement, intervention or litigation in such projects;

•	Changes to federal, state and local environmental laws and regulations, including those related to climate change, the tightening of emission or discharge limits for GHGs and other substances, more extensive permitting requirements and the regulation of additional substances;

•	~~Cost of environmental compliance, including those costs related to climate change;~~

•	~~Changes in implementation and enforcement practices of regulators relating to environmental standards and litigation exposure for remedial activities;~~

•	~~Difficulty in anticipating mitigation requirements associated with environmental and other regulatory approvals or related appeals;~~

•	~~Unplanned outages at facilities in which the Companies have an ownership interest;~~

•	The impact of operational hazards, including adverse developments with respect to pipeline and plant safety or integrity, equipment loss, malfunction or failure, operator error, and other catastrophic events;

•	Risks associated with the operation of nuclear facilities, including costs associated with the disposal of spent nuclear fuel, decommissioning, plant maintenance and changes in existing regulations governing such facilities;

•	~~Changes in operating, maintenance and construction costs;~~

•	~~Domestic terrorism and other threats to the Companies’ physical and intangible assets, as well as threats to cybersecurity;~~

•

Additional competition in industries in which the Companies operate, including in electric markets in which Dominion Energy’s merchant generation facilities operate and potential competition from the development and deployment of alternative energy sources, such as self-generation and distributed generation technologies, and availability of market alternatives to large commercial and industrial customers;

•	~~Competition in the development, construction and ownership of certain electric transmission facilities in Dominion Energy and Virginia Power’s service territory in connection with Order 1000;~~

•	~~Changes in technology, particularly with respect to new, developing or alternative sources of generation and smart grid technologies;~~

•

Changes in demand for the Companies’ services, including industrial, commercial and residential growth or decline in the Companies’ service areas, changes in supplies of natural gas delivered to Dominion Energy and Dominion Energy Gas’ pipeline systems, failure to maintain or replace customer contracts on favorable terms, changes in customer growth or usage patterns, including as a result of energy conservation programs, the availability of energy efficient devices and the use of distributed generation methods;

•	~~Receipt of approvals for, and timing of, closing dates for acquisitions and divestitures;~~

•	~~Impacts of acquisitions, divestitures, transfers of assets to joint ventures and retirements of assets based on asset portfolio reviews;~~

•	The expected timing and likelihood of completion of the proposed transaction with BHE, including the ability to obtain the requisite regulatory approvals and the terms and conditions of such regulatory approvals;

•	~~Adverse outcomes in litigation matters or regulatory proceedings, including matters acquired in the SCANA Combination;~~

•	~~Counterparty credit and performance risk;~~

•	~~Fluctuations in the value of investments held in nuclear decommissioning trusts by Dominion Energy and Virginia Power and in benefit plan trusts by Dominion Energy and Dominion Energy Gas;~~

•	~~Fluctuations in energy-related commodity prices and the effect these could have on Dominion Energy’s earnings and the Companies’ liquidity position and the underlying value of their assets;~~

•	~~Fluctuations in interest rates or foreign currency exchange rates;~~

•	~~Changes in rating agency requirements or credit ratings and their effect on availability and cost of capital;~~

•	~~Global capital market conditions, including the availability of credit and the ability to obtain financing on reasonable terms;~~

•	~~Political and economic conditions, including inflation and deflation;~~

•	~~Employee workforce factors including collective bargaining agreements and labor negotiations with union employees; and~~

•	~~Changes in financial or regulatory accounting principles or policies imposed by governing bodies.~~

Additionally, other risks that could cause actual results to differ from predicted results are set forth in Part I. Item 1A. Risk Factors in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019 and Part II. Item 1A. Risk Factors in the Companies’each respective Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, ~~2020.~~

~~The Companies’ forward-looking statements are based on beliefs~~2021, is formatted in iXBRL (Inline eXtensible Business Reporting Language) and ~~assumptions using information available at~~included herein: (i) the ~~time~~Consolidated Balance Sheets, (ii) the ~~statements are made. The Companies caution~~Consolidated Statements of Operations, (iii) the ~~reader not~~Consolidated Statements of Comprehensive Income, (iv) the Consolidated Statements of Changes in Equity, (v) the Consolidated Statements of Cash Flows, and (vi) the Notes to place undue reliance on their forward-looking statements because the assumptions, beliefs, expectations and projections about future events may, and often do, differ materially from actual results. The Companies undertake no obligation to update any forward-looking statement to reflect developments occurring after the statement is made.

~~Accounting Matters~~

~~Critical Accounting Policies and Estimates~~

As of June 30, 2020, there have been no significant changes with regard to the critical accounting policies and estimates disclosed in MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019. The policies disclosed included the accounting for regulated operations, AROs, income taxes, derivative contracts and financial instruments at fair value, impairment testing of goodwill, long-lived assets and equity method investments and employee benefit plans.

~~Dominion Energy~~

~~Results of Operations~~

~~Presented below is a summary of Dominion Energy’s consolidated results:~~

2020

2019

$ Change

(millions, except EPS)

Second Quarter

Net income (loss) attributable to Dominion Energy

$
(1,169
)

$
54

$
(1,223
)
Diluted EPS

(1.41
)

0.05

(1.46
)
Year-To-Date

Net loss attributable to Dominion Energy

$
(1,439
)

$
(626
)

$
(813
)
Diluted EPS

(1.75
)

(0.78
)

(0.97
)

~~Overview~~

~~Second Quarter 2020 vs. 2019~~

Net income attributable to Dominion Energy decreased $1.2 billion, primarily due to charges associated with the cancellation of the Atlantic Coast Pipeline Project and related portions of the Supply Header Project partially offset by an increase in net investment earnings on nuclear decommissioning trust funds, the absence of charges related to a voluntary retirement program, the absence of a charge for Virginia Power’s contract termination with a non-utility generator, the absence of a charge for litigation acquired in the SCANA Combination and the absence of a charge for the abandonment of a project at a Virginia Power electric generating facility.

~~Year-To-Date 2020 vs. 2019~~

Net loss attributable to Dominion Energy increased $813 million, primarily due to charges associated with the cancellation of the Atlantic Coast Pipeline Project and related portions of the Supply Header Project, a decrease in net investment earnings on nuclear decommissioning trust funds and an increase in charges associated with the planned early retirements of certain electric generation facilities in Virginia. These increases in net loss were partially offset by the absence of charges for refunds of amounts previously

collected from retail electric customers of DESC for the NND Project and for certain regulatory assets and property, plant and equipment acquired in the SCANA Combination for which Dominion Energy committed to forgo recovery, a decrease in charges associated with litigation acquired in the SCANA Combination, the absence of charges for the planned early retirement of certain Virginia Power automated meter reading infrastructure and the absence of charges related to a voluntary retirement program.

~~Analysis of Consolidated Operations~~

~~Presented below are selected amounts related to Dominion Energy’s results of operations:~~

Second Quarter

Year-To-Date

2020

2019

$ Change

2020

2019

$ Change

(millions)

Operating revenue

$
3,585

$
3,970

$
(385
)

$
8,081

$
7,828

$
253

Electric fuel and other energy-related purchases

505

718

(213
)

1,173

1,509

(336
)
Purchased electric capacity

11

24

(13
)

13

63

(50
)
Purchased gas

74

227

(153
)

501

957

(456
)
Net revenue

2,995

3,001

(6
)

6,394

5,299

1,095

Other operations and maintenance

995

1,283

(288
)

2,038

2,285

(247
)
Depreciation, depletion and amortization

673

661

12

1,346

1,312

34

Other taxes

256

284

(28
)

540

576

(36
)
Impairment of assets and other charges

531

312

219

1,299

1,147

152

Other income

502

53

449

50

400

(350
)
Earnings (loss) from equity method investees

(2,281
)

39

(2,320
)

(2,228
)

80

(2,308
)
Interest and related charges

449

452

(3
)

939

921

18

Income tax expense (benefit)

(556
)

43

(599
)

(575
)

157

(732
)
Noncontrolling interests

37

4

33

68

7

61

~~An analysis of Dominion Energy’s results of operations follows:~~

~~Second Quarter 2020 vs. 2019~~

~~Net revenue~~ ~~remained substantially consistent, primarily reflecting:~~

•	~~A $60 million decrease in sales to electric utility retail customers from a decrease in cooling degree days;~~

•	~~A $44 million decrease in sales to electric utility retail customers associated with usage factors impacted by COVID-19;~~

•	~~A $20 million decrease due to unfavorable pricing at Millstone, including the effects of the Millstone 2019 power purchase agreements; and~~

•	~~A $14 million net unrealized loss on freestanding commodity derivatives.~~

~~These decreases were substantially offset by:~~

•	~~A $98 million increase from Virginia Power rate adjustment clauses;~~

•	~~The absence of a $24 million loss as a result of the contribution of SEMI to Wrangler; and~~

•	~~A $16 million decrease in Virginia Power electric capacity expense related to the annual PJM capacity performance market effective June 2019 ($21 million)~~ ~~partially offset by the expiration of various contracts ($5 million).~~

~~Other operations and maintenance~~ ~~decreased 22%, primarily reflecting:~~

•	~~The absence of a charge related to a~~ ~~voluntary retirement program ($288 million);~~

•	~~A $38 million decrease in salaries, wages and benefits; and~~

•	~~A $30 million decrease in outage costs; partially offset by~~

•	~~A $22 million increase in allowance for credit risk on customer accounts related to the effects of COVID-19;~~

•	~~A $16 million increase in certain Virginia Power expenditures, which are primarily recovered through state and FERC rates and do not impact net income; and~~

•	~~A $14 million increase in outside services and safety equipment related to the effects of COVID-19.~~

~~Depreciation, depletion and amortization~~ increased 2%, primarily due to various projects being placed into service ($32 million), partially offset by the absence of depreciation from certain electric generation facilities that have been committed to be retired early ($16 million).

~~Other taxes~~ ~~decreased 10%, primarily due to the absence of a charge related to a voluntary retirement program ($23 million).~~

~~Impairment of assets and other charges~~ ~~increased 70%, primarily due to:~~

•	~~A $482 million charge associated with the probable abandonment of portions of the Supply Header Project related to the Atlantic Coast Pipeline Project; and~~

•	~~An increase in dismantling costs associated with certain Virginia Power electric generation facilities ($30 million); partially offset by~~

•	~~The absence of a $135 million charge related to Virginia Power’s contract termination with a non-utility generator;~~

•	~~The absence of a $100 million charge associated with litigation acquired in the SCANA Combination; and~~

•	~~The absence of a $62 million charge related to the abandonment of a project at a Virginia Power electric generating facility.~~

~~Other income~~ increased $449 million, primarily due to an increase in net investment earnings on nuclear decommissioning trust funds ($311 million) and the absence of a charge related to a voluntary retirement program ($112 million).

~~Earnings (loss) from equity method investees~~ ~~decreased $2.3 billion, primarily due to charges associated with the cancellation of the Atlantic Coast Pipeline Project.~~

~~Interest and related charges~~ ~~remained substantially consistent,~~ primarily reflecting lower interest expense from early redemptions of certain securities in 2019 and 2020 ($37 million) and a reduction in commercial paper borrowings ($13 million), substantially offset by increased borrowings in response to COVID-19 ($24 million) and increases ~~for unrealized losses associated with freestanding derivatives ($23 million).~~

~~Income tax expense~~ decreased $599 million, primarily due to a larger pre-tax loss ($683 million), partially offset by charges associated with the cancellation of the Atlantic Coast Pipeline Project and related Supply Header Project ($81 million).

~~Noncontrolling interests~~ ~~increased $33 million, primarily~~ ~~due to the sale of a 25% noncontrolling limited partnership interest in Cove Point to Brookfield in December 2019.~~

~~Year-To-Date 2020 vs. 2019~~

~~Net revenue~~ ~~increased 21%, primarily reflecting:~~

•	~~The absence of a~~ ~~$1.0 billion charge for refunds of amounts previously collected from retail electric customers of DESC for the NND Project;~~

•	~~A $226 million increase from Virginia Power rate adjustment clauses; and~~

•

~~A $48 million decrease in Virginia Power electric capacity expense related to the annual PJM capacity performance market effective June 2019 ($51 million) and a~~ ~~contract termination with a non-utility generator ($13 million) partially offset by the expiration of various contracts ($16 million).~~

~~These increases were partially offset by:~~

•	An $83 million decrease in sales to electric utility retail customers from a decrease in cooling degree days during the cooling season ($60 million) and a net decrease in heating degree days during the heating season ($23 million);

•	~~A $61 million decrease due to unfavorable pricing at Millstone, including the effects of the Millstone 2019 power purchase agreements;~~

•	~~A $46 million decrease in sales to electric utility retail customers associated with usage factors impacted by COVID-19;~~

•	~~A $22 million decrease as a result of the contribution of SEMI to Wrangler; and~~

•	~~A $20 million decrease in services performed for Atlantic Coast Pipeline.~~

~~Other operations and maintenance~~ ~~decreased 11%, primarily reflecting:~~

•	~~The absence of a charge related to a~~ ~~voluntary retirement program ($288 million);~~

•	~~A decrease in merger and integration-related costs associated with the SCANA Combination ($96 million);~~

•	~~A $56 million decrease in salaries, wages and benefits;~~

•	~~A $40 million decrease in outage costs; and~~

•	~~A $20 million decrease in services performed for Atlantic Coast Pipeline; partially offset by~~

•	~~The absence of a benefit from the revision of future ash pond and landfill closure costs as a result of Virginia legislation enacted in March 2019 ($113 million);~~

•	~~A $55 million increase in certain Virginia Power expenditures, which are primarily recovered through state and FERC rates and do not impact net income; and~~

•	~~A $22 million increase in allowance for credit risk on customer accounts related to the effects of COVID-19.~~

~~Depreciation, depletion and amortization~~ increased 3%, primarily due to various projects being placed into service ($59 million) partially offset by the absence of depreciation from certain electric generation facilities that were, or have been committed to be retired early ($25 million) and a decrease reflecting the expected approval of the nuclear plant life extensions from the NRC ($16 million).

~~Impairment of assets and other charges~~ ~~increased~~ ~~13%, primarily due to:~~

•	~~A $482 million charge associated with the probable abandonment of portions of the Supply Header Project related to the Atlantic Coast Pipeline Project;~~

•	~~An increase in charges associated with the planned early retirements of certain electric generation facilities in Virginia ($379 million); and~~

•	~~An increase in dismantling costs associated with certain Virginia Power electric generation facilities ($30 million); partially offset by~~

•	~~The absence of charges associated with litigation acquired in the SCANA Combination ($278 million);~~

•	~~The absence of a $160 million charge related to Virginia Power’s planned early retirement of certain automated meter reading infrastructure;~~

•	~~The absence of a $135 million charge related to Virginia Power’s contract termination with a non-utility generator;~~

•	~~A decrease in charges for~~ ~~property, plant and equipment acquired in the SCANA Combination for which Dominion Energy committed to forgo recovery ($103 million); and~~

•	~~The absence of a $62 million charge related to the abandonment of a project at a Virginia Power electric generating facility.~~

~~Other income~~ ~~decreased 88%, primarily reflecting~~ ~~net investment losses in 2020 compared to net investment gains in 2019~~ on nuclear decommissioning trust funds ($481 million) and charges associated with litigation acquired in the SCANA Combination ($25 million), partially offset by the absence of a charge related to a voluntary retirement program ($112 million) and an increase in non-service components of pension and other postretirement employee benefit plan credits ($26 million).

~~Earnings (loss) from equity method investees~~ ~~decreased $2.3 billion, primarily due to charges associated with the cancellation of the Atlantic Coast Pipeline Project.~~

~~Interest and related charges~~ ~~increased 2%, primarily related to increases~~ for unrealized losses associated with freestanding derivatives ($81 million), charges associated with the early redemption of certain securities in the first quarter of 2020 ($25 million) and increased borrowings in response to COVID-19 ($24 million), partially offset by lower interest expense from early redemptions of certain securities in 2019 and 2020 ($94 million) and reductions in commercial paper borrowings ($17 million).

