CONSOLIDATED ~~BALANCE SHEETS—(Continued)~~

STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Unaudited)

September 30, 2017

December 31, 2016⁽¹⁾

(millions)

LIABILITIES AND EQUITY

Current Liabilities

Securities due within one year

$
2,788

$
1,709

Short-term debt

3,060

3,155

Accounts payable

757

1,000

Accrued interest, payroll and taxes

843

798

Regulatory liabilities

88

163

Other

1,023

1,290

Total current liabilities

8,559

8,115

Long-Term Debt

Long-term debt

25,529

24,878

Junior subordinated notes

3,980

2,980

Remarketable subordinated notes

1,377

2,373

Total long-term debt

30,886

30,231

Deferred Credits and Other Liabilities

Deferred income taxes and investment tax credits

9,379

8,602

Regulatory liabilities

2,906

2,622

Other

5,159

5,200

Total deferred credits and other liabilities

17,444

16,424

Total liabilities

56,889

54,770

Commitments and Contingencies (see Note 15)

Equity

Common stock – no par⁽²⁾

9,789

8,550

Retained earnings

7,119

6,854

Accumulated other comprehensive loss

(628
)

(799
)
Total common shareholders' equity

16,280

14,605

Noncontrolling interests

2,222

2,235

Total equity

18,502

16,840

Total liabilities and equity

$
75,391

$
71,610

~~(1)~~

~~Dominion Energy’s Consolidated Balance Sheet at December 31, 2016 has been derived from the audited Consolidated Balance Sheet at that date.~~

~~(2)~~

~~1 billion shares authorized; 644 million shares and 628 million shares outstanding at September 30, 2017 and December 31, 2016, respectively.~~

(Amounts in millions)


	Three-Month Periods
	Ended March 31,
		2023		2022

Net income (loss)		$	1,103	$	(20)

Other comprehensive income (loss), net of tax:
Unrecognized amounts on retirement benefits, net of tax of $(3) and $3		(4)		15
Foreign currency translation adjustment		99		(110)
Unrealized (losses) gains on cash flow hedges, net of tax of $(20) and $28		(55)		77
Total other comprehensive income (loss), net of tax		40		(18)

Comprehensive income (loss)		1,143		(38)
Comprehensive income attributable to noncontrolling interests		114		109
Comprehensive income (loss) attributable to BHE shareholders		$	1,029	$	(147)

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

(Unaudited)

Common Stock

Dominion Energy Shareholders

Total
Common

Shares

Amount

Retained Earnings

AOCI

Shareholders'
Equity

Noncontrolling
Interests

Total
Equity

(millions)

December 31,  2015

596

$
6,680

$
6,458

$
(474
)

$
12,664

$
938

$
13,602

Net income including noncontrolling interests

1,666

1,666

55

1,721

Contributions from SunEdison to Four Brothers
   and Three Cedars

—

178

178

Sale of interest in merchant solar projects

22

22

117

139

Purchase of Dominion Energy Midstream
   common units

(3
)

(3
)

(14
)

(17
)
Issuance of common stock

31

2,079

2,079

2,079

Stock awards (net of change in unearned
   compensation)

10

10

10

Present value of stock purchase contract
   payments related to RSNs

(191
)

(191
)

(191
)
Dividends and distributions

(1,287
)

(1,287
)

(39
)

(1,326
)
Other comprehensive income, net of tax

3

3

3

Other

(5
)

(5
)

(1
)

(6
)
September 30, 2016

627

$
8,592

$
6,837

$
(471
)

$
14,958

$
1,234

$
16,192

December 31, 2016

628

$
8,550

$
6,854

$
(799
)

$
14,605

$
2,235

$
16,840

Net income including noncontrolling interests

1,687

1,687

100

1,787

Contributions from NRG to Four Brothers and
   Three Cedars

—

9

9

Issuance of common stock

16

1,232

1,232

1,232

Stock awards (net of change in unearned
   compensation)

17

17

17

Dividends and distributions

(1,435
)

(1,435
)

(123
)

(1,558
)
Other comprehensive income, net of tax

171

171

171

Other

(10
)

13

.

3

1

4

September 30, 2017

644

$
9,789

$
7,119

$
(628
)

$
16,280

$
2,222

$
18,502

(Amounts in millions)


	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, 2021	$	1,650	$	—	$	6,374	$	(744)	$	40,754	$	(1,340)	$	3,895	$	50,589
Net (loss) income	—		—		—		—		(129)		—		109		(20)
Other comprehensive loss	—		—		—		—		—		(18)		—		(18)

Preferred stock dividend	—		—		—		—		(16)		—		—		(16)

Distributions	—		—		—		—		—		—		(116)		(116)


Other equity transactions	—		—		—		—		(1)		—		6		5
Balance, March 31, 2022	$	1,650	$	—	$	6,374	$	(744)	$	40,608	$	(1,358)	$	3,894	$	50,424














Balance, December 31, 2022	$	850	$	—	$	6,298	$	—	$	41,833	$	(2,149)	$	3,807	$	50,639
Net income	—		—		—		—		989		—		114		1,103
Other comprehensive income	—		—		—		—		—		40		—		40


Preferred stock dividend	—		—		—		—		(8)		—		—		(8)

Distributions	—		—		—		—		—		—		(125)		(125)
Contributions	—		—		—		—		—		—		2		2


Balance, March 31, 2023	$	850	$	—	$	6,298	$	—	$	42,814	$	(2,109)	$	3,798	$	51,651

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 CASH FLOWS

(Unaudited)

Nine Months Ended September 30,

2017

2016

(millions)

Operating Activities

Net income including noncontrolling interests

$
1,787

$
1,721

Adjustments to reconcile net income including noncontrolling interests to net cash
provided by operating activities:

Depreciation, depletion and amortization (including nuclear fuel)

1,649

1,325

Deferred income taxes and investment tax credits

652

481

Proceeds from assignment of tower rental portfolio

91

—

Gains on the sales of assets and equity method investment in Iroquois

(61
)

(50
)
Contribution to pension plan

(75
)

—

Other adjustments

(95
)

(78
)
Changes in:

Accounts receivable

247

19

Inventories

(34
)

(10
)
Deferred fuel and purchased gas costs, net

(81
)

84

Prepayments

34

71

Accounts payable

(158
)

(89
)
Accrued interest, payroll and taxes

61

205

Margin deposit assets and liabilities

51

1

Pension and other postretirement benefits

(132
)

(91
)
Other operating assets and liabilities

(272
)

(203
)
Net cash provided by operating activities

3,664

3,386

Investing Activities

Plant construction and other property additions (including nuclear fuel)

(4,122
)

(4,536
)
Acquisition of Dominion Energy Questar, net of cash acquired

—

(4,372
)
Acquisition of solar development projects

(343
)

(21
)
Proceeds from sales of securities

1,496

1,009

Purchases of securities

(1,555
)

(1,065
)
Contributions to equity method affiliates

(343
)

(124
)
Other

(6
)

80

Net cash used in investing activities

(4,873
)

(9,029
)
Financing Activities

Repayment of short-term debt, net

(95
)

(713
)
Issuance of short-term notes

—

1,200

Repayment and repurchase of short-term notes

(250
)

(600
)
Issuance of long-term debt

3,480

5,730

Repayment and repurchase of long-term debt

(1,529
)

(1,169
)
Proceeds from sale of interest in merchant solar projects

—

117

Contributions from NRG and SunEdison to Four Brothers and Three Cedars

9

178

Issuance of common stock

1,233

2,079

Common dividend payments

(1,435
)

(1,287
)
Other

(238
)

(248
)
Net cash provided by financing activities

1,175

5,287

Decrease in cash and cash equivalents

(34
)

(356
)
Cash and cash equivalents at beginning of period

261

607

Cash and cash equivalents at end of period

$
227

$
251

Supplemental Cash Flow Information

Significant noncash investing and financing activities⁽¹⁾:

Accrued capital expenditures

$
355

$
341

(Amounts in millions)


	Three-Month Periods
	Ended March 31,
	2023		2022
Cash flows from operating activities:
Net income (loss)	$	1,103	$	(20)
Adjustments to reconcile net income (loss) to net cash flows from operating activities:
(Gains) losses on marketable securities, net	(699)		1,257
Depreciation and amortization	1,063		1,022
Allowance for equity funds	(49)		(38)
Equity (income) loss, net of distributions	68		88
Net power cost deferrals	(504)		(72)
Amortization of net power cost deferrals	130		47
Other changes in regulatory assets and liabilities	(26)		(17)
Deferred income taxes and investment tax credits, net	(11)		(203)
Other, net	15		6
Changes in other operating assets and liabilities, net of effects from acquisitions:
Trade receivables and other assets	120		333
Derivative collateral, net	(225)		85
Pension and other postretirement benefit plans	(7)		(11)
Accrued property, income and other taxes, net	(177)		(347)
Accounts payable and other liabilities	294		91
Net cash flows from operating activities	1,095		2,221

Cash flows from investing activities:
Capital expenditures	(1,848)		(1,553)

Purchases of marketable securities	(106)		(170)
Proceeds from sales of marketable securities	1,091		149
Purchases of U.S. Treasury Bills	(1,519)		—
Proceeds from maturities of U.S. Treasury Bills	623		—
Equity method investments	(19)		(17)
Other, net	—		19
Net cash flows from investing activities	(1,778)		(1,572)

Cash flows from financing activities:





Repayments of BHE senior debt	(400)		—
Proceeds from subsidiary debt	—		405
Repayments of subsidiary debt	(136)		(193)
Net proceeds from (repayments of) short-term debt	699		(165)

Distributions to noncontrolling interests	(126)		(117)

Other, net	(17)		(240)
Net cash flows from financing activities	20		(310)

Effect of exchange rate changes	1		(1)

Net change in cash and cash equivalents and restricted cash and cash equivalents	(662)		338
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	1,817		1,244
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	1,155	$	1,582

~~(1)~~

~~See Note 14 for noncash financing activities related to the remarketing of RSNs.~~

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

these consolidated financial statements.

~~VIRGINIA ELECTRIC~~

BERKSHIRE HATHAWAY ENERGY COMPANY AND ~~POWER COMPANY~~

~~CONSOLIDATED STATEMENTS OF INCOME~~

~~(Unaudited)~~

Three Months Ended September 30,

Nine Months Ended September 30,

2017

2016

2017

2016

(millions)

Operating Revenue⁽¹⁾

$
2,154

$
2,211

$
5,732

$
5,877

Operating Expenses

Electric fuel and other energy-related purchases⁽¹⁾

549

516

1,414

1,527

Purchased (excess) electric capacity

21

(6
)

(8
)

107

Other operations and maintenance:

Affiliated suppliers

76

73

229

238

Other

297

370

897

1,041

Depreciation and amortization

288

270

854

765

Other taxes

��
76

74

233

218

Total operating expenses

1,307

1,297

3,619

3,896

Income from operations

847

914

2,113

1,981

Other income

13

13

57

47

Interest and related charges⁽¹⁾

128

118

373

345

Income before income tax expense

732

809

1,797

1,683

Income tax expense

273

306

664

637

Net Income

$
459

$
503

$
1,133

$
1,046

SUBSIDIARIES

~~(1)~~

~~See Note 17 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~~

~~(Unaudited)~~

September 30, 2017

December 31, 2016⁽¹⁾

(millions)

ASSETS

Current Assets

Cash and cash equivalents

$
16

$
11

Customer receivables (less allowance for doubtful accounts of $9 and $10)

920

892

Other receivables (less allowance for doubtful accounts of $1 at both dates)

36

99

Affiliated receivables

1

112

Inventories (average cost method)

853

853

Other⁽²⁾

309

281

Total current assets

2,135

2,248

Investments

Nuclear decommissioning trust funds

2,292

2,106

Other

3

3

Total investments

2,295

2,109

Property, Plant and Equipment

Property, plant and equipment

41,813

40,030

Accumulated depreciation and amortization

(13,144
)

(12,436
)
Total property, plant and equipment, net

28,669

27,594

Deferred Charges and Other Assets

Regulatory assets

838

770

Pension and other postretirement benefit assets⁽²⁾

182

130

Other⁽²⁾

462

457

Total deferred charges and other assets

1,482

1,357

Total assets

$
34,581

$
33,308

~~(1)~~

~~Virginia Power’s Consolidated Balance Sheet at December 31, 2016 has been derived from the audited Consolidated Balance Sheet at that date.~~

~~(2)~~

~~See Note 17 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)~~

September 30, 2017

December 31, 2016⁽¹⁾

(millions)

LIABILITIES AND SHAREHOLDER’S EQUITY

Current Liabilities

Securities due within one year

$
851

$
678

Short-term debt

320

65

Accounts payable

337

444

Payables to affiliates

167

109

Affiliated current borrowings

36

262

Accrued interest, payroll and taxes

307

239

Other⁽²⁾

536

725

Total current liabilities

2,554

2,522

Long-Term Debt

10,495

9,852

Deferred Credits and Other Liabilities

Deferred income taxes and investment tax credits

5,357

5,103

Asset retirement obligations

1,300

1,262

Regulatory liabilities

2,202

1,962

Other⁽²⁾

863

742

Total deferred credits and other liabilities

9,722

9,069

Total liabilities

22,771

21,443

Commitments and Contingencies (see Note 15)

Common Shareholder’s Equity

Common stock – no par⁽³⁾

5,738

5,738

Other paid-in capital

1,113

1,113

Retained earnings

4,904

4,968

Accumulated other comprehensive income

55

46

Total common shareholder’s equity

11,810

11,865

Total liabilities and shareholder’s equity

$
34,581

$
33,308

~~(1)~~

~~Virginia Power’s Consolidated Balance Sheet at December 31, 2016 has been derived from the audited Consolidated Balance Sheet at that date.~~

~~(2)~~

~~See Note 17 for amounts attributable to affiliates.~~

~~(3)~~

~~500,000 shares authorized; 274,723 shares outstanding at September 30, 2017 and December 31, 2016.~~

~~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)~~

Nine Months Ended September 30,

2017

2016

(millions)

Operating Activities

Net income

$
1,133

$
1,046

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

Depreciation and amortization (including nuclear fuel)

999

903

Deferred income taxes and investment tax credits

262

369

Proceeds from assignment of tower rental portfolio

91

—

Other adjustments

(28
)

(15
)
Changes in:

Accounts receivable

32

(99
)
Affiliated receivables and payables

159

306

Inventories

1

37

Prepayments

(3
)

15

Deferred fuel expenses, net

(48
)

79

Accounts payable

(33
)

4

Accrued interest, payroll and taxes

67

131

Other operating assets and liabilities

(162
)

8

Net cash provided by operating activities

2,470

2,784

Investing Activities

Plant construction and other property additions

(1,917
)

(1,835
)
Purchases of nuclear fuel

(133
)

(106
)
Proceeds from sales of securities

654

478

Purchases of securities

(681
)

(513
)
Other

(29
)

(11
)
Net cash used in investing activities

(2,106
)

(1,987
)
Financing Activities

Issuance (repayment) of short-term debt, net

255

(691
)
Repayment of affiliated current borrowings, net

(226
)

(376
)
Issuance of long-term debt

1,500

750

Repayment of long-term debt

(679
)

(476
)
Common dividend payments to parent

(1,199
)

—

Other

(10
)

(4
)
Net cash used in financing activities

(359
)

(797
)
Increase in cash and cash equivalents

5

—

Cash and cash equivalents at beginning of period

11

18

Cash and cash equivalents at end of period

$
16

$
18

Supplemental Cash Flow Information

Significant noncash investing activities:

Accrued capital expenditures

$
158

$
209

~~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 September 30,

Nine Months Ended September 30,

2017

2016

2017

2016

(millions)

Operating Revenue⁽¹⁾

$
401

$
382

$
1,313

$
1,181

Operating Expenses

Purchased gas⁽¹⁾

19

21

100

71

Other energy-related purchases

4

4

11

8

Other operations and maintenance:

Affiliated suppliers

20

20

65

63

Other

53

113

312

268

Depreciation and amortization

57

55

167

150

Other taxes

42

36

139

127

Total operating expenses

195

249

794

687

Income from operations

206

133

519

494

Earnings from equity method investee

4

5

15

14

Other income

6

2

16

8

Interest and related charges⁽¹⁾

25

23

72

68

Income from operations before income taxes

191

117

478

448

Income tax expense

74

34

176

162

Net Income

$
117

$
83

$
302

$
286

~~(1)~~

~~See Note 17 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 September 30,

Nine Months Ended September 30,

2017

2016

2017

2016

(millions)

Net income

$
117

$
83

$
302

$
286

Other comprehensive income (loss), net of taxes:

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

1

9

3

(6
)
Amounts reclassified to net income:

Net derivative gains-hedging activities⁽²⁾

(4
)

(1
)

(5
)

(3
)
Net pension and other postretirement benefit costs⁽³⁾

1

1

3

2

Total other comprehensive income (loss)

(2
)

9

1

(7
)
Comprehensive income

$
115

$
92

$
303

$
279

~~(1)~~

Net of $(1) million and $(3) million tax for the three months ended September 30, 2017 and 2016, respectively, and net of $(2) million and $5 million tax for the nine months ended September 30, 2017 and 2016, respectively.

~~(2)~~

Net of $3 million and $2 million tax for the three months ended September 30, 2017 and 2016, respectively, and net of $3 million and $2 million tax for the nine months ended September 30, 2017 and 2016, respectively.

~~(3)~~

~~Net of $(1) million tax for both the three months ended September 30, 2017 and 2016, and net of $(2) million tax for both the nine months ended September 30, 2017 and 2016.~~

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

~~DOMINION ENERGY GAS HOLDINGS, LLC~~

~~CONSOLIDATED BALANCE SHEETS~~

~~(Unaudited)~~

September 30, 2017

December 31, 2016⁽¹⁾

(millions)

ASSETS

Current Assets

Cash and cash equivalents

$
13

$
23

Restricted cash

29

20

Customer receivables (less allowance for doubtful accounts of $1 at both dates)

190

281

Other receivables (less allowance for doubtful accounts of $1 at both dates)⁽²⁾

72

13

Affiliated receivables

17

17

Inventories

90

70

Other⁽²⁾

110

158

Total current assets

521

582

Investments

97

99

Property, Plant and Equipment

Property, plant and equipment

10,971

10,475

Accumulated depreciation and amortization

(2,978
)

(2,851
)
Total property, plant and equipment, net

7,993

7,624

Deferred Charges and Other Assets

Pension and other postretirement benefit assets⁽²⁾

1,714

1,557

Other⁽²⁾

1,303

1,280

Total deferred charges and other assets

3,017

2,837

Total assets

$
11,628

$
11,142

~~(1)~~

~~Dominion Energy Gas’ Consolidated Balance Sheet at December 31, 2016 has been derived from the audited Consolidated Balance Sheet at that date.~~

~~(2)~~

~~See Note 17 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)~~

September 30, 2017

December 31, 2016⁽¹⁾

(millions)

LIABILITIES AND EQUITY

Current Liabilities

Short-term debt

$
620

$
460

Accounts payable

161

221

Payables to affiliates

18

29

Affiliated current borrowings

34

118

Accrued interest, payroll and taxes

197

225

Other⁽²⁾

157

162

Total current liabilities

1,187

1,215

Long-Term Debt

3,564

3,528

Deferred Credits and Other Liabilities

Deferred income taxes and investment tax credits

2,622

2,438

Other⁽²⁾

429

425

Total deferred credits and other liabilities

3,051

2,863

Total liabilities

7,802

7,606

Commitments and Contingencies (see Note 15)

Equity

Membership interests

3,948

3,659

Accumulated other comprehensive loss

(122
)

(123
)
Total equity

3,826

3,536

Total liabilities and equity

$
11,628

$
11,142

~~(1)~~

~~Dominion Energy Gas’ Consolidated Balance Sheet at December 31, 2016 has been derived from the audited Consolidated Balance Sheet at that date.~~

~~(2)~~

~~See Note 17 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 CASH FLOWS~~

~~(Unaudited)~~

Nine Months Ended September 30,

2017

2016

(millions)

Operating Activities

Net income

$
302

$
286

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

Gains on the sales of assets and equity method investment in Iroquois

(61
)

(50
)
Depreciation and amortization

167

150

Deferred income taxes and investment tax credits

176

204

Other adjustments

(9
)

3

Changes in:

Accounts receivable

88

56

Affiliated receivables and payables

(11
)

91

Inventories

(20
)

(17
)
Deferred purchased gas costs, net

11

7

Prepayments

39

15

Accounts payable

(68
)

(76
)
Accrued interest, payroll and taxes

(28
)

(7
)
Pension and other postretirement benefits

(98
)

(97
)
Other operating assets and liabilities

(13
)

(62
)
Net cash provided by operating activities

475

503

Investing Activities

Plant construction and other property additions

(535
)

(610
)
Proceeds from sale of equity method investment in Iroquois

—

7

Proceeds from assignments of shale development rights

5

10

Other

(16
)

(10
)
Net cash used in investing activities

(546
)

(603
)
Financing Activities

Issuance (repayment) of short-term debt, net

160

(331
)
Issuance of long-term debt

—

680

Repayment of affiliated current borrowings, net

(84
)

(95
)
Distribution payments to parent

(15
)

(150
)
Other

—

(9
)
Net cash provided by financing activities

61

95

Decrease in cash and cash equivalents

(10
)

(5
)
Cash and cash equivalents at beginning of period

23

13

Cash and cash equivalents at end of period

$
13

$
8

Supplemental Cash Flow Information

Significant noncash investing activities:

Accrued capital expenditures

$
54

$
42

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

~~COMBINED~~ NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(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. 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 and operated 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 eight 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 and its subsidiaries ("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 and its subsidiaries ("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 and its subsidiaries ("BHE Canada") (which primarily consists of AltaLink, L.P. ("AltaLink")) and BHE U.S. Transmission, LLC and its subsidiaries), BHE Renewables, LLC and its subsidiaries ("BHE Renewables") and HomeServices of America, Inc. and its subsidiaries ("HomeServices"). The Company, through ~~a regulated~~these locally managed and operated businesses, owns four utility companies in the U.S. serving customers in 11 states, two electricity distribution companies in Great Britain, five interstate natural gas ~~transmission~~ pipeline companies and ~~underground~~interests in a liquefied natural gas ("LNG") export, import and storage ~~system~~facility in the ~~Northeast, mid-Atlantic and Midwest states, regulated gas transportation and distribution operations~~U.S., an electric transmission business in ~~Ohio, and gas gathering and processing activities primarily~~Canada, interests in ~~West Virginia, Ohio and Pennsylvania. See Note 3 for a description of operations acquired~~electric transmission businesses in the ~~Dominion Energy Questar Combination.~~

~~Note 2. Significant Accounting Policies~~

~~As permitted by~~U.S., a renewable energy business primarily investing in wind, solar, geothermal and hydroelectric projects, one of the largest residential real estate brokerage firms and residential real estate brokerage franchise networks in the U.S.

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and 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, 2023, and for the three-month periods ended March 31, 2023 and 2022. The results of operations for the three-month period ended March 31, 2023, 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, ~~2016.~~

In2022, describes the ~~Companies' opinion,~~most significant accounting policies used in the ~~accompanying~~preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in the Company's accounting policies or its assumptions regarding significant accounting estimates during the three-month period ended March 31, 2023, other than the updates associated with the Company's estimates of loss contingencies related to the Oregon and Northern California 2020 wildfires (the "2020 Wildfires") and the 2022 McKinney fire as discussed in Note 9.

(2) Property, Plant and Equipment, Net

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


		As of
	Depreciable	March 31,		December 31,
	Life	2023		2022
Regulated assets:
Utility generation, transmission and distribution systems	5-80 years	$	93,123	$	92,759
Interstate natural gas pipeline assets	3-80 years	18,492		18,328
		111,615		111,087
Accumulated depreciation and amortization		(35,395)		(34,599)
Regulated assets, net		76,220		76,488

Nonregulated assets:
Independent power plants	2-50 years	8,514		8,545
Cove Point LNG facility	40 years	3,416		3,412
Other assets	2-30 years	2,680		2,693
		14,610		14,650
Accumulated depreciation and amortization		(3,493)		(3,452)
Nonregulated assets, net		11,117		11,198

		87,337		87,686
Construction work-in-progress		6,246		5,357
Property, plant and equipment, net		$	93,583	$	93,043

Construction work-in-progress includes $5.8 billion as of March 31, 2023 and $4.9 billion as of December 31, 2022, related to the construction of regulated assets.

(3) 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,
	2023		2022
Investments:
BYD Company Limited common stock	$	3,321	$	3,763
U.S. Treasury Bills	2,854		1,931
Rabbi trusts	449		433
Other	318		335
Total investments	6,942		6,462

Equity method investments:
BHE Renewables tax equity investments	4,430		4,535
Electric Transmission Texas, LLC	641		623
Iroquois Gas Transmission System, L.P.	604		600
Other	352		304
Total equity method investments	6,027		6,062

Restricted cash and cash equivalents and investments:
Quad Cities Station nuclear decommissioning trust funds	696		664
Other restricted cash and cash equivalents	192		226
Total restricted cash and cash equivalents and investments	888		890

Total investments and restricted cash and cash equivalents and investments	$	13,857	$	13,414

Reflected as:
Other current assets	$	3,032	$	2,141
Noncurrent assets	10,825		11,273
Total investments and restricted cash and cash equivalents and investments	$	13,857	$	13,414

Investments

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


	Three-Month Periods
	Ended March 31,
		2023		2022
Unrealized gains (losses) recognized on marketable securities held at the reporting date		$	529	$	(1,257)
Net gains recognized on marketable securities sold during the period		170		—
Gains (losses) on marketable securities, net		$	699	$	(1,257)

Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

Cash equivalents consist of funds invested in money market mutual funds, U.S. 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 consist substantially of funds restricted for 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 presented on 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,
	2023		2022

Cash and cash equivalents	$	963	$	1,591
Investments and restricted cash and cash equivalents	133		173
Investments and restricted cash and cash equivalents and investments	59		53
Total cash and cash equivalents and restricted cash and cash equivalents	$	1,155	$	1,817

(4) Recent Financing Transactions

Credit Facilities

In April 2023, AltaLink Investments, L.P. extended, with lender consent, the expiration date for its existing C$200 million one year revolving credit facility to April 2024, by exercising a one-year extension option.

(5) Income Taxes

The effective income tax rate for the three-month period ended March 31, 2022, is 108% and results from a $507 million income tax benefit associated with a $470 million pre-tax loss, primarily relating to a pre-tax unrealized loss of $1,247 million on the Company's investment in BYD Company Limited. The $507 million income tax benefit is primarily comprised of a $99 million benefit (21%) from the application of the statutory income tax rate to the pre-tax loss and a $339 million benefit (72%) from income tax credits.

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


	Three-Month Periods
	Ended March 31,
		2023		2022

Federal statutory income tax rate		21	%	21	%
Income tax credits		(35)		72
State income tax, net of federal income tax impacts		(4)		(3)
Income tax effect of foreign income		7		3
Effects of ratemaking		(3)		8
Equity income		(1)		3
Noncontrolling interest		(2)		5
Other, net		—		(1)
Effective income tax rate		(17)	%	108	%

Income tax credits relate primarily to production tax credits ("PTCs") from wind- and solar-powered generating facilities owned by MidAmerican Energy, PacifiCorp and BHE Renewables. Federal renewable electricity PTCs are earned as energy from qualifying wind- and solar-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- and solar-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service. PTCs recognized for the three-month periods ended March 31, 2023 and 2022 totaled $343 million and $338 million, respectively.

Income tax effect on foreign income includes, among other items, a deferred income tax charge of $82 million recognized in March 2023 related to the July 2022 enactment of a new Energy Profits Levy 25% income tax in the United Kingdom effective May 26, 2022, through December 31, 2025, as well as an increase in the tax rate from 25% to 35% effective January 1, 2023, through March 31, 2028, enacted in January 2023.

The Company's provision for income taxes has been computed on a stand-alone basis. Berkshire Hathaway includes the Company in its consolidated U.S. federal and Iowa state income tax returns and the majority of the Company's U.S. federal income tax is remitted to or received from Berkshire Hathaway. The Company made no payments for federal income taxes to Berkshire Hathaway for the three-month periods ended March 31, 2023 and 2022.

In July 2022, the Company amended its tax allocation agreement with Berkshire Hathaway, which changed how state tax attributes will be settled with respect to state income tax returns that Berkshire Hathaway includes the Company. As a result, the Company no longer expects to receive the cash benefits from the state of Iowa net operating loss carryforward previously recorded as a long-term income tax receivable from Berkshire Hathaway as a component of BHE's shareholders' equity, and recognized a noncash distribution of $744 million to retained earnings.

(6) 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,
		2023		2022
Pension:
Service cost		$	4	$	7
Interest cost		28		19
Expected return on plan assets		(31)		(27)
Settlement		(5)		2
Net amortization		4		4
Net periodic benefit cost		$	—	$	5

Other postretirement:
Service cost		$	1	$	2
Interest cost		7		5
Expected return on plan assets		(8)		(7)
Net amortization		(1)		—
Net periodic benefit (credit) cost		$	(1)	$	—

Amounts other than the service cost for pension and other postretirement benefit plans are recorded in other, net on the Consolidated Statements of Operations. Employer contributions to the domestic pension and other postretirement benefit plans are expected to be $13 million and $7 million, respectively, during 2023. As of March 31, 2023, $3 million and $1 million of contributions had been made to the domestic pension and other postretirement benefit plans, respectively.

Foreign Operations

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


	Three-Month Periods
	Ended March 31,
		2023		2022

Service cost		$	2	$	4
Interest cost		14		10
Expected return on plan assets		(19)		(25)

Net amortization		6		6
Net periodic benefit cost (credit)		$	3	$	(5)

Amounts other than the service cost for the United Kingdom pension plan are recorded in other, net on the Consolidated Statements of Operations. Employer contributions to the United Kingdom pension plan are expected to be £11 million during 2023. As of March 31, 2023, £3 million, or $4 million, of contributions had been made to the United Kingdom pension plan.

(7) Asset Retirement Obligations

MidAmerican Energy estimates its asset retirement obligation ("ARO") liabilities based upon detailed engineering calculations of the amount and timing of the future cash spending for a third party to perform the required work. Spending estimates are escalated for inflation and then discounted at a credit-adjusted, risk-free rate. Changes in estimates could occur for a number of reasons including changes in laws and regulations, plan revisions, inflation and changes in the amount and timing of expected work. During the three-month period ended March 31, 2023, MidAmerican Energy recorded an increase of $88 million for decommissioning its wind-generating facilities due to an updated decommissioning estimate reflecting changes in the projected removal costs per turbine.

(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, 2023:
Assets:
Commodity derivatives	$	3	$	280	$	16	$	(65)	$	234

Interest rate derivatives	42		43		16		—		101
Mortgage loans held for sale	—		650		—		—		650
Money market mutual funds	671		—		—		—		671
Debt securities:
U.S. government obligations	3,079		—		—		—		3,079
International government obligations	—		1		—		—		1
Corporate obligations	—		70		—		—		70
Municipal obligations	—		4		—		—		4

Equity securities:
U.S. companies	385		—		—		—		385
International companies	3,329		—		—		—		3,329
Investment funds	278		—		—		—		278
	$	7,787	$	1,048	$	32	$	(65)	$	8,802
Liabilities:
Commodity derivatives	$	(8)	$	(92)	$	(166)	$	52	$	(214)
Foreign currency exchange rate derivatives	—		(20)		—		—		(20)
Interest rate derivatives	—		(5)		(1)		1		(5)
	$	(8)	$	(117)	$	(167)	$	53	$	(239)


	Input Levels for Fair Value Measurements
	Level 1		Level 2		Level 3		Other(1)		Total
As of December 31, 2022:
Assets:
Commodity derivatives	$	6	$	614	$	51	$	(194)	$	477

Interest rate derivatives	50		54		8		—		112
Mortgage loans held for sale	—		474		—		—		474
Money market mutual funds	1,178		—		—		—		1,178
Debt securities:
U.S. government obligations	2,146		—		—		—		2,146
International government obligations	—		1		—		—		1
Corporate obligations	—		70		—		—		70
Municipal obligations	—		3		—		—		3
Agency, asset and mortgage-backed obligations	—		1		—		—		1
Equity securities:
U.S. companies	360		—		—		—		360
International companies	3,771		—		—		—		3,771
Investment funds	231		—		—		—		231
	$	7,742	$	1,217	$	59	$	(194)	$	8,824
Liabilities:
Commodity derivatives	$	(8)	$	(206)	$	(110)	$	106	$	(218)
Foreign currency exchange rate derivatives	—		(21)		—		—		(21)
Interest rate derivatives	—		(2)		(2)		1		(3)
	$	(8)	$	(229)	$	(112)	$	107	$	(242)

(1)Represents netting under master netting arrangements and a net cash collateral payable of $12 million and $87 million as of March 31, 2023 and December 31, 2022, respectively.

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 the 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 financial assets and liabilities measured at fair value on a recurring basis using significant Level 3 inputs (in millions). Transfers out of Level 3 occur primarily due to increased price observability.


	Three-Month Periods
	Ended March 31,
				Interest
		Commodity		Rate
		Derivatives		Derivatives
2023:
Beginning balance		$	(59)	$	6
Changes included in earnings(1)		9		9
Changes in fair value recognized in OCI		(3)		—
Changes in fair value recognized in net regulatory assets		(98)		—



Settlements		1		—


Ending balance		$	(150)	$	15







2022:
Beginning balance	$	(151)	$	19
Changes included in earnings(1)	(56)		(6)
Changes in fair value recognized in OCI	5		—
Changes in fair value recognized in net regulatory assets	(60)		—


Settlements	23		—

Ending balance	$	(239)	$	13

(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 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, 2023				As of December 31, 2022
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	51,150	$	47,805	$	51,635	$	46,906

(9) Commitments and Contingencies

Commitments

The Company has the following firm commitments that are not reflected on the Consolidated Balance Sheets.

Construction Commitments

In April 2023, PacifiCorp entered into build transfer agreements totaling $1.2 billion through 2025 for the construction of certain wind-powered generating facilities in Wyoming.

During the three-month period ended March 31, 2023, MidAmerican Energy entered into firm construction commitments totaling $183 million for the remainder of 2023 through 2024 related to the construction of wind-powered generating facilities in Iowa.

Fuel Contracts

During the three-month period ended March 31, 2023, PacifiCorp entered into certain coal supply and transportation agreements totaling $247 million through 2025.

Environmental Laws and Regulations

The Company is subject to federal, state, local and foreign laws and regulations regarding air quality, climate change, emissions performance standards, water quality, coal ash disposal, hazardous 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.