~~Income tax expense~~ ~~decreased $732 million, primarily due to a larger pre-tax loss ($623 million) and the~~ ~~absence of a charge for certain income tax-related regulatory assets acquired in the SCANA Combination for which Dominion Energy committed to forgo~~

~~recovery ($198 million), partially offset by charges associated with the cancellation of the Atlantic Coast Pipeline Project and related Supply Header Project ($81 million).~~

~~Noncontrolling interests~~ ~~increased~~ ~~$61 million, primarily due to the sale of a 25% noncontrolling limited partnership interest in Cove Point to Brookfield in December 2019.~~

~~Segment Results of Operations~~

Segment results include the impact of intersegment revenues and expenses, which may result in intersegment profit and loss. In December 2019, Dominion Energy realigned its segments which resulted in the formation of five primary operating segments. The historical information presented herein has been recast to reflect the current segment presentation. Presented below is a summary of contributions by Dominion Energy’s operating segments to net income (loss) attributable to Dominion Energy:

Net Income (Loss) Attributable to
Dominion Energy

Diluted EPS

2020

2019

$ Change

2020

2019

$ Change

(millions, except EPS)

Second Quarter

Dominion Energy Virginia

$
437

$
393

$
44

$
0.52

$
0.49

$
0.03

Gas Transmission & Storage

184

177

7

0.22

0.22

(0.00
)
Gas Distribution

87

66

21

0.10

0.08

0.02

Dominion Energy South Carolina

75

95

(20
)

0.09

0.12

(0.03
)
Contracted Generation

21

13

8

0.03

0.02

0.01

Corporate and Other

(1,973
)

(690
)

(1,283
)

(2.37
)

(0.88
)

(1.49
)
Consolidated

$
(1,169
)

$
54

$
(1,223
)

$
(1.41
)

$
0.05

$
(1.46
)

Year-To-Date

Dominion Energy Virginia

$
866

$
754

$
112

$
1.03

$
0.95

$
0.08

Gas Transmission & Storage

405

399

6

0.48

0.50

(0.02
)
Gas Distribution

312

271

41

0.37

0.34

0.03

Dominion Energy South Carolina

169

166

3

0.20

0.21

(0.01
)
Contracted Generation

80

115

(35
)

0.10

0.14

(0.04
)
Corporate and Other

(3,271
)

(2,331
)

(940
)

(3.93
)

(2.92
)

(1.01
)
Consolidated

$
(1,439
)

$
(626
)

$
(813
)

$
(1.75
)

$
(0.78
)

$
(0.97
)

~~Dominion Energy Virginia~~

~~Presented below are selected operating statistics related to Dominion Energy Virginia’s operations:~~

Second Quarter

Year-To-Date

2020

2019

% Change

2020

2019

% Change

Electricity delivered (million MWh)

18.7

20.6

(9
)%

39.5

42.4

(7
)%
Electricity supplied (million MWh):

Utility

20.1

20.9

(4
)

42.5

42.8

(1
)
Degree days (electric distribution and utility
service area):

Cooling

438

644

(32
)

452

649

(30
)
Heating

371

150

147

1,889

2,042

(7
)
Average electric distribution customer accounts
(thousands)

2,656

2,622

1

2,652

2,620

1

~~Presented below, on an after-tax basis, are the key factors impacting Dominion Energy Virginia’s net income contribution:~~

Second Quarter
2020 vs. 2019
Increase (Decrease)

Year-To-Date
2020 vs. 2019
Increase (Decrease)

Amount

EPS

Amount

EPS

(millions, except EPS)

Regulated electric sales:

Weather

$
(22
)

$
(0.03
)

$
(48
)

$
(0.06
)
Other

(15
)

(0.02
)

(11
)

(0.01
)
Rate adjustment clause equity return

32

0.04

55

0.07

Electric capacity

9

0.01

33

0.04

Outages

14

0.02

22

0.02

Salaries, wages and benefits

15

0.02

26

0.03

Depreciation and amortization

9

0.01

21

0.02

Renewable energy investment tax credits

(10
)

(0.01
)

19

0.02

Other

12

0.01

(5
)

—

Share dilution

—

(0.02
)

—

(0.05
)
Change in net income contribution

$
44

$
0.03

$
112

$
0.08

~~Gas Transmission & Storage~~

~~Presented below are selected operating statistics related to Gas Transmission & Storage’s operations:~~

Second Quarter

Year-To-Date

2020

2019

% Change

2020

2019

% Change

Average retail energy marketing customer
accounts⁽¹⁾ (thousands)

400

790

(49
)%

399

792

(50
)%

~~(1)~~

~~Excludes accounts held by equity method investees.~~

~~Presented below, on an after-tax basis, are the key factors impacting Gas Transmission & Storage’s net income contribution:~~

Second Quarter
2020 vs. 2019
Increase (Decrease)

Year-To-Date
2020 vs. 2019
Increase (Decrease)

Amount

EPS

Amount

EPS

(millions, except EPS)

Noncontrolling interest

$
(24
)

$
(0.03
)

$
(44
)

$
(0.06
)
Contribution to Wrangler

6

0.01

(11
)

(0.01
)
Atlantic Coast Pipeline equity earnings

(4
)

(0.01
)

4

0.01

Salaries, wages and benefits

6

0.01

9

0.01

Interest expense, net

23

0.03

49

0.06

Other

—

—

(1
)

—

Share dilution

—

(0.01
)

—

(0.03
)
Change in net income contribution

$
7

$
0.00

$
6

$
(0.02
)

~~Gas Distribution~~

~~Presented below are selected operating statistics related to Gas Distribution’s operations:~~

Second Quarter

Year-To-Date

2020

2019

% Change

2020

2019

% Change

Gas distribution throughput (bcf):

Sales

24

24

—
%

104

112

(7
%)
Transportation

190

161

18

440

401

10

Heating degree days (gas distribution service area):

North Carolina

314

155

103

1,648

1,811

(9
)
Ohio and West Virginia

804

526

53

3,246

3,441

(6
)
Utah, Wyoming and Idaho

547

634

(14
)

2,879

3,204

(10
)
Average gas distribution customer accounts
(thousands):

Sales

1,885

1,846

2

1,888

1,847

2

Transportation

1,130

1,116

1

1,122

1,112

1

~~Presented below, on an after-tax basis, are the key factors impacting Gas Distribution’s net income contribution:~~

Second Quarter
2020 vs. 2019
Increase (Decrease)

Year-To-Date
2020 vs. 2019
Increase (Decrease)

Amount

EPS

Amount

EPS

(millions, except EPS)

Regulated gas sales:

Weather

$
3

$
—

$
(2
)

$
—

Other

1

—

12

0.01

Salaries, wages and benefits

8

0.01

12

0.02

Interest expense, net

5

0.01

11

0.01

Other

4

—

8

0.01

Share dilution

—

—

—

(0.02
)
Change in net income contribution

$
21

$
0.02

$
41

$
0.03

~~Dominion Energy South Carolina~~

~~Presented below are selected operating statistics related to Dominion Energy South Carolina’s operations:~~

Second Quarter

Year-To-Date

2020

2019

% Change

2020

2019

% Change

Electricity delivered (million MWh)

5.2

5.8

(10
%)

10.3

10.9

(6
%)
Electricity supplied (million MWh)

5.4

6.2

(13
)

10.7

11.4

(6
)
Degree days (electric distribution service areas):

Cooling

171

268

(36
)

176

268

(34
)
Heating

32

38

(16
)

610

698

(13
)
Average electric distribution customer accounts
(thousands)

750

738

2

748

736

2

Gas distribution throughput (bcf):

Sales

14

15

(7
)

33

33

—

Average gas distribution customer accounts
(thousands)

397

385

3

396

383

3

~~Presented below, on an after-tax basis, are the key factors impacting Dominion Energy South Carolina’s net income contribution:~~

Second Quarter
2020 vs. 2019
Increase (Decrease)

Year-To-Date
2020 vs. 2019
Increase (Decrease)

Amount

EPS

Amount

EPS

(millions, except EPS)

Regulated electric sales:

Weather

$
(23
)

$
(0.03
)

$
(14
)

$
(0.02
)
Other

(4
)

—

1

—

Regulated gas sales

2

—

6

0.01

Regulatory rider equity return

(4
)

—

(4
)

(0.01
)
Interest expense, net

2

—

10

0.01

Other

7

0.01

4

0.01

Share dilution

—

(0.01
)

—

(0.01
)
Change in net income contribution

$
(20
)

$
(0.03
)

$
3

$
(0.01
)

~~Contracted Generation~~

~~Presented below are selected operating statistics related to Contracted Generation’s operations:~~

Second Quarter

Year-To-Date

2020

2019

% Change

2020

2019

% Change

Electricity supplied (million MWh)

4.5

4.4

2
%

9.8

9.6

2
%

~~Presented below, on an after-tax basis, are the key factors impacting Contracted Generation’s net income contribution:~~

Second Quarter
2020 vs. 2019
Increase (Decrease)

Year-To-Date
2020 vs. 2019
Increase (Decrease)

Amount

EPS

Amount

EPS

(millions, except EPS)

Margin

$
(6
)

$
(0.01
)

$
(50
)

$
(0.06
)
Planned outage costs

8

0.01

8

0.01

Renewable energy investment tax credits

7

0.01

7

0.01

Other

(1
)

—

—

—

Share dilution

—

—

—

—

Change in net income contribution

$
8

$
0.01

$
(35
)

$
(0.04
)

~~Corporate and Other~~

~~Presented below are the Corporate and Other segment’s after-tax results:~~

Second Quarter

Year-To-Date

2020

2019

$ Change

2020

2019

$ Change

(millions, except EPS)

Specific items attributable to operating segments

$
(1,906
)

$
(482
)

$
(1,424
)

$
(2,937
)

$
(1,817
)

$
(1,120
)
Specific items attributable to Corporate and Other
segment

31

(83
)

114

(139
)

(301
)

162

Total specific items

(1,875
)

(565
)

(1,310
)

(3,076
)

(2,118
)

(958
)
Other corporate operations⁽¹⁾

(98
)

(125
)

27

(195
)

(213
)

18

Total net income (expense)

$
(1,973
)

$
(690
)

$
(1,283
)

$
(3,271
)

$
(2,331
)

$
(940
)
EPS impact

$
(2.37
)

$
(0.88
)

$
(1.49
)

$
(3.93
)

$
(2.92
)

$
(1.01
)

~~(1)~~

~~Primarily consists of net interest expense.~~

~~Total Specific Items~~

Corporate and Other includes specific items attributable to Dominion Energy’s primary operating segments that are not included in profit measures evaluated by executive management in assessing the segments' performance or in allocating resources. See Note 21 to the Consolidated Financial Statements, tagged in ~~this report for discussion of these items~~summary and detail.

104Cover Page Interactive Data File formatted in ~~more detail. Corporate~~iXBRL (Inline eXtensible Business Reporting Language) and ~~Other also includes items attributable to the Corporate and Other segment.~~

~~Virginia Power~~

~~Results of Operations~~

~~Presented below is a summary of Virginia Power’s consolidated results:~~

Second Quarter

Year-To-Date

2020

2019

$ Change

2020

2019

$ Change

(millions)

Net income

$
490

$
100

$
390

$
210

$
120

$
90

~~Overview~~

~~Second Quarter 2020 vs. 2019~~

Net income increased $390 million, primarily due to the absence of charges related to a voluntary retirement program, a contract termination with a non-utility generator and the abandonment of a project at an electric generating facility.

~~Year-To-Date 2020 vs. 2019~~

Net income increased $90 million, primarily due to the absence of charges related to the planned early retirement of certain automated meter reading infrastructure, a voluntary retirement program and a contract termination with a non-utility generator. These increases were partially offset by an increase in charges related to the planned early retirements of certain electric generation facilities and the absence of a revision of future ash pond and landfill closure costs as a result of Virginia legislation enacted in March 2019.

~~Analysis of Consolidated Operations~~

~~Presented below are selected amounts related to Virginia Power’s results of operations:~~

Second Quarter

Year-To-Date

2020

2019

$ Change

2020

2019

$ Change

(millions)

Operating revenue

$
1,805

$
1,938

$
(133
)

$
3,735

$
3,903

$
(168
)
Electric fuel and other energy-related purchases

366

536

(170
)

858

1,132

(274
)
Purchased (excess) electric capacity

(8
)

13

(21
)

(17
)

46

(63
)
Net revenue

1,447

1,389

58

2,894

2,725

169

Other operations and maintenance

376

565

(189
)

794

844

(50
)
Depreciation and amortization

307

299

8

618

603

15

Other taxes

85

90

(5
)

172

175

(3
)
Impairment of assets and other charges

44

197

(153
)

808

743

65

Other income

52

16

36

—

53

(53
)
Interest and related charges

137

135

2

263

270

(7
)
Income tax expense

60

19

41

29

23

6

~~An analysis of Virginia Power’s results of operations follows:~~

~~Second Quarter 2020 vs. 2019~~

~~Net revenue~~ ~~increased 4%, primarily reflecting:~~

•	~~A $98 million increase from rate adjustment clauses; and~~

•	A $16 million decrease in electric capacity expense related to the annual PJM capacity performance market effective June 2019 ($21 million), partially offset by the expiration of various contracts ($5 million); partially offset by

•	~~A $30 million decrease in sales to retail customers from a decrease in cooling degree days; and~~

•	~~A $24 million decrease in sales to retail customers associated with usage factors impacted by COVID-19.~~

~~Other operations and maintenance~~ ~~decreased 33%~~, primarily reflecting the absence of a charge related to a voluntary retirement program ($186 million), a decrease in salaries, wages and benefits ($17 million) and a decrease in planned outage costs ($19 million). These decreases were partially offset by ~~an increase in certain expenses which are primarily recovered~~ ~~through state and FERC rates and do not impact net income ($16 million) and an increase in allowance for credit risk on customer accounts related to COVID-19 ($13 million).~~

~~Depreciation and amortization~~ ~~increased 3%, primarily~~ due to various projects being placed into service ($28 million), partially offset by the absence of depreciation from certain electric generation facilities that have been committed to be retired early ($16 million) and a decrease reflecting the expected approval of the nuclear plant life extensions from the NRC ($8 million).

~~Impairment of assets and other charges~~ decreased 78%, primarily due to the absence of charges related to a contract termination with a non-utility generator ($135 million) and the abandonment of a project at an electric generating facility ($62 million), partially offset by an increase in dismantling costs associated with certain electric generation facilities ($30 million) and the write-off of the portion of a regulatory asset no longer probable of recovery as a result of the enactment of the VCEA ($16 million).

~~Other income~~ ~~increased $36 million, primarily~~ ~~reflecting an increase in net investment earnings on nuclear decommissioning trust funds.~~

~~Income tax expense~~ ~~increased $41 million, primarily due to higher pre-tax income ($80 million), partially offset by higher investment tax credits ($39 million).~~

~~Year-To-Date 2020 vs. 2019~~

~~Net revenue~~ ~~increased 6%, primarily reflecting:~~

•	~~A $226 million increase from rate adjustment clauses; and~~

•

A $48 million decrease in electric capacity expense related to the annual PJM capacity performance market effective June 2019 ($51 million) and a contract termination with a non-utility generator ($13 million) partially offset by the expiration of various contracts ($16 million); partially offset by

•	A $65 million decrease in sales to retail customers from a decrease in cooling degree days during the cooling season ($30 million) and a decrease in heating degree days during the heating season ($35 million); and

•	~~A $24 million decrease in sales to electric retail customers associated with usage factors impacted by COVID-19.~~

~~Other operations and maintenance~~ ~~decreased 6%~~, primarily reflecting the absence of a charge related to a voluntary retirement program ($186 million), a decrease in salaries, wages and benefits ($34 million) and a decrease in planned outage costs ($29 million). These decreases were partially offset by the absence of a benefit from the revision of future ash pond and landfill closure costs as a result of Virginia legislation enacted in March 2019 ($113 million), an increase in certain expenses which are primarily recovered through state and FERC rates and do not impact net income ($55 million) and ~~an increase in allowance for credit risk on customer accounts related to COVID-19 ($13 million)~~.