Lower Klamath Hydroelectric Project

In November 2022, the Federal Energy Regulatory Commission ("FERC") issued a license surrender order for the Lower Klamath Project, which was accepted by the Klamath River Renewal Corporation ("KRRC") and the states of Oregon and California ("States") in December 2022, along with the transfer of the Lower Klamath Project dams. Although PacifiCorp no longer owns the Lower Klamath Project, PacifiCorp will continue to operate the facilities under an operation and maintenance agreement with the KRRC until each facility is ready for removal. Removal of the Copco No. 2 facility is anticipated to begin in 2023, and removal of the remaining three dams (J.C. Boyle, Copco No. 1 and Iron Gate) is anticipated to begin in 2024. The KRRC has $450 million in funding available for dam removal and restoration; $200 million collected from PacifiCorp's Oregon and California customers and $250 million in California bond funds. PacifiCorp and the States have also agreed to equally share cost overruns that may occur above the initial $450 million in funding. Specifically, PacifiCorp and the States have agreed to equally fund an initial $45 million contingency fund and equally share any additional costs above that amount to ensure dam removal and restoration is complete.

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 financial results. The Company is also involved in other kinds of 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.

Wildfire Liability Overview

A provision for a loss contingency is recorded when it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. The Company evaluates the related range of reasonably estimated losses and records a loss based on its best estimate within that range or the lower end of the range if there is no better estimate.

In California, under inverse condemnation, courts have held that investor-owned utilities can be liable for real and personal property damages from wildfires 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 be found liable for all ~~adjustments~~damages proximately caused by negligence, including real and personal property and natural resource damages; fire suppression costs; personal injury and loss of life damages; and interest.

2020 Wildfires

In September 2020, a severe weather event resulting in high winds, low humidity and warm temperatures contributed to several major wildfires, which resulted in real and personal property and natural resource 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 destroyed, including residences; 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 U.S. Forest Service, the California Public Utilities Commission, the Oregon Department of Forestry, the Oregon Department of Justice, PacifiCorp and various experts engaged by PacifiCorp.

As of the date of this filing, numerous lawsuits have been filed in Oregon and California, including a class action complaint in Oregon, on behalf of plaintiffs related to the 2020 Wildfires. The plaintiffs seek damages that include property damages, economic losses, punitive damages, exemplary damages, attorneys' fees and other damages. Additionally, several insurance carriers have filed subrogation complaints in Oregon and California with allegations similar to those made in the aforementioned lawsuits. Final determinations of liability, however, will only be made following the completion of comprehensive investigations and litigation processes.

Based on the facts and circumstances available to PacifiCorp as of the date of this filing, which includes the status of litigation and recent settlements, PacifiCorp has accrued cumulative estimated probable losses associated with the 2020 Wildfires of $877 million through March 31, 2023. PacifiCorp's cumulative accrual includes estimates of losses for fire suppression costs, real and personal property damages, natural resource damages for certain areas and noneconomic damages such as personal injury damages and loss of life damages that are considered probable of being incurred and that it is reasonably able to estimate at this time. For certain aspects of the 2020 Wildfires for which loss is considered probable, information necessary to ~~present fairly their financial position~~reasonably estimate the potential losses, such as those related to certain areas of natural resource damages, is not currently available.

It is reasonably possible 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 variation in those types of properties and lack of available details. To the extent losses beyond the amounts accrued are incurred, additional insurance coverage is expected to be available to cover a portion of the losses.

The following table presents changes in PacifiCorp's liability for estimated losses associated with the 2020 Wildfires (in millions):


	Three-Month Periods
	Ended March 31,
	2023		2022
Beginning balance	$	424	$	252
Accrued losses	400		—

Ending balance	$	824	$	252

PacifiCorp's receivable for expected insurance recoveries associated with the probable losses was $287 million and $246 million, respectively, as of ~~September 30, 2017, their~~March 31, 2023 and December 31, 2022. During the three-month periods ended March 31, 2023 and 2022 PacifiCorp recognized probable losses net of expected insurance recoveries associated with the 2020 Wildfires of $359 million and $— million, respectively, and are recorded in operations and maintenance on the Consolidated Statements of Operations.

2022 McKinney Fire

According to the California Department of Forestry and Fire Protection, on July 29, 2022, a wildfire began in the Oak Knoll Ranger District of the Klamath National Forest in Siskiyou County, California (the "2022 McKinney Fire") located in PacifiCorp's service territory. Third-party reports indicate that the 2022 McKinney Fire resulted in 11 structures damaged, 185 structures destroyed, 12 injuries and four fatalities and consumed 60,000 acres. The cause of the 2022 McKinney Fire is undetermined and remains under investigation by the U.S. Forest Service.

Due to the preliminary nature of the investigation PacifiCorp does not believe a loss is probable and therefore has not accrued any loss as of the date of this filing. While the loss is not probable, PacifiCorp estimates the potential loss, excluding losses for natural resource damages, to be $31 million, net of expected insurance recoveries. The loss estimate includes PacifiCorp's estimate of losses for fire suppression costs; real and personal property damages; and noneconomic damages such as personal injury damages and loss of life damages. PacifiCorp is unable to estimate the total potential loss, including losses for natural resource damages, because there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PacifiCorp. PacifiCorp has insurance available and estimates the potential insurance recoveries to be $103 million, to cover potential losses.

As of the date of this filing, multiple lawsuits have been filed in California on behalf of plaintiffs related to the 2022 McKinney Fire. The plaintiffs seek damages that include property damages, economic and noneconomic losses, punitive damages, exemplary damages, attorneys' fees and other damages but the amount of damages sought are not specified. Final determinations of liability, however, will only be made following the completion of comprehensive investigations and litigation processes.

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 and nonregulated, with further disaggregation of regulated by line of business, including a reconciliation to the Company's reportable segment information included in Note 12 (in millions):


	For the Three-Month Period Ended March 31, 2023
	PacifiCorp		MidAmerican Funding		NV Energy		Northern Powergrid		BHE Pipeline Group		BHE Transmission		BHE Renewables		BHE and Other(1)		Total
Customer Revenue:
Regulated:
Retail electric	$	1,349	$	491	$	848	$	—	$	—	$	—	$	—	$	—	$	2,688
Retail gas	—		296		96		—		—		—		—		—		392
Wholesale	61		100		31		—		—		—		—		(1)		191
Transmission and distribution	38		14		18		281		—		165		—		—		516
Interstate pipeline	—		—		—		—		878		—		—		(56)		822
Other	32		—		—		—		2		—		—		—		34
Total Regulated	1,480		901		993		281		880		165		—		(57)		4,643
Nonregulated	—		3		1		45		266		40		305		—		660
Total Customer Revenue	1,480		904		994		326		1,146		205		305		(57)		5,303
Other revenue	4		16		5		28		27		—		88		—		168
Total	$	1,484	$	920	$	999	$	354	$	1,173	$	205	$	393	$	(57)	$	5,471


	For the Three-Month Period Ended March 31, 2022
	PacifiCorp		MidAmerican Funding		NV Energy		Northern Powergrid		BHE Pipeline Group		BHE Transmission		BHE Renewables		BHE and Other(1)		Total
Customer Revenue:
Regulated:
Retail electric	$	1,185	$	472	$	599	$	—	$	—	$	—	$	—	$	—	$	2,256
Retail gas	—		337		51		—		—		—		—		—		388
Wholesale	55		161		20		—		—		—		—		—		236
Transmission and distribution	32		15		17		269		—		176		—		—		509
Interstate pipeline	—		—		—		—		745		—		—		(41)		704
Other	20		—		1		—		1		—		—		—		22
Total Regulated	1,292		985		688		269		746		176		—		(41)		4,115
Nonregulated	—		2		—		15		278		7		302		—		604
Total Customer Revenue	1,292		987		688		284		1,024		183		302		(41)		4,719
Other revenue	5		18		5		31		11		—		34		—		104
Total	$	1,297	$	1,005	$	693	$	315	$	1,035	$	183	$	336	$	(41)	$	4,823

(1)The BHE and Other reportable segment represents amounts related principally to other corporate 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,
		2023		2022
Customer Revenue:
Brokerage		$	799	$	1,092
Franchise		12		20
Total Customer Revenue		811		1,112
Mortgage and other revenue		64		95
Total		$	875	$	1,207

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, 2023, by reportable segment (in millions):


	Performance obligations expected to be satisfied:
	Less than 12 months		More than 12 months		Total
BHE Pipeline Group	$	2,786	$	20,146	$	22,932
BHE Transmission	490		—		490
Total	$	3,276	$	20,146	$	23,422

(11) Components of Accumulated Other Comprehensive Loss, Net

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


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

Balance, December 31, 2021	$	(318)	$	(1,086)	$	59	$	5	$	(1,340)
Other comprehensive income (loss)	15		(110)		77		—		(18)
Balance, March 31, 2022	$	(303)	$	(1,196)	$	136	$	5	$	(1,358)

Balance, December 31, 2022	$	(390)	$	(1,896)	$	135	$	2	$	(2,149)
Other comprehensive (loss) income	(4)		99		(55)		—		40
Balance, March 31, 2023	$	(394)	$	(1,797)	$	80	$	2	$	(2,109)

(12) Segment Information

The Company's reportable segments with foreign operations include Northern Powergrid, whose business is principally in the United Kingdom, and BHE Transmission, whose business includes operations in Canada. Intersegment eliminations and adjustments, including the allocation of goodwill, have been made. Effective January 1, 2023, the Company's unregulated retail energy services business was transferred to a subsidiary of BHE Renewables. Prior period amounts, which were previously reported in BHE and Other, have been changed to reflect this activity in BHE Renewables. Information related to the Company's reportable segments is shown below (in millions):


	Three-Month Periods
	Ended March 31,
		2023		2022
Operating revenue:
PacifiCorp		$	1,484	$	1,297
MidAmerican Funding		920		1,005
NV Energy		999		693
Northern Powergrid		354		315
BHE Pipeline Group		1,173		1,035
BHE Transmission		205		183
BHE Renewables		393		336
HomeServices		875		1,207
BHE and Other(1)		(57)		(41)
Total operating revenue		$	6,346	$	6,030





Depreciation and amortization:
PacifiCorp	$	279	$	280
MidAmerican Funding	234		250
NV Energy	152		140
Northern Powergrid	85		80
BHE Pipeline Group	172		131
BHE Transmission	61		58
BHE Renewables	66		66
HomeServices	13		15
BHE and Other(1)	1		2
Total depreciation and amortization	$	1,063	$	1,022


	Three-Month Periods
	Ended March 31,
		2023		2022
Operating income:
PacifiCorp		$	(167)	$	216
MidAmerican Funding		88		100
NV Energy		57		62
Northern Powergrid		146		159
BHE Pipeline Group		584		538
BHE Transmission		88		83
BHE Renewables		(69)		54
HomeServices		(45)		28
BHE and Other(1)		(15)		(4)
Total operating income		667		1,236
Interest expense		(586)		(532)
Capitalized interest		24		17
Allowance for equity funds		49		38
Interest and dividend income		86		23
Gains (losses) on marketable securities, net		699		(1,257)
Other, net		40		5
Total income (loss) before income tax expense (benefit) and equity income (loss)		$	979	$	(470)





Interest expense:
PacifiCorp	$	124	$	106
MidAmerican Funding	84		82
NV Energy	63		51
Northern Powergrid	30		32
BHE Pipeline Group	39		37
BHE Transmission	37		38
BHE Renewables	45		42
HomeServices	4		1
BHE and Other(1)	160		143
Total interest expense	$	586	$	532


Earnings (loss) on common shares:
PacifiCorp	$	(120)	$	130
MidAmerican Funding	249		241
NV Energy	34		29
Northern Powergrid	11		111
BHE Pipeline Group	369		322
BHE Transmission	64		62
BHE Renewables	79		145
HomeServices	(34)		21
BHE and Other(1)	329		(1,206)
Total earnings (loss) on common shares	$	981	$	(145)


	As of
	March 31,		December 31,
	2023		2022
Assets:
PacifiCorp	$	30,268	$	30,559
MidAmerican Funding	25,899		26,077
NV Energy	17,210		16,676
Northern Powergrid	9,216		9,005
BHE Pipeline Group	20,931		21,005
BHE Transmission	9,380		9,334
BHE Renewables	11,693		12,632
HomeServices	3,625		3,436
BHE and Other(1)	6,232		5,116
Total assets	$	134,454	$	133,840

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


	Three-Month Periods
	Ended March 31,
		2023		2022
Operating revenue by country:
U.S.		$	5,815	$	5,534
United Kingdom		333		315
Canada		177		181
Australia		21		—

Total operating revenue by country		$	6,346	$	6,030


Income (loss) before income tax expense (benefit) and equity income (loss) by country:
U.S.	$	819	$	(654)
United Kingdom	113		139
Canada	43		46
Australia	5		—
Other	(1)		(1)
Total income (loss) before income tax expense (benefit) and equity income (loss) by country	$	979	$	(470)

The following table shows the change in the carrying amount of goodwill by reportable segment for the three-month period ended March 31, 2023 (in millions):


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

December 31, 2022	$	1,129	$	2,102	$	2,369	$	917	$	1,814	$	1,461	$	95	$	1,602	$	11,489

Foreign currency translation	—		—		—		13		—		1		—		—		14

March 31, 2023	$	1,129	$	2,102	$	2,369	$	930	$	1,814	$	1,462	$	95	$	1,602	$	11,503

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 for the three and nine months ended September 30, 2017 and 2016, their cash flows for the nine months ended September 30, 2017 and 2016 and Dominion Energy's changes in equity for the nine months ended September 30, 2017 and 2016. 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~~Company during the periods ~~presented. Actual results may differ from those estimates.~~

~~The Companies' accompanying unaudited Consolidated Financial Statements~~included herein. Explanations 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 valuemanagement's best estimate of the ~~underlying contractual arrangements. At September 30, 2017, Dominion Energy owns the general partner, 50.9%~~impact of the common and subordinated units and 37.5% of the convertible preferred interests in Dominion Energy Midstream. The public’s ownership interest in Dominion Energy Midstream is reflected as noncontrolling interest in Dominion Energy’s Consolidated Financial Statements. Also, at September 30, 2017, Dominion Energy owns 50% of the units in and consolidates Four Brothers and Three Cedars. NRG's ownership interest in Four Brothers and Three Cedars, as well as Terra Nova Renewable Partners' 33% interest in certain Dominion Energy merchant solar projects, is reflected as noncontrolling interest in Dominion Energy’s 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 expensesweather, customer growth, usage trends and other factors.

~~Certain amounts~~ This discussion should be read in conjunction with the ~~Companies' 2016~~Company's historical unaudited Consolidated Financial Statements and Notes ~~have been reclassified~~to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. The Company's actual results in the future could differ significantly from the historical results.

BHE is a holding company that owns a highly diversified portfolio of locally managed and operated businesses principally engaged in the energy industry and is a consolidated subsidiary of Berkshire Hathaway. As of May 4, 2023, Berkshire Hathaway and family members and related or affiliated entities of the late Mr. Walter Scott, Jr., a former member of BHE's Board of Directors, owned 92% and 8%, respectively, of BHE's voting common stock.

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 U.S. serving customers in 11 states, two electricity distribution companies in Great Britain, five interstate natural gas pipeline companies in the U.S., one of which owns a LNG export, import and storage facility, an electric transmission business in Canada, interests in electric transmission businesses in the U.S., a renewable energy business primarily investing in wind, solar, geothermal and hydroelectric projects, one of the largest residential real estate brokerage firms in the U.S. and one of the largest residential real estate brokerage franchise networks in the U.S. The reportable segment financial information includes all necessary adjustments and eliminations needed to conform to the ~~2017 presentation for comparative purposes.~~Company's significant accounting policies. The ~~reclassifications did not affect~~differences between the ~~Companies’ net income, total assets, liabilities, equity or cash flows.~~

~~Amounts disclosed for Dominion Energy are inclusive~~reportable segment amounts and the consolidated amounts, described as BHE and Other, relate principally to other corporate entities, corporate functions and intersegment eliminations. Effective January 1, 2023, the Company's unregulated retail energy services business was transferred to a subsidiary of ~~Virginia Power and/or Dominion Energy Gas, where applicable. With the exception of the items described below, there~~BHE Renewables. Prior period amounts, which were previously reported in BHE and Other, have been ~~no significant~~changed to reflect this activity in BHE Renewables.

Results of Operations for the First Quarter of 2023 and 2022

Overview

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


	First Quarter
	2023		2022		Change
Operating revenue:
PacifiCorp	$	1,484	$	1,297	$	187	14	%
MidAmerican Funding	920		1,005		(85)		(8)
NV Energy	999		693		306		44
Northern Powergrid	354		315		39		12
BHE Pipeline Group	1,173		1,035		138		13
BHE Transmission	205		183		22		12
BHE Renewables	393		336		57		17
HomeServices	875		1,207		(332)		(28)
BHE and Other	(57)		(41)		(16)		39
Total operating revenue	$	6,346	$	6,030	$	316	5	%

Earnings (loss) on common shares:
PacifiCorp	$	(120)	$	130	$	(250)	*
MidAmerican Funding	249		241		8		3
NV Energy	34		29		5		17
Northern Powergrid	11		111		(100)		(90)
BHE Pipeline Group	369		322		47		15
BHE Transmission	64		62		2		3
BHE Renewables(1)	79		145		(66)		(46)
HomeServices	(34)		21		(55)		*
BHE and Other	329		(1,206)		1,535		*
Total earnings (loss) on common shares	$	981	$	(145)	$	1,126	*

(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 increased $1,126 million for the first quarter of 2023 compared to 2022. Included in these results was a pre-tax gain in the first quarter of 2023 of $717 million ($567 million after-tax) compared to a pre-tax loss in the first quarter of 2022 of $1,247 million ($985 million after-tax) related to the Company's investment in BYD Company Limited. Excluding the impact of this item, adjusted earnings on common shares for the first quarter of 2023 was $414 million, a decrease of $426 million, or 51%, compared to adjusted earnings on common shares for the first quarter of 2022 of $840 million.