~~Depreciation and amortization~~ ~~increased 2%, primarily~~ due to various projects being placed into service ($52 million), partially offset by the absence of depreciation from certain electric generation facilities that were, or have committed to be, retired early ($25 million) and a decrease reflecting the expected approval of the nuclear plant life extensions from the NRC ($16 million).

~~Impairment of assets and other charges~~ ~~increased 9%, primarily due to:~~

•	An ~~increase~~ ~~in charges associated with the planned early retirements of certain electric generation facilities ($379 million); and~~

•	An ~~increase in dismantling costs associated with certain electric generation facilities ($30 million);~~ ~~partially offset by~~

•	~~The absence of a charge related to the planned early retirement of certain automated meter reading infrastructure ($160 million);~~

•	~~The absence of a $135 million charge related to contract termination with a non-utility generator; and~~

•	~~The absence of a $62 million charge related to the abandonment of a project at an electric generating facility.~~

~~Other income~~ ~~decreased $53 million, primarily reflecting~~ ~~net investment losses in 2020 compared to net investment gains in 2019 on nuclear decommissioning trust funds.~~

~~Income tax expense~~ ~~increased 26%, primarily due to higher pre-tax income ($25 million), partially offset by higher investment tax credits ($19 million).~~

~~Dominion Energy Gas~~

~~Results of Operations~~

~~Presented below is a summary of Dominion Energy Gas’ consolidated results:~~

Second Quarter

Year-To-Date

2020

2019

$ Change

2020

2019

$ Change

(millions)

Net income (loss) attributable to Dominion Energy Gas

$
(198
)

$
119

$
(317
)

$
(29
)

$
309

$
(338
)

~~Overview~~

~~Second Quarter 2020 vs. 2019~~

Net income attributable to Dominion Energy Gas decreased $317 million, primarily due to a charge associated with the probable abandonment of portions of the Supply Header Project related to the Atlantic Coast Pipeline Project and the absence of net income from discontinued operations related to the Dominion Energy Gas Restructuring, partially offset by the absence of a charge related to a voluntary retirement program and a decrease in interest and related charges from lower outstanding debt balances.

~~Year-To-Date 2020 vs. 2019~~

Net income attributable to Dominion Energy Gas decreased $338 million, primarily due to a charge associated with the probable abandonment of portions of the Supply Header Project related to the Atlantic Coast Pipeline Project and the absence of net income from discontinued operations related to the Dominion Energy Gas Restructuring, partially offset by the absence of a charge related to a voluntary retirement program and a decrease in interest and related charges from lower outstanding debt balances.

~~Analysis of Consolidated Operations~~

~~Presented below are selected amounts related to Dominion Energy Gas’ results of operations:~~

Second Quarter

Year-To-Date

2020

2019

$ Change

2020

2019

$ Change

(millions)

Operating revenue

$
510

$
530

$
(20
)

$
1,066

$
1,096

$
(30
)
Purchased gas

—

(3
)

3

8

9

(1
)
Other energy-related purchases

1

1

—

1

1

—

Net revenue

509

532

(23
)

1,057

1,086

(29
)
Other operations and maintenance

150

210

(60
)

315

386

(71
)
Depreciation and amortization

94

92

2

187

182

5

Other taxes

35

38

(3
)

77

78

(1
)
Impairment of assets and other charges

482

13

469

482

13

469

Earnings from equity method investees

8

9

(1
)

23

22

1

Other income

46

44

2

95

85

10

Interest and related charges

50

86

(36
)

108

173

(65
)
Income tax expense (benefit)

(82
)

23

(105
)

(30
)

66

(96
)
Net income from discontinued operations

—

26

(26
)

—

80

(80
)
Noncontrolling interests

32

30

2

65

66

(1
)

~~An analysis of Dominion Energy Gas’ results of operations follows:~~

~~Second Quarter 2020 vs. 2019~~

~~Net revenue~~ ~~decreased 4%, primarily reflecting:~~

•	~~A $9 million decrease in services performed for Atlantic Coast Pipeline,~~

•	~~A $6 million decrease in services provided to affiliates; and~~

•	~~A $5 million decrease due to DETI contract changes.~~

~~Other operations and maintenance~~ ~~decreased 29%, primarily reflecting:~~

•	~~A $39 million decrease due to the absence of a charge related to a voluntary retirement program; and~~

•	~~A $9 million decrease in services performed for Atlantic Coast Pipeline.~~

~~Impairment of assets and other charges~~ increased $469 million, due to a $482 million charge associated with the probable abandonment of portions of the Supply Header Project related to the Atlantic Coast Pipeline Project, partially offset by the absence of a $13 million charge related to the abandonment of the Sweden Valley project.

~~Interest and related charges~~ ~~decreased 42%,~~primarily due to the absence of interest expense from Cove Point’s term loan borrowings ($32 million), partially offset by interest expense on Dominion Energy Gas’ November 2019 senior note issuance ($8 million).

~~Income tax expense~~ ~~decreased $105 million, primarily due to lower pre-tax income.~~

~~Year-To-Date 2020 vs. 2019~~

~~Net revenue~~ ~~decreased 3%, primarily reflecting:~~

•	~~A $20 million decrease in services performed for Atlantic Coast Pipeline; and~~

•	~~An $8 million decrease in services provided to affiliates.~~

~~Other operations and maintenance~~ ~~decreased 18%, primarily reflecting:~~

•	~~A $39 million decrease due to the absence of a charge related to a voluntary retirement program; and~~

•	~~A $20 million decrease in services performed for Atlantic Coast Pipeline.~~

~~Other income~~ ~~increased 12%, primarily due to an increase in non-service components of pension and other postretirement employee benefit plan credits.~~

~~Interest and related charges~~ ~~decreased 38%,~~primarily due to the absence of interest expense from Cove Point’s term loan borrowings ($68 million), partially offset by interest expense on Dominion Energy Gas’ November 2019 senior note issuance ($15 million).

~~Income tax expense~~ ~~decreased $96 million, primarily due to lower pre-tax income.~~

~~Liquidity and Capital Resources~~

Dominion Energy depends on both internal and external sources of liquidity to provide working capital and as a bridge to long-term debt financings. Short-term cash requirements not met by cash provided by operations are generally satisfied with proceeds from short-term borrowings. Long-term cash needs are met through issuances of debt and/or equity securities.

At June 30, 2020, Dominion Energy had $5.7 billion of unused capacity under its joint revolving credit facility. In addition, Dominion Energy had $675 million available under a $900 million 364-Day Revolving Credit Agreement entered into in March 2020.

As part of its strategic response to COVID-19, Dominion Energy undertook certain measures in March and April 2020 to buttress its liquidity position. This includes entering the $900 million 364-Day Revolving Credit Agreement, which has the potential for an additional $300 million of capacity upon certain events. In addition, Dominion Energy borrowed $1.1 billion under two 364-Day Term Loan Credit Agreements and issued $2.3 billion of senior notes. In June 2020, Dominion Energy repaid the outstanding balance of $625 million associated with one of the 364-Day Term Loan Credit Agreements. See Note 16 to the Consolidated Financial Statements for more information.

~~A summary of Dominion Energy’s cash flows is presented below:~~

2020

2019

(millions)

Cash, restricted cash and equivalents at January 1

$
269

$
391

Cash flows provided by (used in):

Operating activities

3,136

2,313

Investing activities

(3,334
)

(1,833
)
Financing activities

671

(311
)
Net increase in cash, restricted cash and equivalents

473

169

Cash, restricted cash and equivalents at June 30

$
742

$
560

~~Operating Cash Flows~~

Net cash provided by Dominion Energy’s operating activities increased $823 million, primarily due to higher deferred fuel cost recoveries, lower payments for income taxes, the absence of a contract termination payment and net changes in working capital items.

Dominion Energy believes that its operations provide a stable source of cash flow to contribute to planned levels of capital expenditures and maintain or grow the dividend on common shares. In December 2019, Dominion Energy’s Board of Directors established an annual dividend rate for 2020 of $3.76 per share of common stock. In January 2020, Dominion Energy’s Board of Directors declared dividends payable in March 2020 of 94 cents per share of common stock, and in May 2020, Dominion Energy’s Board of Directors declared dividends payable in June 2020 of 94 cents per share of common stock. In July 2020, Dominion Energy’s Board of Directors declared dividends payable in September 2020 of 94 cents per share of common stock. Also in July 2020, Dominion Energy announced that it currently expects to make a fourth dividend payment in December 2020 of approximately 63 cents per share of common stock reflecting the expected timing of the closing of the proposed transaction with BHE. Dividends are subject to declaration by the Board of Directors.

Dominion Energy’s operations are subject to risks and uncertainties that may negatively impact the timing or amounts of operating cash flows, which are discussed in Part I. Item 1A. Risk Factors in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019 and Part II. Item 1A. Risk Factors in the Companies’ Quarterly Report on Form 10-Q for the quarter ended March 31, 2020.

~~Credit Risk~~

Dominion Energy’s exposure to potential concentrations of credit risk results primarily from its energy marketing and price risk management activities. Presented below is a summary of Dominion Energy’s credit exposure as of June 30, 2020 for these activities. Gross credit exposure for each counterparty is calculated prior to the application of collateral and represents outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights.

Gross Credit
Exposure

Credit
Collateral

Net Credit
Exposure

(millions)

Investment grade⁽¹⁾

$
88

$
—

$
88

Non-investment grade⁽²⁾

3

—

3

No external ratings:

Internally rated—investment grade⁽³⁾

117

—

117

Internally rated—non-investment grade⁽⁴⁾

7

—

7

Total⁽⁵⁾

$
215

$
—

$
215

~~(1)~~

Designations as investment grade are based upon minimum credit ratings assigned by Moody’s Investors Service and Standard & Poor’s. The five largest counterparty exposures, combined, for this category represented approximately 29% of the total net credit exposure.

~~(2)~~

~~The five largest counterparty exposures, combined, for this category represented approximately 2% of the total net credit exposure.~~

~~(3)~~

~~The five largest counterparty exposures, combined, for this category represented approximately 53% of the total net credit exposure.~~

~~(4)~~

~~The five largest counterparty exposures, combined, for this category represented approximately 2% of the total net credit exposure.~~

~~(5)~~

~~Excludes the Millstone 2019 power purchase agreements.~~

~~Investing Cash Flows~~

Net cash used in Dominion Energy’s investing activities increased $1.5 billion, primarily due to an increase in plant construction and other property additions, the absence of cash acquired in the SCANA Combination and the acquisitions of Pivotal LNG, Inc. and an additional interest in Atlantic Coast Pipeline.

~~Financing Cash Flows and Liquidity~~

~~Dominion Energy relies on capital markets as significant sources of funding for capital requirements not satisfied by cash provided by its operations. As discussed further in~~ ~~Credit Ratings~~ ~~and~~ ~~Debt Covenants~~ in MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019, the ability to borrow funds or issue securities and the return demanded by investors are affected by credit ratings. In addition, the raising of external capital is subject to certain regulatory requirements, including registration with the SEC for certain issuances.

Dominion Energy currently meets the definition of a well-known seasoned issuer under SEC rules governing the registration, communications and offering processes under the Securities Act of 1933, as amended. The rules provide for a streamlined shelf registration process to provide registrants with timely access to capital. This allows Dominion Energy to use automatic shelf registration statements to register any offering of securities, other than those for exchange offers or business combination transactions. In June 2020, Dominion Energy filed a SEC shelf registration statement for the sale of debt and equity securities which replaced the shelf registration statement filed by Dominion Energy in June 2017.

Net cash provided by Dominion Energy's financing activities was $671 million for the six months ended June 30, 2020, compared to net cash used by financing activities of $311 million for the six months ended June 30, 2019, primarily due to higher issuances of short- and long-term debt to buttress liquidity as a strategic response to COVID-19 and lower repayments of long-term debt, partially offset by higher repayments of short-term debt and the absence of the issuance of the 2019 Equity Units.

In November 2017, Dominion Energy filed a SEC shelf registration statement for the sale of up to $3.0 billion of variable denomination floating rate demand notes, called Dominion Energy Reliability Investment^SM. The registration limits the principal amount that may be outstanding at any one time to $1.0 billion. The notes are offered on a continuous basis and bear interest at a floating rate per annum determined by the Dominion Energy Reliability Investment Committee, or its designee, on a weekly basis. The notes have no stated maturity date, are non-transferable and may be redeemed in whole or in part by Dominion Energy or at the

investor’s option at any time. The balance as of June 30, 2020 was $176 million. The notes are short-term debt obligations on Dominion Energy’s Consolidated Balance Sheets. The proceeds will be used for general corporate purposes and to repay debt.

In July 2020, the Board of Directors authorized the repurchase of up to $3.0 billion of Dominion Energy’s common stock and rescinded the prior two authorizations from 2005 and 2007. The repurchase program does not include a specific timetable or price or volume targets and may be modified, suspended or terminated at any time. Shares may be purchased through open market or privately negotiated transactions or otherwise at the discretion of management subject to prevailing market conditions, applicable securities laws and other factors.

~~See Note 16 to the Consolidated Financial Statements in this report for further information regarding Dominion Energy’s credit facilities, liquidity and significant financing transactions.~~

~~Credit Ratings~~

Credit ratings are intended to provide banks and capital market participants with a framework for comparing the credit quality of securities and are not a recommendation to buy, sell or hold securities. In the ~~Credit Ratings~~ section of MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019, there is a discussion on the use of capital markets by Dominion Energy as well as the impact of credit ratings on the accessibility and costs of using these markets. As of June 30, 2020, there have been no changes in Dominion Energy’s credit ratings.

~~Debt Covenants~~

~~In the~~ ~~Debt Covenants~~ section of MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019, there is a discussion on the various covenants present in the enabling agreements underlying Dominion Energy’s debt. In addition, see Note 16 to the Consolidated Financial Statements in this report for a description of certain financial covenants associated with term loan and revolving credit agreements entered into in the first quarter of 2020. As of June 30, 2020, there have been no material changes to debt covenants, nor any events of default under Dominion Energy’s debt covenants.

~~Future Cash Payments for Contractual Obligations and Planned Capital Expenditures~~

As of June 30, 2020, there have been no material changes outside the ordinary course of business to Dominion Energy’s contractual obligations nor any material changes to planned capital expenditures as disclosed in MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019.

~~Use of Off-Balance Sheet Arrangements~~

As of June 30, 2020, there have been no material changes to the off-balance sheet arrangements disclosed in MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019, with the exception of the following matter.

In December 2019, Dominion Energy signed an agreement with a lessor, as amended in May 2020, to construct and lease a new corporate office property in Richmond, Virginia. The lessor is providing equity and has obtained financing commitments from debt investors, totaling $465 million, to fund the estimated project costs. If Dominion Energy ultimately proceeds with the project through completion, ~~the project is expected to be completed by September 2024~~. Dominion Energy has been appointed to act as the construction agent for the lessor, during which time Dominion Energy will request cash draws from the lessor and debt investors to fund all project costs. If the project is terminated under certain events, Dominion Energy could be required to pay up to 100% of the then funded amount.

The lease term will commence once construction is substantially complete and the facility is able to be occupied and end in December 2027. At the end of the initial lease term, Dominion Energy can (i) extend the term of the lease for an additional five years, subject to the approval of the participants, at current market terms, (ii) purchase the property for an amount equal to the project costs or, (iii) subject to certain terms and conditions, sell the property on behalf of the lessor to a third party using commercially reasonable efforts to obtain the highest cash purchase price for the property. If the project is sold and the proceeds from the sale are insufficient to repay the investors for the project costs, Dominion Energy may be required to make a payment to the lessor, up to 83% of project costs, for the difference between the project costs and sale proceeds. Dominion Energy is not considered the owner during construction for financial accounting purposes and, therefore, will not reflect the construction activity in its consolidated financial statements. Dominion Energy expects to recognize a right-of-use asset and a corresponding finance lease liability at the commencement of the lease term. Dominion Energy will be considered the owner of the leased property for tax purposes, and as a result, will be entitled to tax deductions for depreciation and interest expense.