The increase in earnings on common shares for the first quarter of 2023 compared to 2022 were primarily due to the following:

•The Utilities' earnings decreased $237 million for the first quarter of 2023 compared to 2022, primarily from higher operations and maintenance expense, largely due to an increase in loss accruals, net of expected insurance recoveries, associated with the 2020 Wildfires. The higher operations and maintenance expense was partially offset by favorable electric utility margin, higher allowances for equity and borrowed funds used during construction, increases in the cash surrender value of corporate-owned life insurance policies and a favorable income tax benefit from valuation allowance changes ~~from Note 2~~on state net operating loss carryforwards. Electric retail customer volumes increased 2.6% for the first quarter of 2023 compared to 2022, driven by higher customer usage and an increase in the average number of customers;

•Northern Powergrid's earnings decreased $100 million for the first quarter of 2023 compared to 2022, primarily due to a deferred income tax charge of $82 million recognized in March 2023 related to the enactment of a new Energy Profits Levy income tax. Units distributed declined 4.8% due to the unfavorable impact of weather and lower customer usage;

•BHE Pipeline Group's earnings increased $47 million for the first quarter of 2023 compared to 2022, largely due to a favorable general rate case settlement at EGTS in 2022 and the impacts of a general rate case, with interim rates effective January 1, 2023, subject to refund, at Northern Natural Gas;

•BHE Renewables' earnings decreased $66 million for the first quarter of 2023 compared to 2022, primarily due to unfavorable changes in unrealized positions on derivative contracts due to lower forward electricity price curves;

•HomeServices' earnings decreased $55 million for the first quarter of 2023 compared to 2022, primarily due to lower earnings from brokerage and settlement services and from mortgage services, reflecting the impact of rising interest rates and a corresponding decline in home sales; and

•BHE and Other's earnings increased $1,535 million for the first quarter of 2023 compared to 2022, primarily due to the $1,552 million favorable comparative change related to the Company's investment in BYD Company Limited.

Reportable Segment Results

PacifiCorp

Operating revenue increased $187 million for the first quarter of 2023 compared to 2022, primarily due to higher retail revenue of $159 million and higher wholesale and other revenue of $28 million, primarily from higher average wholesale market prices, partially offset by lower wholesale volumes. Retail revenue increased primarily due to price impacts of $107 million from higher average retail rates largely due to tariff changes and product mix and $52 million from higher volumes. Retail customer volumes increased 3.3%, primarily due to the favorable impact of weather, higher customer usage and an increase in the average number of customers.

Earnings decreased $250 million for the first quarter of 2023 compared to 2022, primarily due to higher operations and maintenance expense of $428 million, partially offset by higher utility margin of $38 million, higher allowances for equity and borrowed funds used during construction of $21 million and a favorable income tax benefit from valuation allowance changes on state net operating loss carryforwards. Operations and maintenance expense was unfavorable primarily due to an increase in loss accruals, net of expected insurance recoveries, associated with the 2020 Wildfires of $359 million, higher wildfire mitigation and vegetation management costs, and higher general and plant maintenance costs. Utility margin increased primarily due to higher retail rates and volumes, favorable deferred net power costs and higher average wholesale market prices, partially offset by higher purchased power and thermal generation costs and lower wholesale volumes.

MidAmerican Funding

Operating revenue decreased $85 million for the first quarter of 2023 compared to 2022, primarily due to lower natural gas operating revenue of $70 million and lower electric operating revenue of $17 million. Natural gas operating revenue decreased primarily due to a lower average per-unit cost of natural gas sold resulting in lower purchased gas adjustment recoveries of $61 million (fully offset in cost of sales) and the unfavorable impact of weather of $5 million. Electric operating revenue decreased due to lower wholesale and other revenue of $33 million, partially offset by higher retail revenue of $16 million. Electric wholesale and other revenue decreased mainly due to lower wholesale volumes of $22 million and lower average wholesale per-unit prices of $13 million. Electric retail revenue increased primarily due to higher recoveries through adjustment clauses of $14 million (largely offset in expense, primarily cost of sales). Electric retail customer volumes increased 1.0%, primarily due to higher customer usage, partially offset by the unfavorable impact of weather.

Earnings increased $8 million for the first quarter of 2023 compared to 2022, primarily due to lower depreciation and amortization expense of $17 million, a one-time gain on the sale of an investment of $13 million and favorable changes in the cash surrender value of corporate-owned life insurance policies of $12 million, partially offset by higher operations and maintenance expense of $13 million, lower natural gas utility margin of $8 million and lower electric utility margin of $7 million. Depreciation and amortization expense decreased primarily from the impacts of certain regulatory mechanisms, partially offset by additional assets placed in-service. Operations and maintenance expense increased due to higher general and plant maintenance costs and unfavorable property insurance costs. Natural gas utility margin decreased primarily due to the unfavorable impact of weather. Electric utility margin decreased primarily due to lower wholesale revenue, partially offset by higher retail revenue and lower purchased power costs.

NV Energy

Operating revenue increased $306 million for the first quarter of 2023 compared to 2022, primarily due to higher electric operating revenue of $260 million and higher natural gas operating revenue of $44 million from a higher average per-unit cost of natural gas sold (fully offset in cost of sales). Electric operating revenue increased primarily due to higher fully bundled energy rates (fully offset in cost of sales) of $229 million, higher customer volumes of $8 million, increased base tariff general rates of $8 million at Sierra Pacific and favorable transmission and wholesale revenue of $7 million. Electric retail customer volumes increased 2.9%, primarily due to the favorable impact of weather and an increase in the average number of customers.

Earnings increased $5 million for the first quarter of 2023 compared to 2022, primarily due to higher electric utility margin of $31 million and favorable interest and dividend income of $16 million, mainly from carrying charges on higher deferred energy balances, partially offset by higher operations and maintenance expenses of $24 million, unfavorable depreciation and amortization expense of $13 million and increased interest expense of $12 million due to higher outstanding long-term debt balances. Electric utility margin increased primarily due to higher electric retail customer volumes, increased base tariff general rates at Sierra Pacific and higher transmission and wholesale revenue. Operations and maintenance expense increased primarily due to higher general and plant maintenance costs and higher customer service operations costs. Depreciation and amortization expense increased primarily due to additional assets placed in-service.

Northern Powergrid

Operating revenue increased $39 million for the first quarter of 2023 compared to 2022, primarily due to higher distribution revenue of $41 million and higher revenue at CE Gas of $29 million, partially offset by $37 million from the stronger U.S. dollar. Distribution revenue increased primarily due to the recovery of Supplier of Last Resort payments of $43 million (fully offset in cost of sales) and higher tariff rates of $10 million. Also impacting distribution revenue was a 4.8% decline in units distributed, largely due to the unfavorable impact of weather and lower customer usage, of $11 million. CE Gas revenue increased from a gas project that commenced commercial operation in March 2022 and a solar project that commenced commercial operation in July 2022.

Earnings decreased $100 million for the first quarter of 2023 compared to 2022, primarily due to a deferred income tax charge of $82 million recognized in March 2023 related to the enactment of a new Energy Profits Levy income tax. Earnings were also impacted by unfavorable distribution-related operating and depreciation expenses of $11 million and increased non-service benefit plan costs of $10 million, partially offset by favorable operating performance at CE Gas of $8 million from the gas and solar projects that commenced commercial operations in 2022.

BHE Pipeline Group

Operating revenue increased $138 million for the first quarter of 2023 compared to 2022, primarily due to higher operating revenue of $71 million at Northern Natural Gas and $55 million at BHE GT&S. The increase in operating revenue at Northern Natural Gas was largely due to the impacts of a general rate case, with interim rates effective January 1, 2023, subject to refund, of $63 million and higher transportation revenue of $34 million from higher rates in the Field Area, partially offset by lower gas sales of $25 million (largely offset in cost of sales) from system balancing activities. The increase in operating revenue at BHE GT&S was primarily due to an increase in regulated gas transportation and storage services rates due to the settlement of EGTS' general rate case of $42 million, higher LNG revenue of $16 million at Cove Point, and an increase in variable revenue related to park and loan activity of $10 million at EGTS, partially offset by lower non-regulated revenue of $22 million (largely offset in cost of sales) from lower volumes and unfavorable commodity prices.

Earnings increased $47 million for the first quarter of 2023 compared to 2022, largely due to higher earnings at Northern Natural Gas of $28 million and higher earnings at BHE GT&S of $14 million. The increase at Northern Natural Gas is due to the impacts of a general rate case of $16 million and higher transportation revenue in the Field Area, partially offset by higher operations and maintenance expense. The increase at BHE GT&S is due to a favorable general rate case settlement at EGTS in 2022 and higher equity earnings at Iroquois Gas Transmission System, partially offset by higher operations and maintenance expense and increased cost of gas from the unfavorable revaluation of volumes retained, due to lower natural gas prices.

BHE Transmission

Operating revenue increased $22 million for the first quarter of 2023 compared to 2022, primarily due to $26 million of incremental revenue from non-regulated wind-powered generating facilities acquired in November 2022 and higher other non-regulated revenue at BHE Canada, partially offset by $12 million from the stronger U.S. dollar.

Earnings increased $2 million for the first quarter of 2023 compared to 2022, primarily due to $6 million of incremental earnings at non-regulated wind-powered generating facilities acquired in November 2022, partially offset by $3 million from the stronger U.S. dollar.

BHE Renewables

Operating revenue increased $57 million for the first quarter of 2023 compared to 2022, primarily due to higher wind revenues of $60 million, largely due to favorable changes in the valuation of certain derivative contracts, and higher natural gas and electric retail energy services revenue of $23 million, partially offset by lower solar revenues of $20 million from lower generation due to weather events in California. Natural gas and electric retail energy services revenue increased due to higher electric volumes and favorable natural gas and electric pricing, partially offset by lower natural gas volumes.

Earnings decreased $66 million for the first quarter of 2023 compared to 2022, primarily due to lower earnings of $79 million from the retail energy services business, largely due to unfavorable changes in unrealized positions on derivative contracts caused by lower forward electricity price curves, lower natural gas and geothermal earnings of $40 million, primarily due to maintenance outages, and lower solar earnings of $18 million from lower generation due to weather events in California. These items were partially offset by higher wind earnings of $74 million, largely due to favorable changes in the valuation of certain derivative contracts and higher earnings from tax equity investments of $28 million due to lower equity losses and higher production tax credits.

HomeServices

Operating revenue decreased $332 million for the first quarter of 2023 compared to 2022, primarily due to lower brokerage and settlement services revenue of $293 million and lower mortgage revenue of $34 million. The decrease in brokerage and settlement services revenue resulted from a 29% decrease in closed transaction volume due to rising interest rates and a corresponding decline in home sales. The lower mortgage revenue was due to a 41% decrease in funded volume, primarily due to rising interest rates.

Earnings decreased $55 million for the first quarter of 2023 compared to 2022, primarily due to lower earnings from brokerage and settlement services of $38 million and mortgage services of $12 million, largely from the decrease in funded volumes from rising interest rates. Earnings at brokerage and settlement services declined due to the decrease in closed transaction volume, partially offset by favorable operating expenses primarily due to lower compensation costs.

BHE and Other

Operating revenue decreased $16 million for the first quarter of 2023 compared to 2022, due to higher intersegment eliminations.

Earnings increased $1,535 million for the first quarter of 2023 compared to 2022, primarily due to the $1,552 million favorable comparative change related to the Company's investment in BYD Company Limited, favorable changes in the cash surrender value of corporate-owned life insurance policies of $14 million and $8 million of lower dividends on BHE's 4.00% Perpetual Preferred Stock issued to certain insurance subsidiaries of Berkshire Hathaway. These items were partially offset by higher BHE corporate interest expense from an April 2022 debt issuance and $17 million of lower federal income tax credits recognized on a consolidated basis.

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 ~~Companies'~~Company's Annual Report on Form 10-K for the year ended December 31, ~~2016.~~

~~Property, Plant~~2022 for further discussion regarding the limitation of distributions from BHE's subsidiaries.

As of March 31, 2023, the Company's total net liquidity was as follows (in millions):


															BHE Pipeline
					MidAmerican		NV		Northern		BHE				Group and
	BHE		PacifiCorp		Funding		Energy		Powergrid		Canada		HomeServices		Other		Total

Cash and cash equivalents	$	173	$	19	$	58	$	21	$	18	$	64	$	216	$	394	$	963

Credit facilities(1)	3,500		2,000		1,509		650		295		795		2,725		—		11,474
Less:
Short-term debt	(755)		—		—		(83)		(49)		(127)		(805)		—		(1,819)
Tax-exempt bond support and letters of credit	—		(249)		(363)		—		—		(1)		—		—		(613)
Net credit facilities	2,745		1,751		1,146		567		246		667		1,920		—		9,042

Total net liquidity	$	2,918	$	1,770	$	1,204	$	588	$	264	$	731	$	2,136	$	394	$	10,005
Credit facilities:
Maturity dates	2025		2024, 2025		2023, 2025		2025		2025		2023, 2026, 2027		2023, 2024, 2026

(1)Includes $48 million drawn on capital expenditure and ~~Equipment~~

Inother uncommitted credit facilities at Northern Powergrid.

Operating Activities

Net cash flows from operating activities for the ~~first quarter~~three-month periods ended March 31, 2023 and 2022, were $1.1 billion and $2.2 billion, respectively. The decrease was primarily due to changes in working capital and regulatory assets and unfavorable operating results.

The timing of ~~2017, Virginia Power revised~~ the ~~depreciation rates~~Company's income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods selected and assumptions made for each payment date.

Investing Activities

Net cash flows from investing activities for the three-month periods ended March 31, 2023 and 2022, were $(1.8) billion and $(1.6) billion, respectively. The change was primarily due to higher purchases, net of proceeds from maturities, of U.S. Treasury Bills totaling $896 million and higher capital expenditures of $295 million, partially offset by higher proceeds from sales of marketable securities of $942 million. Refer to "Future Uses of Cash" for a discussion of capital expenditures.

Financing Activities

Net cash flows from financing activities for the three-month period ended March 31, 2023, was $20 million. Sources of cash totaled $699 million and consisted of net proceeds from short-term debt. Uses of cash totaled $679 million and consisted mainly of repayments of BHE senior debt totaling $400 million, repayments of subsidiary debt totaling $136 million and distributions to noncontrolling interests of $126 million.

Net cash flows from financing activities for the three-month period ended March 31, 2022, was $(310) million. Sources of cash totaled $405 million and consisted of proceeds from subsidiary debt issuances. Uses of cash totaled $715 million and consisted mainly of repayments of subsidiary debt totaling $193 million, net repayments of short-term debt totaling $165 million and distributions to noncontrolling interests of $117 million.

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 ~~assets~~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 customer rates; changes in environmental and other rules and regulations; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital.

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
	2022		2023		2023
Capital expenditures by business:
PacifiCorp	$	374	$	643	$	3,662
MidAmerican Funding	459		382		2,324
NV Energy	272		437		1,751
Northern Powergrid	169		124		597
BHE Pipeline Group	205		169		1,431
BHE Transmission	47		43		191
BHE Renewables	19		29		269
HomeServices	12		11		46
BHE and Other(1)	(4)		10		12
Total	$	1,553	$	1,848	$	10,283





Capital expenditures by type:
Wind generation	$	153	$	105	$	2,172
Electric distribution	388		477		2,071
Electric transmission	261		291		2,063
Natural gas transmission and storage	103		65		1,097
Solar generation	51		40		236
Electric battery and pumped hydro storage	1		40		236
Other	596		830		2,408
Total	$	1,553	$	1,848	$	10,283

(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 includes both growth and operating expenditures. Growth expenditures include spending for the following:

◦Construction of wind-powered generating facilities at MidAmerican Energy totaling $75 million and $3 million for the three-month periods ended March 31, 2023 and 2022, respectively. The timing and amount of forecast wind generation capital expenditures may be substantially impacted by the ultimate outcome of MidAmerican Energy's Wind PRIME filing. Planned spending for the construction of additional wind-powered generating facilities totals $1,025 million for the remainder of 2023.

◦Repowering of wind-powered generating facilities at MidAmerican Energy totaling $5 million and $120 million for the three-month periods ended March 31, 2023 and 2022, respectively. Planned spending for the repowering of wind-powered generating facilities totals $16 million for the remainder of 2023. 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.

◦Construction of new wind-powered generating facilities and construction at existing wind-powered generating facility sites acquired from third parties at PacifiCorp totaling $14 million and $6 million for the three-month periods ended March 31, 2023 and 2022, respectively. Planned spending for the construction of additional wind-powered generating facilities and those at acquired sites totals $807 million for the remainder of 2023.

◦Repowering of wind-powered generating facilities at BHE Renewables totaling $25 million for the three-month period ended March 31, 2022. Planned spending for the repower of wind-powered facilities totals $50 million for the remainder of 2023.