~~Future Issues and Other Matters~~

The following discussion of future issues and other information includes current developments of previously disclosed matters and new issues arising during the period covered by, and subsequent to, the dates of Dominion Energy’s Consolidated Financial Statements that may impact future results of operations, financial condition and/or cash flows. This section should be read in conjunction with ~~Item 1. Business~~ ~~and~~ ~~Future Issues and Other Matters~~ ~~in MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019,~~ ~~Future Issues and Other Matters~~ ~~in MD&A in the Companies’ Quarterly Report on Form 10-Q for the quarter ended March 31, 2020 and Note 17 to the Consolidated Financial Statements in this report.~~

~~Environmental Matters~~

Dominion Energy is subject to costs resulting from a number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations. See Note 23 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019, Note 17 to the Consolidated Financial Statements in the Companies’ Quarterly Report on Form 10-Q for the quarter ended March 31, 2020 and Note 17 to the Consolidated Financial Statements in this report for additional information on various environmental matters.

~~Legal Matters~~

~~See~~Notes 13 and 23 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019, Notes 13 and 17 to the Consolidated Financial Statements and ~~Item 1. Legal Proceedings~~ ~~in the Companies’ Quarterly Report on Form 10-Q for the quarter ended March 31, 2020 and Notes 13 and 17 to the Consolidated Financial Statements and~~ ~~Item 1. Legal Proceedings~~ ~~in this report for additional information on various legal matters.~~

~~Regulatory Matters~~

See Notes 3 and 13 to the Consolidated Financial Statements in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019, Note 13 to the Consolidated Financial Statements in the Companies’ Quarterly Report on Form 10-Q for the quarter ended March 31, 2020 and Note 13 to the Consolidated Financial Statements in this report for additional information on various regulatory matters.

~~Atlantic Coast Pipeline and Supply Header Projects~~

In July 2020, Dominion Energy and Duke Energy announced the cancellation of the Atlantic Coast Pipeline Project. As a result, Dominion Energy recorded an abandonment for a significant portion of the Supply Header Project. See Notes 2 and 10 to the Consolidated Financial Statements in this report for more information.

~~NWP 12 Permitting~~

In April 2020, the U.S. District Court for the District of Montana issued an order vacating an NWP 12 issued by the Army Corps of Engineers and remanding the permit back to the Army Corps of Engineers for consultation under the Endangered Species Act. In 2017, the Army Corps of Engineers issued an NWP 12 authorizing discharges related to construction projects into waters of the U.S. The district court concluded that the issuance of the NWP 12 was unlawful because the Army Corps of Engineers did not consult under the Endangered Species Act with the U.S Fish and Wildlife Service and/or National Marine Fisheries Service. The district court also enjoined the Army Corps of Engineers from authorizing any dredge or fill activities under NWP 12. Following the district court’s ruling, the Army Corps of Engineers suspended the NWP 12. In May 2020, the district court amended its order to authorize the use of NWP 12 for all utility line projects other than new oil and gas pipeline projects. The Army Corps of Engineers sought emergency relief of the district court’s order from the U.S. Court of Appeals for the Ninth Circuit and the U.S. Supreme Court. In July 2020, the U.S. Supreme Court issued an order limiting the scope of the district court’s order to the construction of the Keystone XL pipeline, allowing other new oil and gas pipeline projects to use the NWP 12 process pending the appeal of the district court’s order to the U.S. Court of Appeals for the Ninth Circuit. As a result of the amended order, the cancellation of the Atlantic Coast Pipeline Project and the pending sale of its gas transmission operations to BHE, Dominion Energy does not currently expect this matter to have a material impact to its results of operations, financial position or cash flows.

~~COVID-19~~

Dominion Energy continues to monitor the global outbreak of COVID-19 and has taken appropriate steps to mitigate the potential risks to Dominion Energy, its employees and its customers posed by the spread of the virus. Dominion Energy provides a critical service to its customers which means that it is paramount for the company to keep its employees who operate its businesses safe and informed. For example, Dominion Energy has taken precautions with regard to employee and facility hygiene, imposed travel limitations on employees, directed employees to work remotely whenever possible and expanded health and paid time off benefits for employees. Additional protocols have been implemented for required work within customer premises to protect Dominion Energy’s employees, such customers and the public. In addition, Dominion Energy has assessed and updated its existing business continuity plans for its business units in the context of this pandemic. Working with a medical advisor, Dominion Energy developed a COVID-19 training program, which has been rolled out to employees. Dominion Energy is providing all appropriate personal protection equipment to keep employees safe and has implemented additional protections such as temperature screenings, testing services, and mandatory face covering policies. Dominion Energy is also working with suppliers to understand the potential impacts to its supply chain; however, at this time, no material risks to Dominion Energy’s supply chain have been identified. This is a rapidly evolving situation, and Dominion Energy will continue to monitor developments affecting its workforce, suppliers and other aspects of its business, such as construction projects, and will take additional precautions as Dominion Energy believes are warranted. In addition, Dominion Energy continues to monitor both customer demand and its ability to collect customer receivables. While Dominion Energy currently does not expect a material impact to its results of operations from the impacts of the COVID-19 pandemic on its operations, the ultimate impacts on its results of operations, financial position and/or cash flows could be material based on the ultimate duration of the pandemic and the related economic recovery.

~~ITEM 3.~~

~~QUANTITATIVE AND QUALITATIVE~~

~~DISCLOSURES ABOUT MARKET RISK~~

The matters discussed in this Item may contain “forward-looking statements” as described in the introductory paragraphs under Part I, Item 2. MD&A in this report. The reader’s attention is directed to those paragraphs for discussion of various risks and uncertainties that may impact the Companies.

~~Market Risk Sensitive Instruments and Risk Management~~

The Companies’ financial instruments, commodity contracts and related financial derivative instruments are exposed to potential losses due to adverse changes in commodity prices, interest rates and equity security prices as described below. Commodity price risk is present in Dominion Energy and Virginia Power’s electric operations and Dominion Energy and Dominion Energy Gas’ natural gas procurement and marketing operations due to the exposure to market shifts in prices received and paid for electricity, natural gas and other commodities. The Companies use commodity derivative contracts to manage price risk exposures for these operations. Interest rate risk is generally related to their outstanding debt and future issuances of debt. In addition, the Companies are exposed to investment price risk through various portfolios of equity and debt securities.

The following sensitivity analysis estimates the potential loss of future earnings or fair value from market risk sensitive instruments over a selected time period due to a 10% change in commodity prices or interest rates.

~~Commodity Price Risk~~

To manage price risk, Dominion Energy and Virginia Power hold commodity-based derivative instruments held for non-trading purposes associated with purchases and sales of electricity, natural gas and other energy-related products. Dominion Energy Gas’ operations are contracted primarily under long-term fixed reservation agreements. Accordingly, management believes that Dominion Energy Gas is not subject to material commodity price risk.

The derivatives used to manage commodity price risk are executed within established policies and procedures and may include instruments such as futures, forwards, swaps, options and FTRs that are sensitive to changes in the related commodity prices. For sensitivity analysis purposes, the hypothetical change in market prices of commodity-based derivative instruments is determined based on models that consider the market prices of commodities in future periods, the volatility of the market prices in each period, as well as the time value factors of the derivative instruments. Prices and volatility are principally determined based on observable market prices.

A hypothetical 10% decrease in commodity prices would have resulted in a decrease in fair value of $31 million and $50 million of Dominion Energy’s commodity-based derivative instruments as of June 30, 2020 and December 31, 2019, respectively.

A hypothetical 10% decrease in commodity prices would have resulted in a decrease in fair value of $42 million and $54 million of Virginia Power’s commodity-based derivative instruments as of June 30, 2020 and December 31, 2019, respectively.

The impact of a change in energy commodity prices on the Companies' commodity-based derivative instruments at a point in time is not necessarily representative of the results that will be realized when the contracts are ultimately settled. Net losses from commodity-based financial derivative instruments used for hedging purposes, to the extent realized, will generally be offset by recognition of the hedged transaction, such as revenue from physical sales of the commodity.

~~Interest Rate Risk~~

The Companies manage their interest rate risk exposure predominantly by maintaining a balance of fixed and variable rate debt. They also enter into interest rate sensitive derivatives, including interest rate swaps and interest rate lock agreements. For variable rate debt outstanding for Dominion Energy, Virginia Power and Dominion Energy Gas, a hypothetical 10% increase in market interest rates would not have resulted in a material change in earnings at June 30, 2020 or December 31, 2019.

The Companies also use interest rate derivatives, including forward-starting swaps, as hedges of forecasted interest payments. As of June 30, 2020, Dominion Energy, Virginia Power and Dominion Energy Gas had $8.5 billion, $2.1 billion and $1.3 billion, respectively, in aggregate notional amounts of these interest rate derivatives outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of $95 million, $50 million and $7 million, respectively, in the fair value of Dominion Energy, Virginia Power and Dominion Energy Gas’ interest rate derivatives at June 30, 2020. As of December 31, 2019, Dominion Energy, Virginia Power and Dominion Energy Gas had $6.4 billion, $1.9 billion and $1.3 billion, respectively, in aggregate notional amounts of these interest rate derivatives outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of $135 million, $88 million and $17 million, respectively, in the fair value of Dominion Energy, Virginia Power and Dominion Energy Gas’ interest rate derivatives at December 31, 2019.

Dominion Energy Gas holds foreign currency swaps for the purpose of hedging the foreign currency exchange risk associated with Euro denominated debt. At both June 30, 2020 and December 31, 2019, Dominion Energy and Dominion Energy Gas had €250 million in aggregate notional amounts of these foreign currency swaps outstanding. A hypothetical 10% decrease in market interest rates would not have resulted in a material decrease in the fair value of Dominion Energy Gas’ foreign currency swaps at June 30, 2020 or December 31, 2019.

The impact of a change in interest rates on the Companies’ interest rate-based financial derivative instruments at a point in time is not necessarily representative of the results that will be realized when the contracts are ultimately settled. Net gains and/or losses from interest rate derivative instruments used for hedging purposes, to the extent realized, will generally be offset by recognition of the hedged transaction.

~~Investment Price Risk~~

Dominion Energy and Virginia Power are subject to investment price risk due to securities held as investments in nuclear decommissioning and rabbi trust funds that are managed by third-party investment managers. These trust funds primarily hold marketable securities that are reported in Dominion Energy and Virginia Power’s Consolidated Balance Sheets at fair value.

Dominion Energy recognized net investment losses (including investment income) on nuclear decommissioning and rabbi trust investments of $207 million for the six months ended June 30, 2020, and net investment gains (including investment income) on nuclear decommissioning and rabbi trust investments of $603 million for the six months ended June 30, 2019 and $1.0 billion for the year ended December 31, 2019. Net realized gains and losses include gains and losses from the sale of investments in both 2020 and 2019 as well as any other-than-temporary declines in fair value in 2019 only. Dominion Energy recorded in AOCI and regulatory liabilities, a net increase in unrealized gains on debt investments of $37 million and $65 million for the six months ended June 30, 2020 and 2019, respectively, and $74 million for the year ended December 31, 2019.

Virginia Power recognized net investment losses (including investment income) on nuclear decommissioning and rabbi trust investments of $119 million for the six months ended June 30, 2020, and net investment gains (including investment income) on nuclear decommissioning and rabbi trust investments of $282 million for the six months ended June 30, 2019 and $481 million for the year ended December 31, 2019. Net realized gains and losses include gains and losses from the sale of investments in both 2020 and 2019 as well as any other-than-temporary declines in fair value in 2019 only. Virginia Power recorded in AOCI and regulatory liabilities, a net increase in unrealized gains on debt investments of $20 million and $31 million for the six months ended June 30, 2020 and 2019, respectively, and $30 million for the year ended December 31, 2019.

Dominion Energy sponsors pension and other postretirement employee benefit plans that hold investments in trusts to fund employee benefit payments. Virginia Power and Dominion Energy Gas employees participate in these plans. Differences between actual and expected returns on plan assets are accumulated and amortized during future periods. As such, any investment-related declines in these trusts will result in future increases in the net periodic cost recognized for employee benefit plans and will be included in the determination of the amount of cash to be contributed to the employee benefit plans.

~~ITEM 4. CONTROLS AND PROCEDURES~~

Senior management of each of Dominion Energy, Virginia Power and Dominion Energy Gas, including Dominion Energy, Virginia Power and Dominion Energy Gas’ CEO and CFO, evaluated the effectiveness of each of their respective company’s disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, each of Dominion Energy, Virginia Power and Dominion Energy Gas’ CEO and CFO have concluded that each of their respective company’s disclosure controls and procedures are effective.

There were no changes that occurred during the last fiscal quarter that materially affected, or are reasonably likely to materially affect Dominion Energy, Virginia Power or Dominion Energy Gas’ internal control over financial reporting.

~~PART II. OTHER INFORMATION~~

~~ITEM 1. LEGAL PROCEEDINGS~~

From time to time, the Companies are alleged to be in violation or in default under orders, statutes, rules or regulations relating to the environment, compliance plans imposed upon or agreed to by the Companies, or permits issued by various local, state and/or federal agencies for the construction or operation of facilities. Administrative proceedings may also be pending on these matters. In addition, in the ordinary course of business, the Companies and their subsidiaries are involved in various legal proceedings.

In March 2018, Virginia Power received a proposed consent order from the VDEQ in connection with alleged CWA permit violations at the Chesterfield power station in 2017. Virginia Power began working cooperatively with both the VDEQ and the EPA to resolve those and certain other alleged violations collectively. In March 2020, Virginia Power finalized a consent decree with the VDEQ and the EPA that would require Virginia Power to pay a $1.4 million civil penalty in connection with various alleged CWA permit and other violations. In July 2020, the consent decree was entered by order of the U.S. District Court for the Eastern District of Virginia.

~~See the following for discussions on various legal, environmental and other regulatory proceedings to which the Companies are a party, which information is incorporated herein by reference:~~

•	~~Notes 13 and 23 to the Consolidated Financial Statements and~~ ~~Future Issues and Other Matters~~ ~~in MD&A in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019.~~

•	~~Notes 13 and 17 to the Consolidated Financial Statements in the Companies’ Quarterly Report on Form 10-Q for the quarter ended March 31, 2020.~~

•	~~Notes 13 and 17 to the Consolidated Financial Statements in this report.~~

~~ITEM 1A. RISK FACTORS~~

The Companies’ businesses are influenced by many factors that are difficult to predict, involve uncertainties that may materially affect actual results and are often beyond the Companies’ control. A number of these risk factors have been identified in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019 and updated in the Companies’ Quarterly Report on Form 10-Q for the quarter ended March 31, 2020,~~which should be taken into consideration when reviewing the information~~ contained in this report. There have been no material changes with regard to the risk factors previously disclosed in the Companies’ Annual Report on Form 10-K for the year ended December 31, 2019 and the Companies’ Quarterly Report on Form 10-Q for the quarter ended March 31, 2020. For other factors that may cause actual results to differ materially from those indicated in any forward-looking statement or projection contained in this report, see ~~Forward-Looking Statements~~Exhibit 101. ~~in MD&A in this report.~~

~~ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS~~

~~Dominion Energy~~

~~ISSUER PURCHASES OF EQUITY SECURITIES~~

~~Period~~

~~Total~~

~~Number of~~

~~Shares~~

~~(or Units)~~

~~Purchased~~⁽¹⁾

~~Average~~

~~Price Paid~~

~~per Share~~

~~(or Unit)~~⁽²⁾

~~Total Number~~

~~of Shares (or Units)~~

~~Purchased as Part~~

~~of Publicly~~

~~Announced Plans or~~

~~Programs~~

~~Maximum Number (or~~

~~Approximate Dollar~~

~~Value) of Shares (or Units)~~

~~that May Yet Be~~

~~Purchased under the Plans~~

~~or Programs~~⁽³⁾

~~4/1/20-4/30/20~~

—

~~19,629,059 shares/~~

~~$1.18 billion~~

~~5/1/20-5/31/20~~

—

~~19,629,059 shares/~~

~~$1.18 billion~~

~~6/1/20-6/30/20~~

—

~~19,629,059 shares/~~

~~$1.18 billion~~

~~Total~~

—

~~19,629,059 shares/~~

~~$1.18 billion~~

~~(1)~~

~~Represents shares that were tendered by employees to satisfy tax withholding obligations on vested restricted stock.~~

~~(2)~~

~~Represents the weighted-average price paid per share.~~

167

~~(3)~~

The remaining repurchase authorization is pursuant to repurchase authority granted by the Dominion Energy Board of Directors in February 2005, as modified in June 2007. The aggregate authorization granted by the Dominion Energy Board of Directors was 86 million shares (as adjusted to reflect a two-for-one stock split distributed in November 2007) not to exceed $4 billion.

~~In July 2020, the Board of Directors authorized the repurchase of up to $3.0 billion of Dominion Energy’s common stock and rescinded the prior two authorizations from 2005 and 2007.~~ The repurchase program does not include a specific timetable or price or volume targets and may be modified, suspended or terminated at any time. Shares may be purchased through open market or privately negotiated transactions or otherwise at the discretion of management subject to prevailing market ~~conditions, applicable securities laws and other factors.~~

~~ITEM 6. EXHIBITS~~

~~Exhibit~~ ~~Number~~	~~Description~~	~~Dominion Energy~~	~~Virginia Power~~	~~Dominion Energy Gas~~

~~2.1~~	Purchase and Sale Agreement, dated as of July 3, 2020, by and among Dominion Energy, Inc., Dominion Energy Questar Corporation and Berkshire Hathaway Energy Company (Exhibit 2.1, Form 8-K filed July 6, 2020, File No. 1-8489).	X

~~3.1.a~~	~~Dominion Energy, Inc. Articles of Incorporation, as restated, effective December 13, 2019 (Exhibit 3.1, Form 8-K filed December 13, 2019, File No.1-8489).~~	X

~~3.1.b~~	~~Virginia Electric and Power Company Amended and Restated Articles of Incorporation, as in effect on October 30, 2014 (Exhibit 3.1.b, Form 10-Q filed November 3, 2014, File No. 1-2255).~~		X

~~3.1.c~~	~~Articles of Organization of Dominion Energy Gas Holdings, LLC (Exhibit 3.1, Form S-4 filed April 4, 2014, File No. 333-195066).~~			X

~~3.1.d~~	~~Articles of Amendment to the Articles of Organization of Dominion Energy Gas Holdings, LLC (Exhibit 3.1, Form 8-K filed May 16, 2017, File No. 1-37591).~~			X

~~3.2.a~~	~~Dominion Energy, Inc. Bylaws, as amended and restated, effective July 30, 2020 (Exhibit 3.1, Form 8-K filed July 31, 2020, File No. 1-8489).~~	X

~~3.2.b~~	~~Virginia Electric and Power Company Amended and Restated Bylaws, effective June 1, 2009 (Exhibit 3.1, Form 8-K filed June 3, 2009, File No. 1-2255).~~		X

~~3.2.c~~	~~Operating Agreement of Dominion Energy Gas Holdings, LLC, as amended and restated, effective November 5, 2019 (Exhibit 3.1, Form 8-K filed November 12, 2019, File No. 001-37591).~~			X

~~4.1~~	Dominion Energy, Inc., Virginia Electric and Power Company and Dominion Energy Gas Holdings, LLC agree to furnish to the U.S. Securities and Exchange Commission upon request any other instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of any of their total consolidated assets.	X	X	X

~~4.2~~	~~Indenture, dated as of June 1, 2015, between Dominion Resources, Inc. and Deutsche Bank Trust Company Americas, as Trustee (Exhibit 4.1, Form 8-K filed June 15, 2015, File No. 1-8489)~~; ~~First Supplemental Indenture, dated as of June 1, 2015 (Exhibit 4.2, Form 8-K filed June 15, 2015, File No. 1-8489)~~; ~~Second Supplemental Indenture, dated as of September 1, 2015 (Exhibit 4.2, Form 8-K filed September 24, 2015, File No. 1-8489)~~; ~~Third Supplemental Indenture, dated as of February 1, 2016 (Exhibit 4.7, Form 10-K for the fiscal year ended December 31, 2015 filed February 26, 2016, File No. 1-8489)~~; ~~Fourth Supplemental Indenture, dated as of August 1, 2016 (Exhibit 4.2, Form 8-K filed August 9, 2016, File No. 1-8489)~~; ~~Fifth Supplemental Indenture, dated as of August 1, 2016 (Exhibit 4.3, Form 8-K filed August 9, 2016, File No. 1-8489)~~; ~~Sixth Supplemental Indenture, dated as of August 1, 2016 (Exhibit 4.4, Form 8-K filed August 9, 2016, File No. 1-8489)~~; ~~Seventh Supplemental Indenture, dated as of September 1, 2016 (Exhibit 4.1, Form 10-Q filed November 9, 2016, File No. 1-8489)~~; ~~Eighth Supplemental Indenture, dated as of December 1, 2016 (Exhibit 4.7, Form 10-K for the fiscal year ended December 31, 2016 filed February 28, 2017, File No. 1-8489)~~; ~~Ninth Supplemental Indenture, dated as of January 1, 2017 (Exhibit 4.2, Form 8-K filed January 12, 2017, File No. 1-8489)~~; ~~Tenth Supplemental Indenture, dated as of January 1, 2017 (Exhibit 4.3, Form 8-K filed January 12, 2017, File No. 1-8489)~~; ~~Eleventh Supplemental Indenture, dated as of March 1, 2017 (Exhibit 4.3, Form 10-Q filed May 4, 2017, File No. 1-8489)~~; ~~Twelfth Supplemental Indenture, dated as of June 1, 2017 (Exhibit 4.2, Form 10-Q filed August 3, 2017, File No. 1-8489)~~; ~~Thirteenth Supplemental Indenture, dated December 1, 2017 (Exhibit 4.8, Form 10-K for the fiscal year ended December 31, 2017 filed February 27, 2018, File No. 1-8489)~~; ~~Fourteenth Supplemental Indenture, dated May 1, 2018 (Exhibit 4.2, Form 10-Q filed August 2, 2018, File No. 1-8489)~~; ~~Fifteenth Supplemental Indenture, dated June 1, 2018 (Exhibit 4.2, Form 8-K, filed June 5, 2018, File No. 1-8489)~~; ~~Sixteenth Supplemental Indenture, dated March 1, 2019 (Exhibit 4.2, Form 8-K filed March 13, 2019, File No. 1-8489)~~; ~~Seventeenth Supplemental Indenture, dated as of August 1, 2019 (Exhibit 4.2, Form 10-Q filed November 1, 2019, File No. 1-8489)~~; ~~Eighteenth Supplemental Indenture, dated as of March 1, 2020 (Exhibit 4.2, Form 8-K, filed March 19, 2020, File No. 1-8489)~~; ~~Nineteenth Supplemental Indenture, dated as of March 1, 2020 (Exhibit 4.3, Form 8-K, filed March 19, 2020, File No. 1-8489)~~; ~~Twentieth Supplemental Indenture, dated as of April 1, 2020 (Exhibit 4.2, Form 8-K, filed April 3, 2020, File No. 1-8489)~~.	X

SIGNATURES

~~Exhibit~~ ~~Number~~	~~Description~~	~~Dominion Energy~~	~~Virginia Power~~	~~Dominion Energy Gas~~

~~31.a~~	~~Certification by Chief Executive Officer of Dominion Energy, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).~~	X

~~31.b~~	~~Certification by Chief Financial Officer of Dominion Energy, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).~~	X

~~31.c~~	~~Certification by Chief Executive Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).~~		X

~~31.d~~	~~Certification by Chief Financial Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).~~		X

~~31.e~~	~~Certification by Chief Executive Officer of Dominion Energy Gas Holdings, LLC pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).~~			X

~~31.f~~	~~Certification by Chief Financial Officer of Dominion Energy Gas Holdings, LLC pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).~~			X

~~32.a~~	Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Dominion Energy, Inc. as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).	X

~~32.b~~	Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Virginia Electric and Power Company as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).		X

~~32.c~~	Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Dominion Energy Gas Holdings, LLC as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).			X

99	~~Condensed consolidated earnings statements (filed herewith).~~	X	X	X

~~101~~	The following financial statements from Dominion Energy, Inc.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2020, filed on August 5, 2020, formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Consolidated Statements of Income, (ii) Consolidated Statements of Comprehensive Income (iii) Consolidated Balance Sheets, (iv) Consolidated Statements of Equity, (v) Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements. The following financial statements from Virginia Electric and Power Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2020, filed on August 5, 2020, formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Consolidated Statements of Income, (ii) Consolidated Statements of Comprehensive Income, (iii) Consolidated Balance Sheets, (iv) Consolidated Statements of Common Shareholder’s Equity (v) Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements. The following financial statements from Dominion Energy Gas Holdings, LLC’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2020, filed on August 5, 2020, formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Consolidated Statements of Income, (ii) Consolidated Statements of Comprehensive Income, (iii) Consolidated Balance Sheets, (iv) Consolidated Statements of Equity, (v) Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements.	X	X	X

~~104~~	~~Cover Page~~ ~~Interactive Data File formatted in iXBRL (Inline eXtensible Business Reporting Language) and contained in Exhibit 101.~~	X	X	X

~~SIGNATURE~~

Pursuant to the requirements of the Securities Exchange Act of 1934, ~~the~~each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


		BERKSHIRE HATHAWAY ENERGY COMPANY

Date: April 30, 2021		~~DOMINION ENERGY, INC.~~ ~~Registrant~~ /s/ Calvin D. Haack
		Calvin D. Haack
~~August 5, 2020~~		~~/s/ Michele L. Cardiff~~ Senior Vice President and Chief Financial Officer
		(principal financial and accounting officer)

		~~Michele L. Cardiff~~ ~~Vice President, Controller and~~ ~~Chief Accounting Officer~~ PACIFICORP

	~~VIRGINIA ELECTRIC AND POWER COMPANY~~ ~~Registrant~~

~~August 5, 2020~~	~~/s/ Michele L. Cardiff~~
Date: April 30, 2021		~~Michele~~/s/ Nikki L. ~~Cardiff~~ Kobliha
		Nikki L. Kobliha
		Vice President, ~~Controller~~Chief Financial Officer and ~~Chief Accounting Officer~~ Treasurer
		(principal financial and accounting officer)
		~~DOMINION~~
		MIDAMERICAN FUNDING, LLC
		MIDAMERICAN ENERGY COMPANY

Date: April 30, 2021		/s/ Thomas B. Specketer
		Thomas B. Specketer
		Vice President and Controller
		of MidAmerican Funding, LLC and
		Vice President and Chief Financial Officer
		of MidAmerican Energy Company
		(principal financial and accounting officer)

		NEVADA POWER COMPANY

Date: April 30, 2021		/s/ Michael E. Cole
		Michael E. Cole
		Vice President, Chief Financial Officer and Treasurer
		(principal financial and accounting officer)

		SIERRA PACIFIC POWER COMPANY

Date: April 30, 2021		/s/ Michael E. Cole
		Michael E. Cole
		Vice President, Chief Financial Officer and Treasurer
		(principal financial and accounting officer)

		EASTERN ENERGY GAS HOLDINGS, LLC ~~Registrant~~

~~August 5, 2020~~	~~/s/ Michele L. Cardiff~~
Date: April 30, 2021		~~Michele L. Cardiff~~ /s/ Scott C. Miller
		Scott C. Miller
		Vice President, ~~Controller~~Chief Financial Officer and ~~Chief Accounting Officer~~ Treasurer
		(principal financial and accounting officer)

~~130~~

168

~~Commission File~~ ~~Number~~	~~Exact name of registrants as specified in their charters, address of~~ ~~principal executive offices and registrants’ telephone number~~	~~I.R.S. Employer~~ ~~Identification Number~~

~~001-08489~~	~~DOMINION ENERGY, INC.~~	~~54-1229715~~

~~000-55337~~	~~VIRGINIA ELECTRIC AND POWER COMPANY~~	~~54-0418825~~

~~001-37591~~	~~DOMINION ENERGY GAS HOLDINGS, LLC~~	~~46-3639580~~

	~~120 Tredegar Street~~ ~~Richmond, Virginia 23219~~ ~~(804) 819-2000~~


Registrant	Name of ~~Each Exchange~~ exchange on ~~Which Registered~~which registered:
~~DOMINION~~BERKSHIRE HATHAWAY ENERGY ~~INC.~~ COMPANY	D	~~Common Stock, no par value~~	~~New York Stock Exchange~~ None
PACIFICORP	~~DRUA~~	~~2016 Series A 5.25% Enhanced Junior Subordinated Notes~~	~~New York Stock Exchange~~ None
MIDAMERICAN FUNDING, LLC	~~DCUE~~	~~2019 Series A Corporate Units~~	~~New York Stock Exchange~~ None
~~DOMINION~~MIDAMERICAN ENERGY COMPANY	None
NEVADA POWER COMPANY	None
SIERRA PACIFIC POWER COMPANY	None
EASTERN ENERGY GAS HOLDINGS, LLC		~~2014 Series C 4.6% Senior Notes~~	~~New York Stock Exchange~~ None

~~Large accelerated filer~~	☐		~~Accelerated filer~~	☐	~~Emerging growth company~~	☐
~~Non-accelerated filer~~	☒		~~Smaller reporting company~~	☐

~~Large accelerated filer~~	☐		~~Accelerated filer~~	☐	~~Emerging growth company~~	☐
~~Non-accelerated filer~~	☒		~~Smaller reporting company~~	☐

		~~Page~~ ~~Number~~
Item 1.			~~Glossary of Terms~~Financial Statements		3 1

	~~PART I. Financial Information~~	9

~~Item 1.~~	~~Financial Statements~~	9
Item 2.	~~Management’s~~Management's Discussion and Analysis of Financial Condition and Results of Operations			~~105~~ 2
Item 3.			Quantitative and Qualitative Disclosures About Market Risk		~~124~~ 163
Item 4.			Controls and Procedures		~~125~~ 163


Registrant			~~Trading~~ ~~Symbol~~Securities registered pursuant to Section 12(b) of the Act:
BERKSHIRE HATHAWAY ENERGY COMPANY			~~Title of Each Class~~None
PACIFICORP			None
MIDAMERICAN FUNDING, LLC			None
MIDAMERICAN ENERGY COMPANY			None
NEVADA POWER COMPANY			None
SIERRA PACIFIC POWER COMPANY			None
EASTERN ENERGY GAS HOLDINGS, LLC			None


Item 1.			Legal Proceedings		164
Item 1A.			~~PART II. Other Information~~Risk Factors		~~126~~ 164

~~Item 1.~~	~~Legal Proceedings~~	~~126~~
~~Item 1A.~~	~~Risk Factors~~	~~126~~
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds			~~126~~ 164
Item 6. 3.			~~Exhibits~~Defaults Upon Senior Securities		~~128~~ 164
Item 4.			Mine Safety Disclosures		165
Item 5.			Other Information		165
Item 6.			Exhibits		165
Signatures					168