•Electric distribution includes both growth and operating expenditures. Growth expenditures include spending for new customer connections and enhancements to existing customer connections. Operating expenditures include spending for ongoing distribution systems infrastructure enhancements at the Utilities and Northern Powergrid, wildfire mitigation, storm damage restoration and 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 spending for the following:

◦PacifiCorp's transmission investments primarily reflect costs associated with Energy Gateway Transmission segments that are expected to be placed in-service in 2024 through 2028. Expenditures for these projects totaled $110 million and $96 million for the ~~results~~three-month periods ended March 31, 2023 and 2022, respectively. Planned spending for these Energy Gateway Transmission segments totals $898 million for the remainder of 2023.

◦Nevada Utilities' Greenlink Nevada transmission expansion program. The Nevada Utilities have received approval from the PUCN to build a 350-mile, 525-kV transmission line, known as Greenlink West, connecting the Ft. Churchill substation to the Northwest substation to the Harry Allen substation; a 235-mile, 525-kV transmission line, known as Greenlink North, connecting the new Ft. Churchill substation to the Robinson Summit substation; a 46-mile, 345-kV transmission line from the new Ft. Churchill substation to the Mira Loma substation; and a 38-mile, 345-kV transmission line from the new Ft. Churchill substation to the Robinson Summit substation. Expenditures for the expansion program and other growth projects totaled $42 million and $30 million for the three-month periods ended March 31, 2023 and 2022, respectively. Planned spending for the expansion program estimated to be placed in-service in 2026 through 2028 and other growth projects totals $88 million for the remainder of 2023.

◦Operating expenditures include spending for 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, spending for asset modernization and the Northern Natural Gas Twin Cities Area Expansion and Spraberry Compression projects. Operating expenditures include, among other items, spending for pipeline integrity projects, automation and controls upgrades, corrosion control, unit exchanges, compressor modifications, projects related to Pipeline and Hazardous Materials Safety Administration natural gas storage rules and natural gas transmission, storage and LNG terminalling infrastructure needs to serve existing and expected demand.

•Solar generation includes growth expenditures, including spending for the following:

◦Construction of solar-powered generating facilities at PacifiCorp totaling 377 MWs of new generation and are expected to be placed in-service in 2026. Planned spending totals $12 million for the remainder of 2023.

◦Construction and operation of solar-powered generating facilities at MidAmerican Energy, primarily consisting of 141 MWs of small- and utility-scale solar generation, all of which were placed in-service in 2022. For the three-month periods ended March 31, 2023 and 2022 solar generation spend totaled $9 million and $44 million, respectively. Planned spending totals $1 million for the remainder of 2023.

◦Construction of a ~~new depreciation study. This change resulted in an increase in depreciation expense of $32~~solar-powered generating facility at Nevada Power totaling $31 million ~~($20~~and $7 million ~~after-tax)~~ for the ~~nine months~~three-month periods ended ~~September 30, 2017~~March 31, 2023 and 2022, respectively. Planned spending totals $175 million for the remainder of 2023. Construction includes expenditures for a 150-MW solar photovoltaic facility with an additional 100 MWs of co-located battery storage that will be developed in Clark County, Nevada. Commercial operation is expected ~~to increase annual depreciation~~ by ~~approximately $40 million ($25 million after-tax). Additionally, Dominion Energy revised~~ the ~~depreciable lives for its merchant generation assets, excluding Millstone, which resulted in a decrease in depreciation expense~~end of ~~$19 million ($12 million after-tax)~~2023.

•Electric battery and pumped hydro storage includes growth expenditures, including spending for the ~~nine months ended September 30, 2017 and is expected to decrease annual depreciation by approximately $26 million ($16 million after-tax).~~

following:

~~New Accounting Standards~~

~~In January 2017,~~◦Construction at the ~~Financial Accounting Standards Board issued revised accounting guidance to clarify the definition~~Nevada Utilities of a ~~business. The revised guidance affects~~100-MW battery energy storage system co-located with a 150-MW solar photovoltaic facility that will be developed in Clark County, Nevada and a 220-MW grid-tied battery energy storage system that will be developed on the evaluation of whether a transaction should be accounted for as an acquisition or disposition of an asset or a business, which may impact goodwill and related financial statement disclosures. The Companies have adopted this guidance on a prospective basis effective October 1, 2017. The adoptionsite of the ~~pronouncement~~retired Reid Gardner generating station in Clark County, Nevada, both with commercial operation expected by the end of 2023. Also, a 200-MW battery energy storage system that will ~~result~~be developed on the site of the Valmy generating station in ~~additional transactions being accounted for as asset acquisitions or dispositions.~~

~~In March 2017,~~Humboldt County, Nevada with commercial operation expected by the ~~Financial Accounting Standards Board issued revised accounting guidance~~end of 2025. Total spending for the ~~presentation~~three-month period ended March 31, 2023, was $39 million with planned spending of ~~net periodic pension~~$159 million for the remainder of 2023.

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 ~~each hierarchy level, including both current~~the exception afforded by GAAP. A discounted cash flow valuation method was used to estimate fair value. When available, the fair value of derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which PacifiCorp transacts. When quoted prices for identical contracts are not available, PacifiCorp uses forward price curves. Forward price curves represent PacifiCorp's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. PacifiCorp bases its forward price curves upon market price quotations, when available, or internally developed and ~~noncurrent portions:~~

Level 1

Level 2

Level 3

Total

(millions)

September 30, 2017

Assets

Derivatives:

Commodity

$
—

$
59

$
154

$
213

Interest rate

—

11

—

11

Foreign currency

—

25

—

25

Investments⁽¹⁾:

Equity securities:

U.S.

3,288

—

—

3,288

Fixed income:

Corporate debt instruments

—

452

—

452

Government securities

475

631

—

1,106

Cash equivalents and other

7

—

—

7

Total assets

$
3,770

$
1,178

$
154

$
5,102

Liabilities

Derivatives:

Commodity

$
—

$
41

$
1

$
42

Interest rate

—

72

—

72

Foreign currency

—

4

—

4

Total liabilities

$
—

$
117

$
1

$
118

December 31, 2016

Assets

Derivatives:

Commodity

$
—

$
115

$
147

$
262

Interest rate

—

17

—

17

Investments⁽¹⁾:

Equity securities:

U.S.

2,913

—

—

2,913

Fixed income:

Corporate debt instruments

—

487

—

487

Government securities

424

614

—

1,038

Cash equivalents and other

5

—

—

5

Total assets

$
3,342

$
1,233

$
147

$
4,722

Liabilities

Derivatives:

Commodity

$
—

$
88

$
8

$
96

Interest rate

—

53

—

53

Foreign currency

—

6

—

6

Total liabilities

$
—

$
147

$
8

$
155

commercial models, with internal and external fundamental data inputs. Market price quotations are obtained from independent energy brokers, exchanges, direct communication with market participants and actual transactions executed by PacifiCorp. Market price quotations for certain major electricity and natural gas trading hubs are generally readily obtainable for the first three years; therefore, PacifiCorp's forward price curves for those locations and periods reflect observable market quotes. Market price quotations for other electricity and natural gas trading hubs are not as readily obtainable for the first three years. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, PacifiCorp 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. Refer to Note 7 for further discussion regarding PacifiCorp's risk management and hedging activities.

~~(1)~~

Includes investments held in the nuclear decommissioning and rabbi trusts. Excludes $92 million and $89 million of assets at September 30, 2017 and December 31, 2016, 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.

PacifiCorp's investments in money market mutual funds and investment funds are stated at fair value. When available, PacifiCorp uses a readily observable quoted market price or net asset value of an identical security in an active market 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.

PacifiCorp's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of PacifiCorp'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 PacifiCorp'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 PacifiCorp's long-term debt (in millions):


	As of March 31, 2023				As of December 31, 2022
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	9,658	$	9,350	$	9,666	$	9,045

(9) Commitments and Contingencies

Commitments

PacifiCorp has the following firm commitments that are not reflected on the Consolidated Balance Sheets.

Construction Commitments

In April 2023, PacifiCorp entered into build transfer agreements totaling $1.2 billion through 2025 for the construction of certain wind-powered generating facilities in Wyoming.

Fuel Contracts

During the three-month period ended March 31, 2023, PacifiCorp entered into certain coal supply and transportation agreements totaling $247 million through 2025.

Environmental Laws and Regulations

PacifiCorp is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions performance standards, water quality, coal ash disposal, wildfire prevention and mitigation and other environmental matters that have the potential to impact its current and future operations. PacifiCorp believes it is in material compliance with all applicable laws and regulations.

Lower Klamath Hydroelectric Project

Legal Matters

PacifiCorp is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. PacifiCorp does not believe that such normal and routine litigation will have a material impact on its consolidated financial results. PacifiCorp is also involved in other kinds of 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.

Wildfires Overview

A provision for a loss contingency is recorded when it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. PacifiCorp evaluates the related range of reasonably estimated losses and records a loss based on its best estimate within that range or the lower end of the range if there is no better estimate.

In California, under inverse condemnation, courts have held that investor-owned utilities can be liable for real and personal property damages from wildfires 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 be found liable for all damages proximately caused by negligence, including real and personal property and natural resource damages; fire suppression costs; personal injury and loss of life damages; and interest.

2020 Wildfires

Based on the facts and circumstances available to PacifiCorp as of the date of this filing, which includes the status of litigation and recent settlements, PacifiCorp has accrued cumulative estimated probable losses associated with the 2020 Wildfires of $877 million through March 31, 2023. PacifiCorp's cumulative accrual includes estimates of losses for fire suppression costs, real and personal property damages, natural resource damages for certain areas and noneconomic damages such as personal injury damages and loss of life damages that are considered probable of being incurred and that it is reasonably able to estimate at this time. For certain aspects of the 2020 Wildfires for which loss is considered probable, information necessary to reasonably estimate the potential losses, such as those related to certain areas of natural resource damages, is not currently available.

The following table presents changes in PacifiCorp's liability for estimated losses associated with the 2020 Wildfires (in millions):



	Three-Month Periods
	Ended March 31,
	2023		2022
Beginning balance	$	424	$	252
Accrued losses	400		—

Ending balance	$	824	$	252

PacifiCorp's receivable for expected insurance recoveries associated with the probable losses was $287 million and $246 million, respectively, as of March 31, 2023 and December 31, 2022. During the three-month periods ended March 31, 2023 and 2022, PacifiCorp recognized probable losses net of expected insurance recoveries associated with the 2020 Wildfires of $359 million and $— million, respectively, and are recorded in operations and maintenance on the Consolidated Statements of Operations.

2022 McKinney Fire

Guarantees

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

(10) Revenue from Contracts with Customers

The following table summarizes PacifiCorp's revenue from contracts with customers ("Customer Revenue") by line of business, with further disaggregation of retail by customer class (in millions):




	Three-Month Periods
	Ended March 31,
		2023		2022
Customer Revenue:
Retail:
Residential		$	585	$	505
Commercial		430		370
Industrial		290		273
Other retail		44		37
Total retail		1,349		1,185
Wholesale		61		55
Transmission		38		32
Other Customer Revenue		32		20
Total Customer Revenue		1,480		1,292
Other revenue		4		5
Total operating revenue		$	1,484	$	1,297

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 PacifiCorp during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should be read in conjunction with PacifiCorp's historical unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10‑Q. PacifiCorp's actual results in the future could differ significantly from the historical results.

Results of Operations for the First Quarter of 2023 and 2022

Overview

Net loss for the first quarter of 2023 was $120 million, a decrease of $250 million compared to 2022 net income of $130 million. The decrease in net income was primarily due to increased operations and maintenance expense, largely due to an increase in loss accruals, net of expected insurance recoveries, associated with the 2020 Wildfires of $359 million, higher wildfire mitigation costs, including vegetation management and higher plant operations and maintenance costs, partially offset by higher income tax benefit, higher utility margin and lower other expense. Utility margin increased primarily due to higher retail prices and volumes, higher net power cost deferrals, higher average wholesale market prices and lower coal-fueled generation volumes, partially offset by higher purchased electricity costs from higher prices and volumes, higher natural gas-fueled generation costs from higher prices and volumes, lower wholesale volumes and higher coal-fueled generation prices. Retail customer volumes increased 3.3% primarily due to favorable impacts of weather, an increase in the average number of customers and an increase in commercial and residential customer usage, partially offset by a decrease in industrial customer usage. Energy generated decreased 7% for the first quarter of 2023 compared to 2022 primarily due to lower coal-fueled, wind-powered and hydroelectric generation volumes, partially offset by higher natural gas-fueled generation volumes. Wholesale electricity sales volumes decreased 47% and purchased electricity volumes increased 28%.

Non-GAAP Financial Measure

Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as utility margin, to help evaluate results of operations. Utility margin is calculated as operating revenue less cost of fuel and energy, which are captions presented on the Consolidated Statements of Operations.

PacifiCorp's cost of fuel and energy is generally recovered from its customers through regulatory recovery mechanisms and as a result, changes in PacifiCorp's revenue are comparable to changes in such expenses. As such, management believes utility margin more appropriately and concisely explains profitability rather than a discussion of revenue and cost of fuel and energy separately. Management believes the presentation of utility margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.

Utility margin is not a measure calculated in accordance with GAAP and should be viewed as a supplement to and not a substitute for operating income which is the most comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to operating income (in millions):


	First Quarter
	2023		2022		Change
Utility margin:
Operating revenue	$	1,484	$	1,297	$	187	14	%
Cost of fuel and energy	614		465		149		32
Utility margin	870		832		38		5
Operations and maintenance	705		277		428		155
Depreciation and amortization	279		280		(1)		—
Property and other taxes	53		59		(6)		(10)
Operating (loss) income	$	(167)	$	216	$	(383)	(177)	%

Utility Margin

A comparison of key operating results related to utility margin is as follows:


	First Quarter
	2023		2022		Change
Utility margin (in millions):
Operating revenue	$	1,484	$	1,297	$	187	14	%
Cost of fuel and energy	614		465		149		32
Utility margin	$	870	$	832	$	38	5	%

Sales (GWhs):
Residential	5,102		4,764		338		7	%
Commercial	4,983		4,550		433		10
Industrial, irrigation and other	4,209		4,523		(314)		(7)
Total retail	14,294		13,837		457		3
Wholesale	825		1,553		(728)		(47)
Total sales	15,119		15,390		(271)		(2)	%


Average number of retail customers (in thousands)	2,057		2,025		32		2	%

Average revenue per MWh:
Retail	$	93.82	$	85.46	$	8.36	10	%
Wholesale	$	86.45	$	39.12	$	47.33	121	%

Heating degree days	5,205		4,745		460		10	%

Cooling degree days	—		5		(5)		(100)	%

Sources of energy (GWhs)(1):
Coal	5,555		6,911		(1,356)		(20)	%
Natural gas	3,955		3,115		840		27
Wind(2)	2,083		2,392		(309)		(13)
Hydroelectric and other(2)	812		984		(172)		(17)
Total energy generated	12,405		13,402		(997)		(7)
Energy purchased	4,128		3,223		905		28
Total	16,533		16,625		(92)		(1)	%

Average cost of energy per MWh:
Energy generated(3)	$	28.35	$	18.83	$	9.52	51	%
Energy purchased	$	77.72	$	55.49	$	22.23	40	%

(1)GWh amounts are net of energy used by the related generating facilities.

(2) All or some of the renewable energy attributes associated with generation from these sources may be: (a) used in future years to comply with RPS or other regulatory requirements or (b) sold to third parties in the form of Renewable Energy Credits or other environmental commodities.

(3) The average cost per MWh of energy generated includes only the cost of fuel associated with the generating facilities.

Quarter Ended March 31, 2023 compared to Quarter Ended March 31, 2022

Utility margin increased $38 million, or 5%, for the first quarter of 2023 compared to 2022 primarily due to:

•$159 million increase in retail revenue due to higher average prices and higher volumes. Retail customer volumes increased 3.3% primarily due to favorable impacts of weather, mainly in Oregon, an increase in the average number of customers and an increase in commercial and residential customer usage, partially offset by a decrease in industrial customer usage across all states except Idaho;

•$97 million of higher deferred net power costs net of amortization of previous deferrals in accordance with established adjustment mechanisms;

•$17 million of higher other revenue primarily due to higher wheeling revenue and higher revenues associated with sales of greenhouse gas allowances;

•$11 million increase in wholesale revenue primarily due to higher average market prices, partially offset by lower volumes; and

•$9 million of lower coal-fueled generation costs primarily due to lower volumes, partially offset by higher average prices.

The increases above were partially offset by:

•$142 million of higher purchased electricity costs from higher average market prices and higher volumes; and

•$109 million of higher natural gas-fueled generation costs due to higher average market prices and higher volumes.

Operations and maintenance increased $428 million for the first quarter of 2023 compared to 2022 primarily due to a $359 million increase in loss accruals, net of expected insurance recoveries, associated with the 2020 Wildfires, $23 million of higher wildfire mitigation costs, including vegetation management and amortization of amounts previously deferred in Oregon, $21 million of higher general and plant maintenance costs, $10 million of higher labor and benefit expenses, and $8 million of higher demand-side management amortization expense (offset in retail revenue).

Property and other taxes decreased $6 million, or 10%, for the first quarter of 2023 compared to 2022 primarily due to lower property tax rates in Utah.

Interest expense increased $18 million, or 17%, for the first quarter of 2023 compared to 2022 primarily due to higher average long-term debt balances.

Allowance for borrowed and equity funds increased $21 million for the first quarter of 2023 compared to 2022 primarily due to higher qualified construction work-in-progress balances.

Interest and dividend income increased $12 million for the first quarter of 2023 compared to 2022 primarily due to higher investment income due to higher average interest rates and the recording of interest on higher deferred net power cost balances.

Other, net increased $6 million for the first quarter of 2023 compared to 2022 primarily due to higher cash surrender values of Supplemental Executive Retirement Plan life insurance policies driven by market increases and a favorable change in ~~Dominion~~deferred compensation and long-term incentive plan primarily due to market movements (offset in operations and maintenance expense).

Income tax (benefit) expense decreased $112 million to a benefit of $110 million for the first quarter of 2023 compared to an expense of $2 million for the first quarter of 2022 and the effective tax rate was 48% for 2023 and 2% for 2022. The $112 million decrease in income tax expense to an income tax benefit is primarily due to the increase in loss accruals, net of expected insurance recoveries, associated with the 2020 Wildfires during the first quarter of 2023 and the release of a valuation allowance on state net operating loss carryforwards in the first quarter of 2023 compared to the establishment of a state valuation allowance in 2022.

Liquidity and Capital Resources

As of March 31, 2023, PacifiCorp's total net liquidity was as follows (in millions):


Cash and cash equivalents	$	19

Credit facilities	2,000
Less:

Tax-exempt bond support and letters of credit	(249)
Net credit facilities	1,751

Total net liquidity	$	1,770
Credit facilities:
Maturity dates	2024, 2025

Operating Activities

Net cash flows from operating activities for the three-month periods ended March 31, 2023 and 2022, were $339 million and $537 million, respectively. The decrease is primarily due to higher wholesale and fuel purchases, collateral returned to counterparties and operations and maintenance expenses, partially offset by higher collections from retail customers.

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

Investing Activities

Net cash flows from investing activities for the three-month periods ended March 31, 2023 and 2022, were $(644) million and $(371) million, respectively. The change is primarily due to an increase in capital expenditures of $269 million. Refer to "Future Uses of Cash" for discussion of capital expenditures.

Financing Activities

Net cash flows from financing activities for the three-month period ended March 31, 2023, were $(311) million. Uses of cash consisted primarily of $300 million for common stock dividends paid to PPW Holdings LLC and $9 million for the repayment of long-term debt.

Net cash flows from financing activities for the three-month period ended March 31, 2022, were $(11) million. Uses of cash consisted substantially of $9 million for the repayment of long-term debt.

Short-term Debt

Regulatory authorities limit PacifiCorp to $2.0 billion of short-term debt. As of March 31, 2023, and December 31, 2022, PacifiCorp had no short-term debt outstanding.

Debt Authorizations

PacifiCorp currently has regulatory authority from the OPUC and the Idaho Public Utilities Commission to issue an additional $5 billion of long-term debt. PacifiCorp must make a notice filing with the WUTC prior to any future issuance. PacifiCorp currently has an effective shelf registration statement with the SEC to issue an indeterminate amount of first mortgage bonds through September 2023.

Common Shareholders' Equity

In January 2023, PacifiCorp declared a common stock dividend of $300 million, paid in February 2023, to PPW Holdings LLC.

Future Uses of Cash

PacifiCorp 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, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which PacifiCorp has access to external financing depends on a variety of factors, including PacifiCorp's credit ratings, investors' judgment of risk associated with PacifiCorp and conditions in the overall capital markets, including the condition of the utility industry.

Capital Expenditures

PacifiCorp 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 customer rates; changes in environmental and other rules and regulations; outcomes of regulatory proceedings, including regulatory filings for Certificates of Public Convenience and Necessity; changes in income tax laws; general business conditions; new customer requests; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital.

PacifiCorp'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
	2022		2023		2023

Wind generation	$	8	$	17	$	833
Electric distribution	139		177		781
Electric transmission	156		169		1,484
Solar generation	—		—		19
Electric battery and pumped hydro storage	1		1		24
Other	70		279		521
Total	$	374	$	643	$	3,662

PacifiCorp has included estimates for new renewable and carbon free generation resources, conversion of certain coal-fueled units to natural gas-fueled units, energy storage assets and associated transmission assets in its forecast capital expenditures based on its 2021 IRP. These estimates are likely to change as a result of the associated RFP process. PacifiCorp's historical and forecast capital expenditures include the following:

•Wind generation includes both growth projects and operating expenditures. Growth projects include construction of new wind-powered generating facilities and construction at existing wind-powered generating facility sites acquired from third parties totaling $14 million and $6 million for the three-month periods ended March 31, 2023 and 2022, respectively. Planned spending for the construction of additional wind-powered generating facilities and those at acquired sites totals $807 million for the remainder of 2023 and is primarily for the Rock Creek I and Rock Creek II projects to be constructed in Wyoming totaling 590 MWs that are expected to be placed in-service in 2024 and 2025.

•Electric distribution includes both growth projects and operating expenditures. Operating expenditures includes spend on wildfire mitigation. Expenditures for wildfire mitigation totaled $33 million and $22 million for the three-month periods ended March 31, 2023 and 2022, respectively. Planned spending for wildfire mitigation totals $162 million for the remainder of 2023. The remaining investments primarily relate to expenditures for new connections and distribution operations.

•Electric transmission includes both growth projects and operating expenditures. Transmission growth investments primarily reflect costs associated with Energy Gateway Transmission segments that are expected to be placed in-service in 2024 through 2028. Expenditures for these projects totaled $110 million and $96 million for the three-month periods ended March 31, 2023 and 2022, respectively. Planned spending for these Energy Gateway Transmission segments totals $898 million for the remainder of 2023.

•Other includes both growth projects and operating expenditures. Expenditures for information technology totaled $46 million and $45 million for the three-month periods ended March 31, 2023 and 2022, respectively. Planned information technology spending totals $180 million for the remainder of 2023. The remaining investments relate to operating projects that consist of routine expenditures for generation and other infrastructure needed to serve existing and expected demand.

Energy Supply Planning

As required by certain state regulations, PacifiCorp uses an IRP to develop a long-term resource plan to ensure that PacifiCorp can continue to provide reliable and cost-effective electric service to its customers while maintaining compliance with existing and evolving environmental laws and regulations. PacifiCorp files its IRP biennially with the state commissions in each of the six states where PacifiCorp operates. Five states indicate whether the IRP meets the state commission's IRP standards and guidelines, a process referred to as "acknowledgment" in some states. Acknowledgment by a state commission does not address cost recovery or prudency of resources ultimately selected.

In September 2021, PacifiCorp filed its 2021 IRP with its state commissions and subsequently filed its 2021 IRP Update in March and April 2022. Reviews of the 2021 IRP by the Wyoming Public Service Commission and the WUTC are ongoing.

In March 2023, PacifiCorp filed its 2023 IRP in Idaho, Oregon and Wyoming. A 60-day post-filing extended comment period has been added to the 2023 IRP to provide opportunity for additional stakeholder feedback. PacifiCorp will consider feedback during the first 30 days and then prepare an addendum, if warranted, to the filed IRP on May 30, 2023.

The 2023 IRP is off cycle with regard to Washington's four-year IRP cycle and has instead been filed in that state as the "Washington Two-Year Progress Report," aligned with the Clean Energy Transformation Act requirements. The March 2023 filing is considered informational in Utah, pending the potential addendum to be filed in May 2023.

Requests for Proposals

PacifiCorp issues individual RFPs to procure resources identified in the IRP or resources driven by customer demands. The IRP and the RFPs provide for the identification and staged procurement of resources to meet load or state-specific compliance obligations. Depending upon the specific RFP, applicable laws and regulations may require PacifiCorp to file draft RFPs with the UPSC, the OPUC and the WUTC. Approval by the UPSC, the OPUC or the WUTC may be required depending on the nature of the RFPs.

PacifiCorp's 2022 All-Source RFP was issued to market in April 2022. In December 2022, PacifiCorp bid 12 eligible self-build (benchmark) resources and in March 2023, PacifiCorp received 302 bids from 74 developers and 93 different projects sites across six states. A final shortlist is expected later in 2023 with resources contracted by December 2023. PacifiCorp anticipates a similar all-source RFP will be required in connection with the 2023 IRP.

Material Cash Requirements

As of March 31, 2023, there have been no material changes in cash requirements from the information provided in Item 7 of PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2022, other than those disclosed in Note 9 of the Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

Regulatory Matters

PacifiCorp is subject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for discussion regarding PacifiCorp's current regulatory matters.

Environmental Laws and Regulations

PacifiCorp is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions performance standards, water quality, coal ash disposal and other environmental matters that have the potential to impact PacifiCorp'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 and local agencies. PacifiCorp believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and PacifiCorp is unable to predict the impact of the changing laws and regulations on its operations and financial results.

Refer to "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information regarding environmental laws and regulations.

Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the 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 future as additional information becomes available. Estimates are used for, but not limited to, the accounting for the effects of certain types of regulation, pension and other postretirement benefits, income taxes, revenue recognition-unbilled revenue and wildfire loss contingencies. For additional discussion of PacifiCorp's critical accounting estimates, see Item 7 of PacifiCorp's Annual Report on Form 10-K for the year ended December 31, 2022. There have been no significant changes in PacifiCorp's assumptions regarding critical accounting estimates since December 31, 2022.

MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company

Consolidated Financial Section

PART I

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

MidAmerican Energy Company

Results of Review of Interim Financial Information

We have reviewed the accompanying balance sheet of MidAmerican Energy Company ("MidAmerican Energy") as of March 31, 2023, the related statements of operations, changes in shareholder's equity, and cash flows for the three-month periods ended March 31, 2023 and 2022, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the balance sheet of MidAmerican Energy as of December 31, 2022, and the related statements of operations, changes in shareholder's equity, and cash flows for the year then ended (not presented herein); and in our report dated February 24, 2023, we expressed an unqualified opinion on those financial statements. In our opinion, the information set forth in the accompanying balance sheet as of December 31, 2022, is fairly stated, in all material respects, in relation to the balance sheet from which it has been derived.

Basis for Review Results

This interim financial information is the responsibility of MidAmerican Energy's management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to MidAmerican Energy in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our reviews in accordance with standards of the PCAOB. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

/s/ Deloitte & Touche LLP

Des Moines, Iowa

May 5, 2023

MIDAMERICAN ENERGY COMPANY

BALANCE SHEETS (Unaudited)

(Amounts in millions)


	As of
	March 31,		December 31,
	2023		2022
ASSETS
Current assets:
Cash and cash equivalents	$	57	$	258
Trade receivables, net	387		536
Income tax receivable	275		42
Inventories	280		277
Prepayments	123		91
Other current assets	36		66
Total current assets	1,158		1,270

Property, plant and equipment, net	20,981		21,091
Regulatory assets	571		550
Investments and restricted investments	942		902
Other assets	155		165

Total assets	$	23,807	$	23,978

The accompanying notes are an integral part of these financial statements.

MIDAMERICAN ENERGY COMPANY

BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)


	As of
	March 31,		December 31,
	2023		2022
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	395	$	536
Accrued interest	88		85
Accrued property, income and other taxes	142		170

Current portion of long-term debt	310		317
Other current liabilities	106		93
Total current liabilities	1,041		1,201

Long-term debt	7,412		7,412
Regulatory liabilities	836		1,119
Deferred income taxes	3,452		3,433
Asset retirement obligations	778		683
Other long-term liabilities	500		485
Total liabilities	14,019		14,333

Commitments and contingencies (Note 8)

Shareholder's equity:
Common stock - 350 shares authorized, no par value, 71 shares issued and outstanding	—		—
Additional paid-in capital	561		561
Retained earnings	9,227		9,084

Total shareholder's equity	9,788		9,645

Total liabilities and shareholder's equity	$	23,807	$	23,978

The accompanying notes are an integral part of these financial statements.

MIDAMERICAN ENERGY COMPANY

STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)


	Three-Month Periods
	Ended March 31,
		2023		2022
Operating revenue:
Regulated electric		$	591	$	608
Regulated natural gas and other		329		397
Total operating revenue		920		1,005

Operating expenses:
Cost of fuel and energy		115		125
Cost of natural gas purchased for resale and other		236		298
Operations and maintenance		205		192
Depreciation and amortization		234		250
Property and other taxes		42		40
Total operating expenses		832		905

Operating income		88		100

Other income (expense):
Interest expense		(80)		(78)
Allowance for borrowed funds		4		4
Allowance for equity funds		11		15
Other, net		16		(3)
Total other income (expense)		(49)		(62)

Income before income tax expense (benefit)		39		38
Income tax expense (benefit)		(203)		(206)

Net income		$	242	$	244

The accompanying notes are an integral part of these financial statements.

MIDAMERICAN ENERGY COMPANY

STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited)

(Amounts in millions)


	Common Stock		Additional Paid-in Capital		Retained Earnings		Total Shareholder's Equity






Balance, December 31, 2021	$	—	$	561	$	8,399	$	8,960
Net income	—		—		244		244

Balance, March 31, 2022	$	—	$	561	$	8,643	$	9,204







Balance, December 31, 2022	$	—	$	561	$	9,084	$	9,645
Net income	—		—		242		242
Common stock dividend	—		—		(100)		(100)
Other equity transactions	—		—		1		1
Balance, March 31, 2023	$	—	$	561	$	9,227	$	9,788

The accompanying notes are an integral part of these financial statements.

MIDAMERICAN ENERGY COMPANY

STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)


	Three-Month Periods
	Ended March 31,
	2023		2022
Cash flows from operating activities:
Net income	$	242	$	244
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	234		250
Amortization of utility plant to other operating expenses	8		9
Allowance for equity funds	(11)		(15)
Deferred income taxes and investment tax credits, net	32		16
Settlements of asset retirement obligations	(6)		(7)
Other, net	8		10
Changes in other operating assets and liabilities:
Trade receivables and other assets	131		42
Inventories	(3)		49

Pension and other postretirement benefit plans	(3)		3
Accrued property, income and other taxes, net	(263)		(244)
Accounts payable and other liabilities	(81)		3
Net cash flows from operating activities	288		360

Cash flows from investing activities:
Capital expenditures	(382)		(459)
Purchases of marketable securities	(48)		(105)
Proceeds from sales of marketable securities	42		102
Other, net	4		1
Net cash flows from investing activities	(384)		(461)

Cash flows from financing activities:
Common stock dividend	(100)		—

Repayments of long-term debt	(7)		(1)

Other, net	(1)		1
Net cash flows from financing activities	(108)		—

Net change in cash and cash equivalents and restricted cash and cash equivalents	(204)		(101)
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	268		239
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	64	$	138

The accompanying notes are an integral part of these financial statements.

MIDAMERICAN ENERGY COMPANY

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

(1) General

MidAmerican Energy Company ("MidAmerican Energy") is a public utility with electric and natural gas operations and is the principal subsidiary of MHC Inc. ("MHC"). MHC is a holding company that conducts no business other than the ownership of its subsidiaries. MHC's nonregulated subsidiary is Midwest Capital Group, Inc. MHC is the direct wholly owned subsidiary of MidAmerican Funding, LLC ("MidAmerican Funding"), which is an Iowa limited liability company with Berkshire Hathaway Energy Company ("BHE") as its sole member. BHE is a holding company based in Des Moines, Iowa, that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

The unaudited Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and 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 disclosures required by GAAP for annual financial statements. Management believes the unaudited Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Financial Statements as of March 31, 2023, and for the three-month periods ended March 31, 2023 and 2022. The results of operations for the three-month period ended March 31, 2023, are not necessarily indicative of the results to be expected for the full year.

The preparation of the unaudited Financial Statements in 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 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 Financial Statements. Note 2 of Notes to Financial Statements included in MidAmerican Energy's Annual Report on Form 10-K for the year ended December 31, 2022, describes the most significant accounting policies used in the preparation of the unaudited Financial Statements. There have been no significant changes in MidAmerican Energy's accounting policies or its assumptions regarding significant accounting estimates during the three-month period ended March 31, 2023.

(2) Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

Cash equivalents consist of funds invested in money market mutual funds, U.S. 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 consist substantially of funds restricted for wildlife preservation. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as presented on the Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Balance Sheets (in millions):


	As of
	March 31,		December 31,
	2023		2022

Cash and cash equivalents	$	57	$	258
Restricted cash and cash equivalents in other current assets	7		10
Total cash and cash equivalents and restricted cash and cash equivalents	$	64	$	268

(3) Property, Plant and Equipment, Net

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


		As of
		March 31,		December 31,
	Depreciable Life	2023		2022
Utility plant:
Generation	20-62 years	$	18,385	$	18,582
Transmission	55-80 years	2,672		2,662
Electric distribution	15-80 years	4,983		4,931
Natural gas distribution	30-75 years	2,166		2,144
Utility plant in-service		28,206		28,319
Accumulated depreciation and amortization		(8,210)		(8,024)
Utility plant in-service, net		19,996		20,295



Nonregulated property, net of accumulated depreciation and amortization	20-50 years	6		6
		20,002		20,301
Construction work-in-progress		979		790
Property, plant and equipment, net		$	20,981	$	21,091

Under a revenue sharing arrangement in Iowa, MidAmerican Energy accrues throughout the year a regulatory liability based on the extent to which its anticipated annual equity return exceeds specified thresholds, with an equal amount recorded in depreciation and amortization expense. The annual regulatory liability accrual reduces utility plant upon final determination of the amount. For the three-month periods ended March 31, 2023 and 2022, $20 million and $42 million, respectively, is reflected in depreciation and amortization expense on the Statement of Operations.