~~Abbreviation or Acronym~~	~~Definition~~
~~2016 Equity Units~~			Dominion Energy’s 2016 Series A Equity Units issued in August 2016, initially in the form of 2016 Series A Corporate Units, consisting of a stock purchase contract and a 1/40 interest in RSNs issued by Dominion Energy
~~2019 Equity Units~~	Dominion Energy’s 2019 Series A Equity Units issued in June 2019, initially in the form of 2019 Series A Corporate Units, consisting of a stock purchase contract and a 1/10 interest in a share of the Series A Preferred Stock
~~2017 Tax Reform Act~~	An Act to Provide for Reconciliation Pursuant to Titles II and V of the Concurrent Resolution on the Budget for Fiscal Year 2018 (previously known as The Tax Cuts and Jobs Act) enacted on December 22, 2017
~~ACE Rule~~	~~Affordable Clean Energy Rule~~
~~AFUDC~~	~~Allowance for funds used during construction~~
~~Align RNG~~	~~Align RNG, LLC, a joint venture between Dominion Energy and Smithfield Foods, Inc.~~
~~Altavista~~	~~Altavista biomass power station~~
~~AMI~~	~~Advanced Metering Infrastructure~~
~~AOCI~~	~~Accumulated other comprehensive income (loss)~~
~~ARO~~	~~Asset retirement obligation~~
~~Atlantic Coast Pipeline~~	~~Atlantic Coast Pipeline, LLC, a limited liability company owned by Dominion Energy and Duke Energy~~
~~Atlantic Coast Pipeline Project~~	A previously proposed approximately 600-mile natural gas pipeline running from West Virginia through Virginia to North Carolina which would have been owned by Dominion Energy and Duke Energy and constructed and operated by DETI
~~BACT~~	~~Best available control technology~~
~~bcf~~	~~Billion cubic feet~~
~~Bear Garden~~	~~A 590 MW combined-cycle, natural gas-fired power station in Buckingham County, Virginia~~
~~BHE~~	Berkshire Hathaway Energy Company and Related Entities
~~Blue Racer~~ BHE		~~Blue Racer Midstream, LLC, a joint venture between Caiman~~Berkshire Hathaway Energy ~~II, LLC and FR BR Holdings, LLC~~ Company
BP Berkshire Hathaway		~~BP Wind Energy North America~~Berkshire Hathaway Inc.
~~Brookfield~~ Berkshire Hathaway Energy or the Company		~~Brookfield Super-Core Infrastructure Partners, an infrastructure fund managed by Brookfield Asset Management Inc.~~ Berkshire Hathaway Energy Company and its subsidiaries
~~Brunswick County~~ PacifiCorp		~~A 1,376 MW combined-cycle, natural gas-fired power station in Brunswick County, Virginia~~ PacifiCorp and its subsidiaries
~~CAA~~ MidAmerican Funding		~~Clean Air Act~~
~~CARES Act~~	~~Coronavirus Aid, Relief and Economic Security Act, enacted on March 27, 2020~~
~~CCR~~	~~Coal combustion residual~~
~~CEO~~	~~Chief Executive Officer~~
~~CEP~~	~~Capital Expenditure Program, as established by House Bill 95, Ohio legislation enacted in 2011, deployed by East Ohio to recover certain costs associated with capital investment~~
~~CERCLA~~	~~Comprehensive Environmental Response, Compensation and Liability Act of 1980, also known as Superfund~~
~~CFO~~	~~Chief Financial Officer~~
CO₂	~~Carbon dioxide~~

~~Colonial Trail West~~	~~A 142 MW utility-scale solar power station located in Surry County, Virginia~~
~~Companies~~	~~Dominion Energy, Virginia Power and Dominion Energy Gas, collectively~~
~~Contracted Generation~~	~~Contracted Generation operating segment~~
~~Cooling degree days~~	Units measuring the extent to which the average daily temperature is greater than 65 degrees Fahrenheit, or 75 degrees Fahrenheit in DESC’s service territory, calculated as the difference between 65 or 75 degrees, as applicable, and the average temperature for that day
~~Cove Point~~	~~Dominion Energy Cove Point LNG, LP~~
~~Cove Point LNG Facility~~	~~An LNG import/export and storage facility, including the Liquefaction Facility, located on the Chesapeake Bay in Lusby, Maryland~~
~~CPCN~~	~~Certificate of Public Convenience and Necessity~~
~~CWA~~	~~Clean Water Act~~
~~DCP~~	~~The legal entity, Dominion Cove Point, LLC, one or more of its consolidated subsidiaries, or the entirety~~ of ~~Dominion Cove Point,~~MidAmerican Funding, LLC and its ~~consolidated~~ subsidiaries
~~DECG~~ MidAmerican Energy			~~Dominion~~MidAmerican Energy ~~Carolina Gas Transmission, Inc.~~ Company
~~DECGS~~ NV Energy			~~Dominion Energy Carolina Gas Services, Inc.~~
~~DEQPS~~	~~Dominion Energy Questar Pipeline Services, Inc.~~
~~DES~~	~~Dominion Energy Services, Inc.~~
~~DESC~~	The legal entity, Dominion Energy South Carolina, Inc., one or more of its consolidated entities or operating segment, or the entirety of Dominion Energy South Carolina, Inc. and its consolidated entities
~~DETI~~	~~Dominion Energy Transmission, Inc.~~
~~DGI~~	~~Dominion Generation, Inc.~~
~~DGP~~	~~Dominion Gathering and Processing, Inc.~~
~~DMLPHCII~~	~~Dominion MLP Holding Company II, LLC~~
~~DOE~~	~~U.S. Department of Energy~~
~~Dominion Energy~~	~~The legal entity, Dominion Energy, Inc., one or more of its consolidated subsidiaries (other than Virginia Power and Dominion Energy Gas) or operating segments, or the entirety of Dominion~~NV Energy, Inc. and its ~~consolidated~~ subsidiaries
~~Dominion~~Nevada Power			Nevada Power Company and its subsidiaries
Sierra Pacific			Sierra Pacific Power Company and its subsidiaries
Nevada Utilities			Nevada Power Company and its subsidiaries and Sierra Pacific Power Company and its subsidiaries
Eastern Energy Gas			~~The legal entity, Dominion Energy Gas Holdings, LLC, one or more of its consolidated subsidiaries or operating segment, or the entirety of Dominion~~Eastern Energy Gas Holdings, LLC and its ~~consolidated~~ subsidiaries
~~Dominion~~Registrants			Berkshire Hathaway Energy Company, PacifiCorp and its subsidiaries, MidAmerican Funding, LLC and its subsidiaries, MidAmerican Energy Company, Nevada Power Company and its subsidiaries, Sierra Pacific Power Company and its subsidiaries and Eastern Energy Gas ~~Restructuring~~ Holdings, LLC and its subsidiaries
Northern Powergrid			Northern Powergrid Holdings Company
BHE Pipeline Group			BHE GT&S, LLC, Northern Natural Gas Company and Kern River Gas Transmission Company
BHE GT&S			BHE GT&S, LLC
Northern Natural Gas			Northern Natural Gas Company
Kern River			Kern River Gas Transmission Company
BHE Transmission			BHE Canada Holdings Corporation and BHE U.S. Transmission, LLC
BHE Canada			BHE Canada Holdings Corporation
AltaLink			AltaLink, L.P.
BHE U.S. Transmission			BHE U.S. Transmission, LLC
BHE Renewables			BHE Renewables, LLC and CalEnergy Philippines
HomeServices			HomeServices of America, Inc. and its subsidiaries
Utilities			PacifiCorp and its subsidiaries, MidAmerican Energy Company, Nevada Power Company and its subsidiaries and Sierra Pacific Power Company and its subsidiaries
Domestic Regulated Businesses			PacifiCorp and its subsidiaries, MidAmerican Energy Company, Nevada Power Company and its subsidiaries, Sierra Pacific Power Company and its subsidiaries, BHE GT&S, LLC, Northern Natural Gas Company and Kern River Gas Transmission Company
GT&S Transaction			The acquisition of ~~DCP~~substantially all of the natural gas transmission and ~~DMLPHCII from, and the disposition of East Ohio and DGP to, Dominion Energy by Dominion Energy Gas on November 6, 2019~~
~~Dominion Energy Midstream~~	~~The legal entity, Dominion Energy Midstream Partners, LP, one or more of its consolidated subsidiaries, or the entirety~~storage business of Dominion Energy ~~Midstream Partners, LP~~ and ~~its consolidated subsidiaries~~ Dominion Questar, exclusive of the Questar Pipeline Group on November 1, 2020
DEI			Dominion Energy, ~~Questar Pipeline~~ Inc.
		~~The legal entity, Dominion Energy~~ Questar Pipeline ~~LLC, one or more of its consolidated subsidiaries, or the entirety of~~ Group		Dominion Energy Questar Pipeline, LLC and ~~its consolidated subsidiaries~~ related entities
~~Dominion Energy South Carolina~~			~~Dominion Energy South Carolina operating segment~~
~~Dominion Energy Virginia~~			~~Dominion Energy Virginia operating segment~~
~~DSM~~			~~Demand-side management~~
~~Dth~~			~~Dekatherm~~
~~Duke Energy~~			~~The legal entity, Duke Energy Corporation, one or more of its consolidated subsidiaries, or the entirety of Duke Energy Corporation and its consolidated subsidiaries~~

~~East Ohio~~	~~The East Ohio Gas Company, doing business as Dominion Energy Ohio~~
~~EPA~~ Certain Industry Terms		~~U.S.~~
2017 Tax Reform		The Tax Cuts and Jobs Act enacted on December 22, 2017, effective January 1, 2018


AFUDC		Allowance for Funds Used During Construction
AUC		Alberta Utilities Commission
BART		Best Available Retrofit Technology

COVID-19		Coronavirus Disease 2019

CSAPR		Cross-State Air Pollution Rule
D.C. Circuit		United States Court of Appeals for the District of Columbia Circuit
DEAA		Deferred Energy Accounting Adjustment
Dth		Decatherm
EBA		Energy Balancing Account
ECAM		Energy Cost Adjustment Mechanism
EPA		United States Environmental Protection Agency
~~EPS~~ FERC		~~Earnings per share~~
~~Export Customers~~	~~ST Cove Point, LLC, a joint venture of Sumitomo Corporation and Tokyo Gas Co., LTD., and GAIL Global (USA) LNG, LLC~~
~~FERC~~	Federal Energy Regulatory Commission
~~FILOT~~		~~Fee in lieu of taxes~~
~~Four Brothers~~ GAAP		~~Four Brothers Solar, LLC, a limited liability company owned by Dominion Energy and Four Brothers Holdings, LLC, a subsidiary~~Accounting principles generally accepted in the United States of ~~GIP~~ America
~~Fowler Ridge~~ GEMA		~~Fowler I Holdings LLC, a wind-turbine facility joint venture with BP in Benton County, Indiana~~ Gas and Electricity Markets Authority
~~FTRs~~ GHG		~~Financial transmission rights~~ Greenhouse Gases
~~GAAP~~ GWh		~~U.S. generally accepted accounting principles~~ Gigawatt Hour
~~Gal~~ GTA		~~Gallon~~ General Tariff Application
~~Gas Distribution~~ IPUC		~~Gas Distribution operating segment~~ Idaho Public Utilities Commission
~~Gas Transmission & Storage~~ ICC		~~Gas Transmission & Storage operating segment~~ Illinois Commerce Commission
~~GENCO~~ IRP		~~South Carolina Generating Company, Inc.~~ Integrated Resource Plan
~~GHG~~ IUB		~~Greenhouse gas~~ Iowa Utilities Board
~~GIP~~ kV		~~The legal entity, Global Infrastructure Partners, one or more of its consolidated subsidiaries, or the entirety of Global Infrastructure Partners and its consolidated subsidiaries~~ Kilovolt
~~Granite Mountain~~ KHSA		~~Granite Mountain Holdings, LLC, a limited liability company owned by Dominion Energy and Granite Mountain Renewables, LLC, a subsidiary of GIP~~ Klamath Hydroelectric Settlement Agreement
~~Grassfield Solar~~		~~A proposed 20 MW utility-scale solar power station located in Chesapeake, Virginia~~
~~Greensville County~~ MW		~~A 1,588 MW combined-cycle, natural gas-fired power station in Greensville County, Virginia~~ Megawatt
~~GTSA~~ MWh		~~Virginia Grid Transformation and Security Act of 2018~~ Megawatt Hour
GW NAAQS		~~Gigawatt~~ National Ambient Air Quality Standards
~~Heating degree days~~ NOx		Units measuring the extent to which the average daily temperature is less than 65 degrees Fahrenheit, or 60 degrees Fahrenheit in DESC’s service territory, calculated as the difference between 65 or 60 degrees, as applicable, and the average temperature for that day Nitrogen Oxides
~~Hope~~		~~Hope Gas, Inc., doing business as Dominion Energy West Virginia~~
~~Hopewell~~ Ofgem		~~Polyester biomass power station~~ Office of Gas and Electric Markets
~~Iron Springs~~ OPUC		~~Iron Springs Holdings, LLC, a limited liability company owned by Dominion Energy and Iron Springs Renewables, LLC, a subsidiary of GIP~~ Oregon Public Utility Commission
~~Iroquois~~ PTC		~~Iroquois Gas Transmission System, L.P.~~ Production Tax Credit
~~ISO~~ PUCN		~~Independent system operator~~
~~JAX LNG~~	~~JAX LNG, LLC, an LNG supplier in Florida serving the marine and LNG markets~~
~~June 2006 hybrids~~	~~Dominion Energy’s 2006 Series A Enhanced Junior Subordinated Notes due 2066~~
~~Kewaunee~~	~~Kewaunee nuclear power station~~
kV	~~Kilovolt~~
~~Liquefaction Facility~~	~~A natural gas export/liquefaction facility at the Cove Point LNG Facility~~
~~LNG~~	~~Liquefied natural gas~~
~~MATS~~	~~Utility Mercury and Air Toxics Standard Rule~~

~~MD&A~~	~~Management’s Discussion and Analysis of Financial Condition and Results of Operations~~
~~MGD~~	~~Million gallons a day~~
~~Millstone~~	~~Millstone nuclear power station~~
~~Millstone 2019 power purchase agreements~~	~~Power purchase agreements with Eversource Energy and The United Illuminating Company for Millstone to provide nine million MWh per year of electricity for ten years~~
MW	~~Megawatt~~
~~MWh~~	~~Megawatt hour~~
~~NAV~~	~~Net asset value~~
~~NGL~~	~~Natural gas liquid~~
~~NND Project~~	V.C. Summer Units 2 and 3 nuclear development project under which DESC and Santee Cooper undertook to construct two Westinghouse AP1000 Advanced Passive Safety nuclear units in Jenkinsville, South Carolina
~~Norge Solar~~	~~A proposed 20 MW utility-scale solar power station located in James City County, Virginia~~
~~North Carolina Commission~~	~~North Carolina Utilities Commission~~
~~NRC~~	~~U.S. Nuclear Regulatory Commission~~
~~NSPS~~	~~New Source Performance Standards~~
~~NWP 12~~	~~A nationwide permit from the Army Corps of Engineers authorizing activities required for the~~ ~~construction, maintenance, repair and removal of utility lines, including electric transmission, gas pipelines, water and communications conduit and associated facilities in waters of the U.S.~~
~~NYSE~~	~~New York Stock Exchange~~
~~Ohio Commission~~	Public Utilities Commission of ~~Ohio~~ Nevada
~~Order 1000~~ RAC		~~Order issued by FERC adopting requirements for electric transmission planning, cost allocation and development~~ Renewable Adjustment Clause
~~Overthrust~~ REC		~~Dominion~~Renewable Energy ~~Overthrust Pipeline, L.L.C.~~ Credit
~~PIR~~ RFP		~~Pipeline Infrastructure Replacement program deployed by East Ohio~~ Request for Proposal
~~PJM~~ RPS		~~PJM Interconnection, L.L.C.~~ Renewable Portfolio Standards
~~Predecessor~~ RRA		~~Dominion~~ Renewable Energy ~~as the predecessor for accounting purposes for the period of Dominion Energy’s ownership of DCP~~Credit and ~~DMLPHCII until the completion of the Dominion Energy Gas Restructuring~~ Sulfur DioxideRevenue Adjustment Mechanism
~~PREP~~ SCR		~~Pipeline Replacement and Expansion Program, a program of replacing, upgrading and expanding natural gas utility infrastructure deployed by Hope~~ Selective Catalytic Reduction
~~PSD~~ SEC		~~Prevention of significant deterioration~~
~~PSNC~~	~~Public Service Company of North Carolina, Incorporated, doing business as Dominion Energy North Carolina~~
~~Questar Gas~~	~~Questar Gas Company, doing business as Dominion Energy Utah, Dominion Energy Wyoming and Dominion Energy Idaho~~
~~RCC~~	~~Replacement Capital Covenant~~
~~RGGI~~	~~Regional Greenhouse Gas Initiative~~
~~RICO~~	~~Racketeer Influenced and Corrupt Organizations Act~~
~~Rider B~~	~~A rate adjustment clause associated with the recovery of costs related to the conversion of three of~~ ~~Virginia~~ ~~Power’s coal-fired power stations to biomass~~
~~Rider BW~~	~~A rate adjustment clause associated with the recovery of costs related to Brunswick County~~
~~Rider GV~~	~~A rate adjustment clause associated with the recovery of costs related to Greensville County~~

~~Rider R~~	~~A rate adjustment clause associated with the recovery of costs related to Bear Garden~~
~~Rider S~~	~~A rate adjustment clause associated with the recovery of costs related to the Virginia City Hybrid Energy Center~~
~~Rider T1~~	~~A rate adjustment clause to recover the difference between revenues produced from transmission rates~~ ~~included~~ ~~in base rates and the new total revenue requirement developed annually for the rate years effective September 1~~
~~Rider U~~	~~A rate adjustment clause associated with the recovery of costs of new underground distribution facilities~~
~~Rider US-2~~	~~A rate adjustment clause associated with the recovery of costs related to Woodland Solar, Scott Solar and Whitehouse Solar~~
~~Rider US-3~~	~~A rate adjustment clause associated with the recovery of costs related to Colonial Trail West and Spring Grove 1~~
~~Rider US-4~~	~~A rate adjustment clause associated with the recovery of costs related to Sadler Solar~~
~~Rider W~~	~~A rate adjustment clause associated with the recovery of costs related to Warren County~~
~~Riders C1A, C2A and~~ ~~C3A~~	~~Rate adjustment clauses associated with the recovery of cost related to certain DSM programs approved in DSM cases~~
~~ROE~~	~~Return on equity~~
~~RSN~~	~~Remarketable subordinated note~~
~~RTO~~	~~Regional transmission organization~~
~~Sadler Solar~~	~~An approximately 100 MW proposed utility-scale solar power station located in Greensville County, Virginia~~
~~Santee Cooper~~	~~South Carolina Public Service Authority~~
~~SBL Holdco~~	~~SBL Holdco, LLC, a wholly-owned subsidiary of DGI~~
~~SCANA~~	~~The legal entity, SCANA Corporation, one or more of its consolidated subsidiaries, or the entirety of~~ ~~SCANA~~ ~~Corporation and its consolidated subsidiaries~~
~~SCANA Combination~~	~~Dominion Energy’s acquisition of SCANA completed on January 1, 2019 pursuant to the terms of the agreement and plan of merger entered on January 2, 2018 between Dominion Energy and SCANA~~
~~SCANA Merger Approval~~ ~~Order~~	~~Final order issued by the South Carolina Commission on December 21, 2018 setting forth its approval of the SCANA Combination~~
~~SCDHEC~~	~~South Carolina Department of Health and Environmental Control~~
~~SCDOR~~	~~South Carolina Department of Revenue~~
~~Scott Solar~~	~~A 17 MW utility-scale solar power station in Powhatan County, Virginia~~
~~SEC~~	~~U.S.~~United States Securities and Exchange Commission
~~SEMI~~ SIP		~~SCANA Energy Marketing, LLC (formerly known as SCANA Energy Marketing, Inc.), a subsidiary of~~ ~~SCANA~~State Implementation Plan ~~through December 2019, and effective December 2019, a subsidiary of Wrangler~~
~~September 2006 hybrids~~ SO2		~~Dominion Energy’s 2006 Series B Enhanced Junior Subordinated Notes due 2066~~ Sulfur Dioxide
~~Series A Preferred Stock~~		~~Dominion Energy’s 1.75% Series A Cumulative Perpetual Convertible Preferred Stock, without par~~ ~~value, with a liquidation preference of $1,000 per share~~
~~Series B Preferred Stock~~ UPSC		~~Dominion Energy’s 4.65% Series B Fixed-Rate Cumulative Redeemable Perpetual Preferred Stock,~~ ~~without~~ ~~par value, with a liquidation preference of $1,000 per share~~
~~South Carolina~~ ~~Commission~~	Utah Public Service Commission ~~of South Carolina~~
~~Southampton~~ WPSC		~~Southampton biomass power station~~ Wyoming Public Service Commission
~~Southern~~ WUTC		~~The legal entity, The Southern Company, one or more of its consolidated subsidiaries, or the entirety of The Southern~~Washington Utilities and Transportation Commission


Berkshire Hathaway Energy Company and its ~~consolidated~~ subsidiaries

~~Spring Grove 1~~	~~An approximately 98 MW proposed utility-scale solar power station located in Surry County, Virginia~~
~~Standard & Poor’s~~ Report of Independent Registered Public Accounting Firm		~~Standard & Poor’s Ratings Services, a division of S&P Global Inc.~~ 4
~~Summer~~ Consolidated Balance Sheets		~~V.C. Summer nuclear power station~~ 5
~~Supply Header Project~~ Consolidated Statements of Operations		~~A project previously intended for DETI to provide approximately 1,500,000 Dths of firm transportation service to various customers in connection with the Atlantic Coast Pipeline Project~~ 7
~~Surry~~ Consolidated Statements of Comprehensive Income		~~Surry nuclear power station~~ 8
~~Sycamore Solar~~ Consolidated Statements of Changes in Equity		~~A proposed 42 MW utility-scale solar power station located in Pittsylvania County, Virginia~~ 9
~~Terra Nova Renewable Partners~~ Consolidated Statements of Cash Flows		~~A partnership comprised primarily of institutional investors advised by J.P. Morgan Asset Management-Global Real Assets~~ 10
~~Three Cedars~~ Notes to Consolidated Financial Statements		~~Granite Mountain and Iron Springs, collectively~~ 11
~~Utah Commission~~ PacifiCorp and its subsidiaries		~~Utah Public Service Commission~~
~~VCEA~~ Report of Independent Registered Public Accounting Firm		~~Virginia Clean Economy Act, passed by the Virginia General Assembly in March 2020 and enacted on April 11, 2020~~ 48
~~VDEQ~~ Consolidated Balance Sheets		~~Virginia Department of Environmental Quality~~ 49
~~VEBA~~ Consolidated Statements of Operations		~~Voluntary Employees’ Beneficiary Association~~ 51
~~VIE~~ Consolidated Statements of Changes in Shareholders' Equity		~~Variable interest entity~~ 52
~~Virginia City Hybrid Energy Center~~ Consolidated Statements of Cash Flows		~~A 610 MW baseload carbon-capture compatible, clean coal powered electric generation facility in Wise County, Virginia~~ 53
~~Virginia Commission~~ Notes to Consolidated Financial Statements		~~Virginia State Corporation Commission~~ 54
~~Virginia Power~~ MidAmerican Energy Company		~~The legal entity, Virginia Electric~~
Report of Independent Registered Public Accounting Firm		71
Balance Sheets		72
Statements of Operations		74
Statements of Changes in Shareholder's Equity		75
Statements of Cash Flows		76
Notes to Financial Statements		77
MidAmerican Funding, LLC and ~~Power Company, one or more~~its subsidiaries
Report of ~~its consolidated subsidiaries or operating segment, or the entirety~~Independent Registered Public Accounting Firm		85
Consolidated Balance Sheets		86
Consolidated Statements of ~~Virginia Electric and~~Operations		88
Consolidated Statements of Changes in Member's Equity		89
Consolidated Statements of Cash Flows		90
Notes to Consolidated Financial Statements		91
Nevada Power Company and its ~~consolidated~~ subsidiaries
~~VOC~~ Report of Independent Registered Public Accounting Firm		~~Volatile organic compounds~~ 106
~~Warren County~~ Consolidated Balance Sheets		~~A 1,350 MW combined-cycle, natural gas-fired power station in Warren County, Virginia~~ 107
~~WECTEC~~ Consolidated Statements of Operations		~~WECTEC Global Project Services, Inc., a wholly-owned subsidiary of Westinghouse~~ 108
~~West Virginia Commission~~ Consolidated Statements of Changes in Shareholder's Equity		~~Public Service Commission of West Virginia~~ 109
~~Westinghouse~~ Consolidated Statements of Cash Flows		~~Westinghouse Electric Company LLC~~ 110
~~Wexpro~~ Notes to Consolidated Financial Statements		~~The legal entity, Wexpro Company, one or more of its consolidated subsidiaries, or the entirety of Wexpro~~ 111
Sierra Pacific Power Company and its ~~consolidated~~ subsidiaries
~~Whitehouse Solar~~ Report of Independent Registered Public Accounting Firm		~~A 20 MW utility-scale solar power station in Louisa County, Virginia~~ 122
~~White River Hub~~ Consolidated Balance Sheets		~~White River Hub, LLC~~ 123
~~Woodland Solar~~ Consolidated Statements of Operations		~~A 19 MW utility-scale solar power station in Isle of Wight County, Virginia~~ 124
~~Wrangler~~ Consolidated Statements of Changes in Shareholder's Equity		~~Wrangler Retail~~ 125
Consolidated Statements of Cash Flows		126
Notes to Financial Statements		127
Eastern Energy Gas Holdings, LLC ~~a partnership between Dominion Energy~~ and ~~Interstate Gas Supply, Inc.~~ its subsidiaries
~~Wyoming Commission~~ Report of Independent Registered Public Accounting Firm		~~Wyoming Public Service Commission~~ 141
Consolidated Balance Sheets		142
Consolidated Statements of Operations		144
Consolidated Statements of Comprehensive Income		145
Consolidated Statements of Changes in Equity		146
Consolidated Statements of Cash Flows		147
Notes to Consolidated Financial Statements		148

	Three Months Ended June 30,					Six Months Ended June 30,
	2020			2019		2020			2019
(millions, except per share amounts)
Operating Revenue⁽¹⁾	$	3,585		$	3,970	$	8,081		$	7,828
Operating Expenses
Electric fuel and other energy-related purchases		505			718		1,173			1,509
Purchased electric capacity		11			24		13			63
Purchased gas		74			227		501			957
Other operations and maintenance		995			1,283		2,038			2,285
Depreciation, depletion and amortization		673			661		1,346			1,312
Other taxes		256			284		540			576
Impairment of assets and other charges		531			312		1,299			1,147
Total operating expenses		3,045			3,509		6,910			7,849
Income (loss) from operations		540			461		1,171			(21	)
Earnings (loss) from equity method investees		(2,281	)		39		(2,228	)		80
Other income		502			53		50			400
Interest and related charges		449			452		939			921
Income (loss) from operations including noncontrolling interests before income tax expense (benefit)		(1,688	)		101		(1,946	)		(462	)
Income tax expense (benefit)		(556	)		43		(575	)		157
Net Income (Loss) Including Noncontrolling Interests		(1,132	)		58		(1,371	)		(619	)
Noncontrolling Interests		37			4		68			7
Net Income (Loss) Attributable to Dominion Energy	$	(1,169	)	$	54	$	(1,439	)	$	(626	)
Earnings Per Common Share
Net Income (Loss) attributable to Dominion Energy - Basic	$	(1.41	)	$	0.07	$	(1.75	)	$	(0.78	)
Net Income (Loss) attributable to Dominion Energy - Diluted		(1.41	)		0.05		(1.75	)		(0.78	)

	June 30, 2020			December 31, 2019⁽¹⁾
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	675		$	166
Customer receivables (less allowance for doubtful accounts of $44 and $20)		2,040			2,278
Other receivables (less allowance for doubtful accounts of $3 at both dates)⁽²⁾		233			367
Inventories		1,735			1,742
Prepayments		589			328
Regulatory assets		616			879
Other		236			328
Total current assets		6,124			6,088
Investments
Nuclear decommissioning trust funds		6,018			6,192
Investment in equity method affiliates		584			1,646
Other		382			379
Total investments		6,984			8,217
Property, Plant and Equipment
Property, plant and equipment		96,527			97,466
Accumulated depreciation, depletion and amortization		(28,547	)		(28,384	)
Total property, plant and equipment, net		67,980			69,082
Deferred Charges and Other Assets
Goodwill		8,946			8,946
Regulatory assets		9,438			7,687
Other		4,256			3,803
Total deferred charges and other assets		22,640			20,436
Total assets	$	103,728		$	103,823

	Preferred Stock				Common Stock					Dominion Energy Shareholders						Total
	Shares		Amount		Shares		Amount			Retained Earnings			AOCI			Shareholders' Equity			Noncontrolling Interests			Total Equity
(millions, except per share amounts)
March 31, 2019		—	$	—		802	$	20,834		$	7,806		$	(1,731	)	$	26,909		$	690		$	27,599
Net income including noncontrolling interests											54						54			4			58
Issuance of stock		2		1,596		1		78									1,674						1,674
Stock purchase contract component of 2019 Equity Units⁽¹⁾								(264	)								(264	)					(264	)
Stock awards (net of change in unearned compensation)								12									12						12
Dividends ($0.9175 per common share) and distributions											(736	)					(736	)		(10	)		(746	)
Other comprehensive income, net of tax														48			48						48
June 30, 2019		2	$	1,596		803	$	20,660		$	7,124		$	(1,683	)	$	27,697		$	684		$	28,381


March 31, 2020		2	$	2,387		839	$	23,902		$	6,455		$	(2,018	)	$	30,726		$	2,026		$	32,752
Net income (loss) including noncontrolling interests											(1,169	)					(1,169	)		37			(1,132	)
Issuance of stock						1		70									70						70
Stock awards (net of change in unearned compensation)								13									13						13
Preferred stock dividends⁽¹⁾											(16	)					(16	)					(16	)
Common stock dividends ($0.940 per share) and distributions											(789	)					(789	)		(50	)		(839	)
Other comprehensive income, net of tax														38			38						38
Other								(1	)		(1	)					(2	)					(2	)
June 30, 2020		2	$	2,387		840	$	23,984		$	4,480		$	(1,980	)	$	28,871		$	2,013		$	30,884

	Predecessor Equity			Membership Interests			AOCI			Total Members' Equity			Noncontrolling Interests			Total
(millions)
March 31, 2019	$	2,938		$	4,682		$	(191	)	$	7,429		$	1,432		$	8,861
Net income		72			47						119			30			149
Dividends and distributions		(153	)								(153	)		(36	)		(189	)
Other comprehensive income, net of tax								5			5						5
Other		2									2						2
June 30, 2019	$	2,859		$	4,729		$	(186	)	$	7,402		$	1,426		$	8,828

March 31, 2020	$	—		$	8,968		$	(271	)	$	8,697		$	1,381		$	10,078
Net income (loss)					(198	)					(198	)		32			(166	)
Dividends and distributions					(1,418	)					(1,418	)		(38	)		(1,456	)
June 30, 2020	$	—		$	7,352		$	(271	)	$	7,081		$	1,375		$	8,456

	Three Months Ended June 30, 2019⁽¹⁾		Six Months Ended June 30, 2019⁽¹⁾
(millions, except EPS)
Operating Revenue	$	3,970	$	8,835
Net income attributable to Dominion Energy		392		962
Earnings Per Common Share – Basic	$	0.49	$	1.21
Earnings Per Common Share – Diluted	$	0.47	$	1.19

	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019
(millions)
Operating revenue	$	154	$	383
Depreciation and amortization		22		43
Other operating expenses		128		277
Other income		18		37
Interest and related charges		8		18
Income tax expense		3		17
Net income from discontinued operations	$	11	$	65