(4) Income Taxes

A reconciliation of the federal statutory income tax rate to MidAmerican Energy's effective income tax rate applicable to income before income tax expense (benefit) is as follows:


	Three-Month Periods
	Ended March 31,
		2023		2022

Federal statutory income tax rate		21	%	21	%
Income tax credits		(518)		(534)
State income tax, net of federal income tax impacts		(18)		(21)
Effects of ratemaking		(8)		(8)
Other, net		2		—
Effective income tax rate		(521)	%	(542)	%

Income tax credits relate primarily to production tax credits ("PTC") from MidAmerican Energy's wind- and solar-powered generating facilities. Federal renewable electricity PTCs are earned as energy from qualifying wind- and solar-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. MidAmerican Energy recognizes its renewable electricity PTCs throughout the year based on when the credits are earned and excludes them from the annual effective tax rate that is the basis for the interim recognition of other income tax expense. Wind- and solar-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service. PTCs recognized for the three-month periods ended March 31, 2023 and 2022, totaled $202 million and $203 million, respectively.

Berkshire Hathaway includes BHE and subsidiaries in its U.S. federal and Iowa state income tax returns. Consistent with established regulatory practice, MidAmerican Energy's provision for income tax has been computed on a stand-alone basis, and substantially all of its currently payable or receivable income tax is remitted to or received from BHE. MidAmerican Energy made net cash payments for income tax to BHE totaling $1 million and $— million for the three-month periods ended March 31, 2023 and 2022, respectively.

(5) Employee Benefit Plans

MidAmerican Energy sponsors a noncontributory defined benefit pension plan covering a majority of all employees of BHE and its domestic energy subsidiaries other than PacifiCorp and NV Energy, Inc. MidAmerican Energy also sponsors certain postretirement healthcare and life insurance benefits covering substantially all retired employees of BHE and its domestic energy subsidiaries other than PacifiCorp and NV Energy, Inc.

Net periodic benefit cost (credit) for the plans of MidAmerican Energy and the aforementioned affiliates included the following components (in millions):


	Three-Month Periods
	Ended March 31,
		2023		2022
Pension:
Service cost		$	3	$	5
Interest cost		8		5
Expected return on plan assets		(8)		(7)
Settlement		(5)		2

Net periodic benefit cost (credit)		$	(2)	$	5

Other postretirement:
Service cost		$	1	$	2
Interest cost		3		2
Expected return on plan assets		(4)		(4)

Net periodic benefit cost (credit)		$	—	$	—

Amounts other than the service cost for pension and other postretirement benefit plans are recorded in Other, net in the Statements of Operations. Employer contributions to the pension and other postretirement benefit plans during 2023 are expected to be $7 million and $2 million, respectively. As of March 31, 2023, $2 million and $1 million of contributions had been made to the pension and other postretirement benefit plans, respectively.

(6) Asset Retirement Obligations

(7) Fair Value Measurements

The carrying value of MidAmerican Energy'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. MidAmerican Energy has various financial assets and liabilities that are measured at fair value on the 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 MidAmerican Energy has the ability to access at the measurement date.

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

The following table presents MidAmerican Energy's financial assets and liabilities recognized on the 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, 2023:
Assets:
Commodity derivatives	$	2	$	7	$	—	$	(5)	$	4
Money market mutual funds	67		—		—		—		67
Debt securities:
U.S. government obligations	225		—		—		—		225
International government obligations	—		1		—		—		1
Corporate obligations	—		70		—		—		70
Municipal obligations	—		4		—		—		4

Equity securities:
U.S. companies	385		—		—		—		385
International companies	8		—		—		—		8
Investment funds	22		—		—		—		22
	$	709	$	82	$	—	$	(5)	$	786

Liabilities - commodity derivatives	$	—	$	(10)	$	(5)	$	10	$	(5)


	Input Levels for Fair Value Measurements
	Level 1		Level 2		Level 3		Other(1)		Total
As of December 31, 2022:
Assets:
Commodity derivatives	$	1	$	37	$	6	$	(10)	$	34
Money market mutual funds	225		—		—		—		225
Debt securities:
U.S. government obligations	215		—		—		—		215
International government obligations	—		1		—		—		1
Corporate obligations	—		70		—		—		70
Municipal obligations	—		3		—		—		3
Agency, asset and mortgage-backed obligations	—		1		—		—		1
Equity securities:
U.S. companies	360		—		—		—		360
International companies	8		—		—		—		8
Investment funds	16		—		—		—		16
	$	825	$	112	$	6	$	(10)	$	933

Liabilities - commodity derivatives	$	—	$	(12)	$	(1)	$	10	$	(3)

(1)Represents netting under master netting arrangements and a net cash collateral receivable of $5 million and $— million as of March 31, 2023 and December 31, 2022, respectively.

MidAmerican Energy's investments in money market mutual funds and debt and equity securities are stated at fair value, with debt securities accounted for as available-for-sale securities. 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 MidAmerican Energy's commodity derivative assets and liabilities measured at fair value on a recurring basis ~~and included in the~~using significant Level 3 inputs (in millions):


	Three-Month Periods
	Ended March 31,
		2023		2022

Beginning balance		$	5	$	(5)
Changes in fair value recognized in net regulatory assets		(13)		13
Settlements		3		(4)
Ending balance		$	(5)	$	4

MidAmerican Energy's long-term debt is carried at cost on the Balance Sheets. The fair value ~~category:~~

Three Months Ended September 30,

Nine Months Ended September 30,

2017

2016

2017

2016

(millions)

Beginning balance

$
152

$
124

$
139

$
95

Total realized and unrealized gains (losses):

Included in earnings

(11
)

(7
)

(36
)

(23
)
Included in other comprehensive income

—

—

—

2

Included in regulatory assets/liabilities

11

(37
)

34

(5
)
Settlements

1

9

13

27

Transfers out of Level 3

—

—

3

(7
)
Ending balance

$
153

$
89

$
153

$
89

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

$
1

$
—

$
1

$
—

of MidAmerican Energy'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 MidAmerican Energy's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents ~~Dominion Energy’s classification~~the carrying value and estimated fair value of ~~gains~~MidAmerican Energy's long-term debt (in millions):


	As of March 31, 2023				As of December 31, 2022
	Carrying Value		Fair Value		Carrying Value		Fair Value

Long-term debt	$	7,722	$	7,127	$	7,729	$	6,964

(8) Commitments and ~~losses~~Contingencies

Commitments

MidAmerican Energy has the following firm commitments that are not reflected on the Balance Sheets.

Construction Commitments

Environmental Laws and Regulations

Legal Matters

MidAmerican Energy is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. MidAmerican Energy does not believe that such normal and routine litigation will have a material impact on its financial results.

Transmission Rates

MidAmerican Energy's wholesale transmission rates are set annually using formula rates approved by the Federal Energy Regulatory Commission ("FERC") subject to true-up for actual cost of service. In November 2013 and February 2015, a coalition of intervenors filed successive complaints with the FERC requesting that the base return on equity ("ROE") used to determine rates in effect prior to September 2016 no longer be found just and reasonable and sought to reduce the base ROE. In August 2022, the U.S. Court of Appeals for the District of Columbia Circuit issued an opinion vacating all orders related to the complaints and remanding them back to the FERC. MidAmerican Energy cannot predict the ultimate outcome of these matters or the amount of refunds, if any, and accordingly, has reversed its previously accrued liability for potential refunds of amounts collected under the higher ROE during the periods covered by the complaints.

(9) Revenue from Contracts with Customers

The following table summarizes MidAmerican Energy's revenue from contracts with customers ("Customer Revenue") by line of business, with further disaggregation of retail by customer class, including a reconciliation to MidAmerican Energy's reportable segment information included in ~~earnings~~Note 11 (in millions):


	For the Three-Month Period Ended March 31, 2023
		Electric		Natural Gas		Other		Total
Customer Revenue:
Retail:
Residential		$	167	$	199	$	—	$	366
Commercial		75		78		—		153
Industrial		214		7		—		221
Natural gas transportation services		—		13		—		13
Other retail		35		(1)		—		34
Total retail		491		296		—		787
Wholesale		71		29		—		100
Multi-value transmission projects		14		—		—		14
Other Customer Revenue		—		—		3		3
Total Customer Revenue		576		325		3		904
Other revenue		15		1		—		16
Total operating revenue		$	591	$	326	$	3	$	920


	For the Three-Month Period Ended March 31, 2022
		Electric		Natural Gas		Other		Total
Customer Revenue:
Retail:
Residential		$	168	$	225	$	—	$	393
Commercial		74		88		—		162
Industrial		198		9		—		207
Natural gas transportation services		—		14		—		14
Other retail		32		1		—		33
Total retail		472		337		—		809
Wholesale		104		58		—		162
Multi-value transmission projects		15		—		—		15
Other Customer Revenue		—		—		1		1
Total Customer Revenue		591		395		1		987
Other revenue		17		1		—		18
Total operating revenue		$	608	$	396	$	1	$	1,005

(10) Shareholder's Equity

In January 2023, MidAmerican Energy paid $100 million in cash dividends to its parent company, MHC.

(11) Segment Information

MidAmerican Energy has identified two reportable segments: regulated electric and regulated natural gas. The regulated electric segment derives most of its revenue from regulated retail sales of electricity to residential, commercial, and industrial customers and from wholesale sales. The regulated natural gas segment derives most of its revenue from regulated retail sales of natural gas to residential, commercial, and industrial customers and also obtains revenue by transporting natural gas owned by others through its distribution system. Pricing for regulated electric and natural gas sales are established separately by regulatory agencies; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and evaluating performance. Common operating costs, interest income, interest expense and income tax expense are allocated to each segment based on certain factors, which primarily relate to the nature of the cost.

The following tables provide information on a reportable segment basis (in millions):


	Three-Month Periods
	Ended March 31,
		2023		2022
Operating revenue:
Regulated electric		$	591	$	608
Regulated natural gas		326		396
Other		3		1
Total operating revenue		$	920	$	1,005

Operating income:
Regulated electric		$	50	$	51
Regulated natural gas		38		49

Total operating income		88		100
Interest expense		(80)		(78)
Allowance for borrowed funds		4		4
Allowance for equity funds		11		15
Other, net		16		(3)
Total income before income tax expense (benefit)		$	39	$	38


	As of
	March 31, 2023		December 31, 2022
Assets:
Regulated electric	$	22,091	$	22,092
Regulated natural gas	1,716		1,885
Other	—		1
Total assets	$	23,807	$	23,978

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Managers and Member of

MidAmerican Funding, LLC

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of MidAmerican Funding, LLC and subsidiaries ("MidAmerican Funding") as of March 31, 2023, the related consolidated statements of operations, changes in member's equity, and cash flows for the three-month periods ended March 31, 2023 and 2022, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the ~~Level~~United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB) and in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet of MidAmerican Funding as of December 31, 2022, and the related consolidated statements of operations, changes in member's equity, and cash flows for the year then ended (not presented herein); and in our report dated February 24, 2023, 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, 2022, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

This interim financial information is the responsibility of MidAmerican Funding's management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to MidAmerican Funding in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our reviews in accordance with standards of the PCAOB and with auditing standards generally accepted in the United States of America applicable to reviews of interim financial information. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB and with auditing standards generally accepted in the United States of America, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

/s/ Deloitte & Touche LLP

Des Moines, Iowa

May 5, 2023

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)


	As of
	March 31,		December 31,
	2023		2022
ASSETS
Current assets:
Cash and cash equivalents	$	58	$	261
Trade receivables, net	387		536
Income tax receivable	274		43
Inventories	280		277
Prepayments	123		91
Other current assets	44		66
Total current assets	1,166		1,274

Property, plant and equipment, net	20,982		21,092
Goodwill	1,270		1,270
Regulatory assets	571		550
Investments and restricted investments	944		904
Other assets	154		164

Total assets	$	25,087	$	25,254

The accompanying notes are an integral part of these consolidated financial statements.

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)


	As of
	March 31,		December 31,
	2023		2022
LIABILITIES AND MEMBER'S EQUITY
Current liabilities:
Accounts payable	$	395	$	536
Accrued interest	89		90
Accrued property, income and other taxes	142		170


Current portion of long-term debt	310		317
Other current liabilities	106		93
Total current liabilities	1,042		1,206

Long-term debt	7,652		7,652
Regulatory liabilities	836		1,119
Deferred income taxes	3,451		3,431
Asset retirement obligations	778		683
Other long-term liabilities	500		484
Total liabilities	14,259		14,575

Commitments and contingencies (Note 8)

Member's equity:
Paid-in capital	1,679		1,679
Retained earnings	9,149		9,000

Total member's equity	10,828		10,679

Total liabilities and member's equity	$	25,087	$	25,254

The accompanying notes are an integral part of these consolidated financial statements.

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)


	Three-Month Periods
	Ended March 31,
		2023		2022
Operating revenue:
Regulated electric		$	591	$	608
Regulated natural gas and other		329		397
Total operating revenue		920		1,005

Operating expenses:
Cost of fuel and energy		115		125
Cost of natural gas purchased for resale and other		236		298
Operations and maintenance		205		192
Depreciation and amortization		234		250
Property and other taxes		42		40
Total operating expenses		832		905

Operating income		88		100

Other income (expense):
Interest expense		(84)		(82)
Allowance for borrowed funds		4		4
Allowance for equity funds		11		15
Other, net		28		(4)
Total other income (expense)		(41)		(67)

Income before income tax expense (benefit)		47		33
Income tax expense (benefit)		(202)		(208)

Net income		$	249	$	241

The accompanying notes are an integral part of these consolidated financial statements.

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER'S EQUITY (Unaudited)

(Amounts in millions)


	Paid-in Capital		Retained Earnings		Total Member's Equity






Balance, December 31, 2021	$	1,679	$	8,122	$	9,801
Net income	—		241		241

Balance, March 31, 2022	$	1,679	$	8,363	$	10,042






Balance, December 31, 2022	$	1,679	$	9,000	$	10,679
Net income	—		249		249
Distribution to member	—		(100)		(100)

Balance, March 31, 2023	$	1,679	$	9,149	$	10,828

The accompanying notes are an integral part of these consolidated financial statements.

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)


	Three-Month Periods
	Ended March 31,
	2023		2022
Cash flows from operating activities:
Net income	$	249	$	241
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	234		250
Amortization of utility plant to other operating expenses	8		9
Allowance for equity funds	(11)		(15)
Deferred income taxes and investment tax credits, net	32		16

Settlements of asset retirement obligations	(6)		(7)
Other, net	(5)		10
Changes in other operating assets and liabilities:
Trade receivables and other assets	123		43
Inventories	(3)		49

Pension and other postretirement benefit plans	(3)		3
Accrued property, income and other taxes, net	(261)		(245)
Accounts payable and other liabilities	(85)		(1)
Net cash flows from operating activities	272		353

Cash flows from investing activities:
Capital expenditures	(382)		(459)
Purchases of marketable securities	(48)		(105)
Proceeds from sales of marketable securities	42		102
Proceeds from sale of investment	12		—
Other, net	5		1
Net cash flows from investing activities	(371)		(461)

Cash flows from financing activities:
Distribution to member	(100)		—

Repayments of long-term debt	(7)		(1)
Net change in note payable to affiliate	—		8

Other, net	(1)		—
Net cash flows from financing activities	(108)		7

Net change in cash and cash equivalents and restricted cash and cash equivalents	(207)		(101)
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	271		240
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	64	$	139

The accompanying notes are an integral part of these consolidated financial statements.

MIDAMERICAN FUNDING, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) General

MidAmerican Funding, LLC ("MidAmerican Funding") is an Iowa limited liability company with Berkshire Hathaway Energy Company ("BHE") as its sole member. BHE is a holding company based in Des Moines, Iowa, that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway"). MidAmerican Funding's direct wholly owned subsidiary is MHC Inc. ("MHC"), which constitutes substantially all of MidAmerican Funding's assets, liabilities and business activities except those related to MidAmerican Funding's long-term debt securities. MHC conducts no business other than the ownership of its subsidiaries. MHC's principal subsidiary is MidAmerican Energy Company ("MidAmerican Energy"), a public utility with electric and natural gas operations, and its direct wholly owned nonregulated subsidiary is Midwest Capital Group, Inc.

The preparation of the unaudited Consolidated Financial Statements in 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 MidAmerican Funding's Annual Report on Form 10-K for the year ended December 31, 2022, describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in MidAmerican Funding's accounting policies or its assumptions regarding significant accounting estimates during the three-month period ended March 31, 2023.

(2) Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

Cash equivalents consist of funds invested in money market mutual funds, U.S. 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 consist substantially of funds restricted for wildlife preservation. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as presented on 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,
	2023		2022

Cash and cash equivalents	$	58	$	261
Restricted cash and cash equivalents in other current assets	6		10
Total cash and cash equivalents and restricted cash and cash equivalents	$	64	$	271

(3) Property, Plant and Equipment, Net

Refer to Note 3 of MidAmerican Energy's Notes to Financial Statements.