	Dominion Energy						Virginia Power						Dominion Energy Gas
Six Months Ended June 30,	2020			2019			2020			2019			2020				2019
U.S. statutory rate		21.0	%		21.0	%		21.0	%		21.0	%		21.0	%			21.0	%
Increases (reductions) resulting from:
State taxes, net of federal benefit		5.6			0.7			4.9			4.7			(255.3	)			3.0
Investment tax credits		3.9			(3.8	)		(11.3	)		(5.2	)		—				—
Production tax credits		0.3			(1.1	)		(2.0	)		(0.8	)		—				—
Reversal of excess deferred income taxes		1.5			(6.9	)		(0.8	)		(4.2	)		(68.4	)			(0.9	)
Write-off of regulatory assets		(4.2	)		(41.6	)		—			—			189.4				—
AFUDC - equity		0.5			(1.9	)		(0.6	)		(0.1	)		(36.8	)			(0.5	)
Other, net		0.9			(0.3	)		1.1			0.4			(467.1	)	⁽¹⁾		(4.3	)	⁽¹⁾
Effective tax rate		29.5	%		(33.9	)%		12.3	%		15.8	%		(617.2	)%			18.3	%

	Deferred gains and losses on derivatives- hedging activities			Unrealized gains and losses on investment securities			Unrecognized pension and other postretirement benefit costs			Other comprehensive loss from equity method investees			Total
(millions)
Three Months Ended June 30, 2020
Beginning balance	$	(651	)	$	37		$	(1,402	)	$	(2	)	$	(2,018	)
Other comprehensive income before reclassifications: gains (losses)		2			19			(1	)		—			20
Amounts reclassified from AOCI: (gains) losses⁽¹⁾		5			(5	)		18			—			18
Net current period other comprehensive income (loss)		7			14			17			—			38
Ending balance	$	(644	)	$	51		$	(1,385	)	$	(2	)	$	(1,980	)
Three Months Ended June 30, 2019
Beginning balance	$	(290	)	$	18		$	(1,457	)	$	(2	)	$	(1,731	)
Other comprehensive income before reclassifications: gains (losses)		(78	)		13			113			—			48
Amounts reclassified from AOCI: (gains) losses⁽¹⁾		(21	)		(1	)		22			—			—
Net current period other comprehensive income (loss)		(99	)		12			135			—			48
Ending balance	$	(389	)	$	30		$	(1,322	)	$	(2	)	$	(1,683	)
Six Months Ended June 30, 2020
Beginning balance	$	(407	)	$	37		$	(1,421	)	$	(2	)	$	(1,793	)
Other comprehensive income before reclassifications: gains (losses)		(264	)		28			(1	)		—			(237	)
Amounts reclassified from AOCI: (gains) losses⁽¹⁾		27			(14	)		37			—			50
Net current period other comprehensive income (loss)		(237	)		14			36			—			(187	)
Ending balance	$	(644	)	$	51		$	(1,385	)	$	(2	)	$	(1,980	)
Six Months Ended June 30, 2019
Beginning balance	$	(235	)	$	2		$	(1,465	)	$	(2	)	$	(1,700	)
Other comprehensive income before reclassifications: gains (losses)		(102	)		29			113			—			40
Amounts reclassified from AOCI: (gains) losses⁽¹⁾		(52	)		(1	)		30			—			(23	)
Net current period other comprehensive income (loss)		(154	)		28			143			—			17
Ending balance	$	(389	)	$	30		$	(1,322	)	$	(2	)	$	(1,683	)

Details about AOCI components	Amounts reclassified from AOCI			Affected line item in the Consolidated Statements of Income
(millions)
Three Months Ended June 30, 2020
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(9	)	Operating revenue
Interest rate contracts		22		Interest and related charges
Foreign currency contracts		(6	)	Other income
Total		7
Tax		(2	)	Income tax expense (benefit)
Total, net of tax	$	5
Unrealized (gains) and losses on investment securities:
Realized (gains) losses on sale of securities	$	(5	)	Other income
Total		(5	)
Tax		—		Income tax expense (benefit)
Total, net of tax	$	(5	)
Unrecognized pension and other postretirement benefit costs:
Amortization of prior-service costs (credits)	$	(5	)	Other income
Amortization of actuarial losses		31		Other income
Total		26
Tax		(8	)	Income tax expense (benefit)
Total, net of tax	$	18
Three Months Ended June 30, 2019
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(38	)	Operating revenue
Interest rate contracts		13		Interest and related charges
Foreign currency contracts		(4	)	Other income
Total		(29	)
Tax		8		Income tax expense (benefit)
Total, net of tax	$	(21	)
Unrealized (gains) and losses on investment securities:
Realized (gains) losses on sale of securities	$	(1	)	Other income
Total		(1	)
Tax		—		Income tax expense (benefit)
Total, net of tax	$	(1	)
Unrecognized pension and other postretirement benefit costs:
Amortization of prior-service costs (credits)	$	(8	)	Other income
Amortization of actuarial losses		27		Other income
Total		19
Tax		3		Income tax expense (benefit)
Total, net of tax	$	22

	Deferred gains and losses on derivatives- hedging activities			Unrealized gains and losses on investment securities			Total
(millions)
Three Months Ended June 30, 2020
Beginning balance	$	(79	)	$	4		$	(75	)
Other comprehensive income before reclassifications: gains (losses)		1			6			7
Amounts reclassified from AOCI: (gains) losses⁽¹⁾		—			(2	)		(2	)
Net current period other comprehensive income (loss)		1			4			5
Ending balance	$	(78	)	$	8		$	(70	)
Three Months Ended June 30, 2019
Beginning balance	$	(20	)	$	3		$	(17	)
Other comprehensive income before reclassifications: gains (losses)		(11	)		2			(9	)
Amounts reclassified from AOCI: (gains) losses⁽¹⁾		1			(1	)		—
Net current period other comprehensive income (loss)		(10	)		1			(9	)
Ending balance	$	(30	)	$	4		$	(26	)
Six Months Ended June 30, 2020
Beginning balance	$	(34	)	$	5		$	(29	)
Other comprehensive income before reclassifications: gains (losses)		(44	)		4			(40	)
Amounts reclassified from AOCI: (gains) losses⁽¹⁾		—			(1	)		(1	)
Net current period other comprehensive income (loss)		(44	)		3			(41	)
Ending balance	$	(78	)	$	8		$	(70	)
Six Months Ended June 30, 2019
Beginning balance	$	(13	)	$	1		$	(12	)
Other comprehensive income before reclassifications: gains (losses)		(18	)		4			(14	)
Amounts reclassified from AOCI: (gains) losses⁽¹⁾		1			(1	)		—
Net current period other comprehensive income (loss)		(17	)		3			(14	)
Ending balance	$	(30	)	$	4		$	(26	)

	Deferred gains and losses on derivatives- hedging activities			Unrecognized pension costs			Total
(millions)
Three Months Ended June 30, 2020
Beginning balance	$	(166	)	$	(105	)	$	(271	)
Amounts reclassified from AOCI: (gains) losses⁽¹⁾		(2	)		2			—
Net current period other comprehensive income (loss)		(2	)		2			—
Ending balance	$	(168	)	$	(103	)	$	(271	)
Three Months Ended June 30, 2019
Beginning balance	$	(48	)	$	(143	)	$	(191	)
Other comprehensive income before reclassifications: gains (losses)		(24	)		29			5
Amounts reclassified from AOCI: (gains) losses⁽¹⁾		(2	)		2			—
Net current period other comprehensive income (loss)		(26	)		31			5
Ending balance	$	(74	)	$	(112	)	$	(186	)
Six Months Ended June 30, 2020
Beginning balance	$	(81	)	$	(106	)	$	(187	)
Other comprehensive income before reclassifications: gains (losses)		(91	)		—			(91	)
Amounts reclassified from AOCI: (gains) losses⁽¹⁾		4			3			7
Net current period other comprehensive income (loss)		(87	)		3			(84	)
Ending balance	$	(168	)	$	(103	)	$	(271	)
Six Months Ended June 30, 2019
Beginning balance	$	(25	)	$	(144	)	$	(169	)
Other comprehensive income before reclassifications: gains (losses)		(51	)		29			(22	)
Amounts reclassified from AOCI: (gains) losses⁽¹⁾		1			3			4
Net current period other comprehensive income (loss)		(50	)		32			(18	)
Less other comprehensive income (loss) attributable to noncontrolling interest		(1	)		—			(1	)
Ending balance	$	(74	)	$	(112	)	$	(186	)

	Fair Value (millions)		Valuation Techniques	Unobservable Input		Range	Weighted Average⁽¹⁾
Assets
Physical and financial forwards:
Natural gas⁽²⁾	$	112	Discounted cash flow	Market price (per Dth)	⁽³⁾	(2) - 3		(1	)
FTRs		18	Discounted cash flow	Market price (per MWh)	⁽³⁾	(1) - 5		1
Total assets	$	130
Liabilities
Financial forwards:
FTRs	$	5	Discounted cash flow	Market price (per MWh)	⁽³⁾	(5) - 5		—
Physical options:
Natural gas		2	Option model	Market price (per Dth)	⁽³⁾	1 - 5		2
				Price volatility	⁽⁴⁾	56% - 72%		66	%
Total liabilities	$	7

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2020			2019			2020			2019
(millions)
Beginning balance	$	43		$	53		$	(37	)	$	64
Total realized and unrealized gains (losses):
Included in earnings:
Operating revenue		—			3			—			2
Purchased gas		—			1			—			1
Electric fuel and other energy-related purchases		(4	)		(3	)		(26	)		(7	)
Included in regulatory assets/liabilities		80			18			160			25
Settlements		4			3			26			2
Purchases		—			—			—			(10	)
Transfers out of Level 3		—			—			—			(2	)
Ending balance	$	123		$	75		$	123		$	75
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets/liabilities still held at the reporting date:
Operating revenue	$	—		$	2		$	—		$	2
Purchased gas		—			1			—			1
Total	$	—		$	3		$	—		$	3

	June 30, 2020				December 31, 2019
	Carrying Amount		Estimated Fair Value⁽¹⁾		Carrying Amount		Estimated Fair Value⁽¹⁾
(millions)
Dominion Energy
Long-term debt⁽²⁾	$	36,060	$	42,151	$	32,055	$	36,155
Supplemental 364-Day credit facility borrowings		225		225		—		—
Junior subordinated notes⁽³⁾		3,408		3,554		4,797		4,953
Virginia Power
Long-term debt⁽³⁾	$	12,328	$	15,189	$	12,326	$	14,281
Dominion Energy Gas
Long-term debt⁽⁴⁾	$	5,523	$	5,891	$	5,520	$	5,738

	June 30, 2020								December 31, 2019
	Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Gross Assets Presented in the Consolidated Balance Sheet⁽¹⁾		Financial Instruments		Cash Collateral Received		Net Amounts		Gross Assets Presented in the Consolidated Balance Sheet⁽¹⁾		Financial Instruments		Cash Collateral Received		Net Amounts
(millions)
Commodity contracts:
Over-the-counter	$	136	$	9	$	—	$	127	$	35	$	21	$	—	$	14
Exchange		45		20		7		18		37		21		—		16
Interest rate contracts:
Over-the-counter		34		14		—		20		11		3		—		8
Foreign currency contracts:
Over-the-counter		—		—		—		—		8		8		—		—
Total derivatives, subject to a master netting or similar arrangement	$	215	$	43	$	7	$	165	$	91	$	53	$	—	$	38

	Current		Noncurrent
Natural Gas (bcf):
Fixed price⁽¹⁾		69		32
Basis		236		538
Electricity (MWh):
Fixed price		4,964,045		2,775,850
FTRs		101,087,887		—
Liquids (Gal)⁽²⁾		26,460,000		—
Interest rate⁽³⁾	$	1,950,000,000	$	6,576,403,434
Foreign currency⁽³⁾	€	-	€	250,000,000

	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax			Maximum Term
(millions)
Commodities:
Gas	$	(2	)	$	(2	)	18 months
Electricity		8			8		6 months
NGL		—			—		6 months
Interest rate		(640	)		(59	)	378 months
Foreign currency		(10	)		(4	)	72 months
Total	$	(644	)	$	(57	)

	Carrying Amount of the Hedged Asset (Liability)⁽¹⁾						Cumulative Amount of Fair Value Hedging Adjustments Included in the Carrying Amount of the Hedged Assets (Liabilities)⁽²⁾
	June 30, 2020			December 31, 2019			June 30, 2020			December 31, 2019
(millions)
Long-term debt	$	(1,154	)	$	(1,154	)	$	(4	)	$	(4	)

	Fair Value – Derivatives under Hedge Accounting		Fair Value – Derivatives not under Hedge Accounting		Total Fair Value
(millions)
June 30, 2020
ASSETS
Current Assets
Commodity	$	—	$	73	$	73
Interest rate		—		8		8
Total current derivative assets⁽¹⁾		—		81		81
Noncurrent Assets
Commodity		—		109		109
Interest rate		—		26		26
Total noncurrent derivative assets⁽²⁾		—		135		135
Total derivative assets	$	—	$	216	$	216
LIABILITIES
Current Liabilities
Commodity	$	—	$	42	$	42
Interest rate		514		25		539
Foreign currency		5		—		5
Total current derivative liabilities		519		67		586
Noncurrent Liabilities
Commodity		—		8		8
Interest rate		655		78		733
Foreign currency		7		—		7
Total noncurrent derivative liabilities		662		86		748
Total derivative liabilities	$	1,181	$	153	$	1,334
December 31, 2019
ASSETS
Current Assets
Commodity	$	30	$	37	$	67
Interest rate		1		—		1
Total current derivative assets⁽¹⁾		31		37		68
Noncurrent Assets
Commodity		1		6		7
Interest rate		10		—		10
Foreign currency		8		—		8
Total noncurrent derivative assets⁽²⁾		19		6		25
Total derivative assets	$	50	$	43	$	93
LIABILITIES
Current Liabilities
Commodity	$	6	$	77	$	83
Interest rate		321		1		322
Foreign currency		3		—		3
Total current derivative liabilities		330		78		408
Noncurrent Liabilities
Commodity		1		47		48
Interest rate		267		17		284
Total noncurrent derivative liabilities		268		64		332
Total derivative liabilities	$	598	$	142	$	740

Derivatives in cash flow hedging relationships	Amount of Gain (Loss) Recognized in AOCI on Derivatives⁽¹⁾			Amount of Gain (Loss) Reclassified From AOCI to Income			Increase (Decrease) in Derivatives Subject to Regulatory Treatment⁽²⁾
(millions)
Three Months Ended June 30, 2020
Derivative type and location of gains (losses):
Commodity:
Operating revenue				$	9
Purchased gas					—
Total commodity	$	—		$	9		$	—
Interest rate⁽³⁾		—			(22	)		14
Foreign currency⁽⁴⁾		6			6			—
Total	$	6		$	(7	)	$	14
Three Months Ended June 30, 2019
Derivative type and location of gains (losses):
Commodity:
Operating revenue				$	38
Total commodity	$	35		$	38		$	—
Interest rate⁽³⁾		(142	)		(13	)		(131	)
Foreign currency⁽⁴⁾		2			4			—
Total	$	(105	)	$	29		$	(131	)
Six Months Ended June 30, 2020
Derivative type and location of gains (losses):
Commodity:
Operating revenue				$	16
Purchased gas					(3	)
Electric fuel and other energy-related purchases					—
Total commodity	$	—		$	13		$	—
Interest rate⁽³⁾		(336	)		(49	)		(550	)
Foreign currency⁽⁴⁾		(17	)		—			—
Total	$	(353	)	$	(36	)	$	(550	)
Six Months Ended June 30, 2019
Derivative type and location of gains (losses):
Commodity:
Operating revenue				$	92
Purchased gas					3
Total commodity	$	101		$	95		$	—
Interest rate⁽³⁾		(226	)		(23	)		(215	)
Foreign currency⁽⁴⁾		(9	)		(2	)		—
Total	$	(134	)	$	70		$	(215	)

Derivatives not designated as hedging instruments	Amount of Gain (Loss) Recognized in Income on Derivatives⁽¹⁾
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2020			2019			2020			2019
(millions)
Derivative type and location of gains (losses):
Commodity:
Operating revenue	$	(10	)	$	27		$	55		$	30
Purchased gas		—			(11	)		(14	)		(8	)
Electric fuel and other energy-related purchases		(8	)		(3	)		(73	)		(12	)
Interest rate⁽²⁾		(25	)		—			(86	)		—
Total	$	(43	)	$	13		$	(118	)	$	10