(4) Income Taxes

A reconciliation of the federal statutory income tax rate to MidAmerican Funding's effective income tax rate applicable to income before income tax expense (benefit) is as follows:


	Three-Month Periods
	Ended March 31,
		2023		2022

Federal statutory income tax rate		21	%	21	%
Income tax credits		(430)		(618)
State income tax, net of federal income tax impacts		(13)		(24)
Effects of ratemaking		(6)		(9)
Other, net		(2)		—
Effective income tax rate		(430)	%	(630)	%

Income tax credits relate primarily to production tax credits ("PTC") from MidAmerican Energy's wind- and solar-powered generating facilities. Federal renewable electricity PTCs are earned as energy from qualifying wind- and solar-powered generating facilities is produced and sold and are based on a per-kilowatt hour rate pursuant to the applicable federal income tax law. MidAmerican Funding recognizes its renewable electricity PTCs throughout the year based on when the credits are earned and excludes them from the annual effective tax rate that is the basis for the interim recognition of other income tax expense. Wind- and solar-powered generating facilities are eligible for the credits for 10 years from the date the qualifying generating facilities are placed in-service. PTCs recognized for the three-month periods ended March 31, 2023 and 2022, totaled $202 million and $203 million, respectively.

Berkshire Hathaway includes BHE and subsidiaries in its U.S. federal and Iowa state income tax returns. Consistent with established regulatory practice, MidAmerican Funding's and MidAmerican Energy's provisions for income tax have been computed on a stand-alone basis, and substantially all of their currently payable or receivable income tax is remitted to or received from BHE. MidAmerican Funding made no cash payments for income tax to BHE for each of the three-month periods ended March 31, 2023 and 2022.

(5) Employee Benefit Plans

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

(6) Asset Retirement Obligations

Refer to Note 6 of MidAmerican Energy's Notes to Financial Statements.

(7) Fair Value Measurements

Refer to Note 7 of MidAmerican Energy's Notes to Financial Statements. MidAmerican Funding's long-term debt is carried at cost on the Consolidated Financial Statements. The fair value ~~category.~~

Operating Revenue

Electric Fuel and Other Energy - Related Purchases

Total

(millions)

Three Months Ended September 30, 2017

Total gains (losses) included in earnings

$
1

$
(12
)

$
(11
)
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

1

—

1

Three Months Ended September 30, 2016

Total gains (losses) included in earnings

$
—

$
(7
)

$
(7
)
Nine Months Ended September 30, 2017

Total gains (losses) included in earnings

$
1

$
(37
)

$
(36
)
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

1

—

1

Nine Months Ended September 30, 2016

Total gains (losses) included in earnings

$
—

$
(23
)

$
(23
)

~~Virginia Power~~

of MidAmerican Funding'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 MidAmerican Funding's variable-rate long-term debt approximates fair value because of the frequent repricing of these instruments at market rates. The following table presents ~~Virginia Power's quantitative information about Level 3~~the carrying value and estimated fair value ~~measurements at September 30, 2017.~~of MidAmerican Funding's long-term debt (in millions):


	As of March 31, 2023				As of December 31, 2022
	Carrying Value		Fair Value		Carrying Value		Fair Value

Long-term debt	$	7,962	$	7,386	$	7,969	$	7,219

(8) Commitments and Contingencies

MidAmerican Funding is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. MidAmerican Funding does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.

Refer to Note 8 of MidAmerican Energy's Notes to Financial Statements.

(9) Revenue from Contracts with Customers

Refer to Note 9 of MidAmerican Energy's Notes to Financial Statements.

(10) Member's Equity

In January 2023, MidAmerican Funding paid a $100 million cash distribution to its parent company, BHE.

(11) Segment Information

MidAmerican Funding has identified two reportable segments: regulated electric and regulated natural gas. The ~~range~~regulated electric segment derives most of its revenue from regulated retail sales of electricity to residential, commercial, and ~~weighted average~~industrial customers and from wholesale sales. The regulated natural gas segment derives most of its revenue from regulated retail sales of natural gas to residential, commercial, and industrial customers and also obtains revenue by transporting natural gas owned by others through its distribution system. Pricing for regulated electric and natural gas sales are ~~presented~~established separately by regulatory agencies; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and evaluating performance. Common operating costs, interest income, interest expense and income tax expense are allocated to each segment based on certain factors, which primarily relate to the nature of the cost. "Other" in ~~dollars for market price inputs~~the tables below consists of the financial results and ~~percentages for price volatility.~~

assets of nonregulated operations, MHC and MidAmerican Funding.

Fair Value
(millions)

Valuation Techniques

Unobservable Input

Range

Weighted
Average⁽¹⁾

Assets

Physical and financial forwards and
futures:

Natural gas⁽²⁾

$
91

Discounted cash flow

Market price (per Dth)
⁽³⁾

(2) - 7

(1
)
FTRs

19

Discounted cash flow

Market price (per MWh)
⁽³⁾

(1) - 7

1

Physical options:

Natural gas

1

Option model

Market price (per Dth)
⁽³⁾

2 - 7

4

Price volatility
⁽⁴⁾

24% - 46%

32
%
Electricity

42

Option model

Market price (per MWh)
⁽³⁾

21 - 50

34

Price volatility
⁽⁴⁾

0% - 78%

28
%
Total assets

$
153

Liabilities

Financial forwards:

FTRs

$
1

Discounted cash flow

Market price (per MWh)
⁽³⁾

(5) - 7

1

Total liabilities

$
1

The following tables provide information on a reportable segment basis (in millions):


	Three-Month Periods
	Ended March 31,
		2023		2022
Operating revenue:
Regulated electric		$	591	$	608
Regulated natural gas		326		396
Other		3		1
Total operating revenue		$	920	$	1,005

Operating income:
Regulated electric		$	50	$	51
Regulated natural gas		38		49

Total operating income		88		100
Interest expense		(84)		(82)
Allowance for borrowed funds		4		4
Allowance for equity funds		11		15
Other, net		28		(4)
Total income before income tax expense (benefit)		$	47	$	33


	As of
	March 31, 2023		December 31, 2022
Assets(1):
Regulated electric	$	23,282	$	23,283
Regulated natural gas	1,795		1,963
Other	10		8
Total assets	$	25,087	$	25,254

~~(1)~~	~~Averages weighted~~
(1)			Assets by ~~volume.~~ reportable segment reflect the assignment of goodwill to applicable reporting units.

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 MidAmerican Funding and its subsidiaries and MidAmerican Energy during the periods included herein. Information in Management's Discussion and Analysis related to MidAmerican Energy, whether or not segregated, also relates to MidAmerican Funding. Information related to other subsidiaries of MidAmerican Funding pertains only to the discussion of the financial condition and results of operations of MidAmerican Funding. Where necessary, discussions have been segregated under the heading "MidAmerican Funding" to allow the reader to identify information applicable only to MidAmerican Funding. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should be read in conjunction with MidAmerican Funding's historical unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements and MidAmerican Energy's historical unaudited Financial Statements and Notes to Financial Statements in Part I, Item 1 of this Form 10-Q. MidAmerican Funding's and MidAmerican Energy's actual results in the future could differ significantly from the historical results.

Results of Operations for the First Quarter of 2023 and 2022

Overview

MidAmerican Energy -

MidAmerican Energy's net income for the first quarter of 2023 was $242 million, a decrease of $2 million, or 1%, compared to 2022, primarily due to higher operations and maintenance expense, lower natural gas utility margin, lower electric utility margin, lower allowance for equity funds, lower income tax benefit, higher property and other taxes and higher interest expense, offset by favorable other, net and lower depreciation and amortization expense. Electric retail customer volumes increased 1% primarily due to higher customer usage for certain industrial customers, partially offset by the unfavorable impact of weather. Energy generated decreased 9%, due to lower wind-powered and coal-fueled generation, and energy purchased increased 17%. Wholesale electricity sales volumes decreased 18% due to unfavorable market conditions. Natural gas retail customer volumes decreased 10% due to the unfavorable impact of weather.

MidAmerican Funding -

MidAmerican Funding's net income for the first quarter of 2023 was $249 million, an increase of $8 million, or 3%, compared to 2022. The variance in net income was primarily due to a one-time gain on the sale of an investment of $10 million, partially offset by the changes in MidAmerican Energy's earnings discussed above.

Non-GAAP Financial Measure

Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as, electric utility margin and natural gas utility margin, to help evaluate results of operations. Electric utility margin is calculated as regulated electric operating revenue less cost of fuel and energy, which are captions presented on the Statements of Operations. Natural gas utility margin is calculated as regulated natural gas operating revenue less regulated cost of natural gas purchased for resale, which are included in regulated natural gas and other and cost of natural gas purchased for resale and other, respectively, on the Statements of Operations.

MidAmerican Energy's cost of fuel and energy and cost of natural gas purchased for resale are generally recovered from its retail customers through regulatory recovery mechanisms, and as a result, changes in MidAmerican Energy's expense included in regulatory recovery mechanisms result in comparable changes to revenue. As such, management believes electric utility margin and natural gas utility margin more appropriately and concisely explain profitability rather than a discussion of revenue and cost of sales separately. Management believes the presentation of electric utility margin and natural gas utility margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.

Electric utility margin and natural gas utility margin are not measures calculated in accordance with GAAP and should be viewed as a supplement to, and not a substitute for, operating income, which is the most comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to MidAmerican Energy's operating income (in millions):


	First Quarter
	2023		2022		Change
Electric utility margin:
Operating revenue	$	591	$	608	$	(17)	(3)	%
Cost of fuel and energy	115		125		(10)		(8)
Electric utility margin	476		483		(7)		(1)	%

Natural gas utility margin:
Operating revenue	326		396		(70)		(18)	%
Natural gas purchased for resale	236		298		(62)		(21)
Natural gas utility margin	90		98		(8)		(8)	%

Utility margin	566		581		(15)		(3)	%

Other operating revenue	3		1		2		*

Operations and maintenance	205		192		13		7
Depreciation and amortization	234		250		(16)		(6)
Property and other taxes	42		40		2		5

Operating income	$	88	$	100	$	(12)	(12)	%

* Not meaningful.

Electric Utility Margin

A comparison of key operating results related to electric utility margin is as follows:


	First Quarter
	2023		2022		Change
Utility margin (in millions):
Operating revenue	$	591	$	608	$	(17)	(3)	%
Cost of fuel and energy	115		125		(10)		(8)
Utility margin	$	476	$	483	$	(7)	(1)	%

Sales (GWhs):
Residential	1,793		1,853		(60)		(3)	%
Commercial	1,018		1,013		5		—
Industrial	4,102		3,979		123		3
Other	409		403		6		1
Total retail	7,322		7,248		74		1
Wholesale	4,352		5,325		(973)		(18)
Total sales	11,674		12,573		(899)		(7)	%

Average number of retail customers (in thousands)	818		810		8		1	%

Average revenue per MWh:
Retail	$	67.02	$	65.10	$	1.92	3	%
Wholesale	$	17.56	$	20.65	$	(3.09)	(15)	%

Heating degree days	2,992		3,315		(323)		(10)	%


Sources of energy (GWhs)(1):
Wind and other(2)	7,377		8,290		(913)		(11)	%
Coal	2,116		2,359		(243)		(10)
Nuclear	927		920		7		1
Natural gas	344		234		110		47
Total energy generated	10,764		11,803		(1,039)		(9)
Energy purchased	1,123		962		161		17
Total	11,887		12,765		(878)		(7)	%

Average cost of energy per MWh:
Energy generated(3)	$	6.09	$	5.56	$	0.53	10	%
Energy purchased	$	43.72	$	62.04	$	(18.32)	(30)	%

(1) GWh amounts are net of energy used by the related generating facilities.

(2) All or some of the renewable energy attributes associated with generation from these sources may be: (a) used in future years to comply with RPS or other regulatory requirements or (b) sold to third parties in the form of renewable energy credits or other environmental commodities.

(3) The average cost per MWh of energy generated includes only the cost of fuel associated with the generating facilities.

Natural Gas Utility Margin

A comparison of key operating results related to natural gas utility margin is as follows:


	First Quarter
	2023		2022		Change
Utility margin (in millions):
Operating revenue	$	326	$	396	$	(70)	(18)	%
Natural gas purchased for resale	236		298		(62)		(21)
Utility margin	$	90	$	98	$	(8)	(8)	%

Throughput (000's Dths):
Residential	24,393		27,099		(2,706)		(10)	%
Commercial	11,352		12,460		(1,108)		(9)
Industrial	1,483		1,844		(361)		(20)
Other	34		35		(1)		(3)
Total retail sales	37,262		41,438		(4,176)		(10)
Wholesale sales	10,407		12,232		(1,825)		(15)
Total sales	47,669		53,670		(6,001)		(11)
Natural gas transportation service	29,585		31,313		(1,728)		(6)
Total throughput	77,254		84,983		(7,729)		(9)	%

Average number of retail customers (in thousands)	793		785		8		1	%

Average revenue per retail Dth sold	$	7.63	$	7.84	$	(0.21)	(3)	%

Heating degree days	3,132		3,485		(353)		(10)	%

Average cost of natural gas per retail Dth sold	$	5.58	$	5.80	$	(0.22)	(4)	%

Combined retail and wholesale average cost of natural gas per Dth sold	$	4.96	$	5.55	$	(0.59)	(11)	%

Quarter Ended March 31, 2023 Compared to Quarter Ended March 31, 2022

MidAmerican Energy -

Electric utility margin decreased $7 million, or (1)%, for the first quarter of 2023 compared to 2022, primarily due to:

•a $23 million decrease in wholesale utility margin due to lower volumes of 18.3% and lower margins per unit of $7 million, reflecting lower market prices; partially offset by

•a $17 million increase in retail utility margin primarily due to $14 million, net of energy costs, from higher recoveries through bill riders (offset in operations and maintenance expense and income tax benefit); and $7 million from higher customer usage; partially offset by $5 million from the unfavorable impact of weather. Retail customer volumes increased 1.0%.

Natural gas utility margin decreased $8 million, or 8%, for the first quarter of 2023 compared to 2022 primarily due to:

•a $5 million decrease from lower recoveries through a capital tracker mechanism;

•a $5 million decrease due to the unfavorable impact of weather; partially offset by

•a $3 million increase due to price impacts from changes in sales mix.

Operations and maintenance increased $13 million, or 7%, for the first quarter of 2023 compared to 2022 primarily due to higher technology and other administrative costs of $6 million, higher other power and steam power generation costs of $5 million, higher property insurance costs of $3 million and higher benefit costs of $2 million, partially offset by lower nuclear power generation costs of $4 million.

Depreciation and amortization decreased $16 million, or 6%, for the first quarter of 2023 compared to 2022 primarily due to $22 million from lower Iowa revenue sharing accruals, and $16 million from a regulatory mechanism that provides customers the retail energy benefits of certain wind-powered generation projects, partially offset by $19 million from wind-powered generating facilities and other plant placed in-service and $3 million from lower depreciation expense deferrals in 2023.

Property and other taxes increased $2 million, or 5%, for the first quarter of 2023 compared to 2022 primarily due to $1 million from higher wind turbine property taxes and $1 million from higher replacement taxes.

Interest expense increased $2 million, or 3%, for the first quarter of 2023 compared to 2022 due to higher interest rates on variable rate long-term debt.

Allowance for equity funds decreased $4 million, or 27%, for the first quarter of 2023 compared to 2022 due to lower construction work-in-progress balances related to wind- and solar-powered generation.

Other, net increased $19 million, or 633%, for the first quarter of 2023 compared to 2022 primarily due to favorable investment earnings, largely attributable to higher cash surrender values of corporate-owned life insurance policies, and lower non-service costs of employee benefit plans.

Income tax benefit decreased $3 million, or 1%, for the first quarter of 2023 compared to 2022 primarily due to lower PTCs and state income tax impacts. PTCs for the first quarter of 2023 and 2022 totaled $202 million and $203 million, respectively.

MidAmerican Funding -

Income tax benefit decreased $6 million, or 3%, for the first quarter of 2023 compared to 2022 principally due to higher pretax income from a one-time gain on the sale of an investment and the changes in MidAmerican Energy's income tax benefit discussed above.

Liquidity and Capital Resources

As of March 31, 2023, the total net liquidity for MidAmerican Energy and MidAmerican Funding was as follows (in millions):

~~(2)~~	~~Includes basis.~~
MidAmerican Energy:
Cash and cash equivalents		$	57

Credit facilities, maturing 2023 and 2025		1,505
Less:

Tax-exempt bond support		(363)
Net credit facilities		1,142

MidAmerican Energy total net liquidity		$	1,199

MidAmerican Funding:
MidAmerican Energy total net liquidity		$	1,199
Cash and cash equivalents		1
MHC, Inc. credit facility, maturing 2023		4
MidAmerican Funding total net liquidity		$	1,204

Operating Activities

MidAmerican Energy's net cash flows from operating activities for the three-month periods ended March 31, 2023 and 2022, were $288 million and $360 million, respectively. MidAmerican Funding's net cash flows from operating activities for the three-month periods ended March 31, 2023 and 2022, were $272 million and $353 million, respectively. Cash flows from operating activities reflect higher payments to vendors, higher derivative collateral posted, higher property tax payments and lower utility margins for MidAmerican Energy's regulated electric and natural gas businesses.

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

Investing Activities

MidAmerican Energy's net cash flows from investing activities for the three-month periods ended March 31, 2023 and 2022, were $(384) million and $(461) million, respectively. MidAmerican Funding's net cash flows from investing activities for the three-month periods ended March 31, 2023 and 2022, were $(371) million and $(461) million, respectively. Net cash flows from investing activities consist almost entirely of capital expenditures. Refer to "Future Uses of Cash" for further discussion of capital expenditures. Purchases and proceeds related to marketable securities substantially consist of activity within the Quad Cities Generating Station nuclear decommissioning trust and other trust investments.

Financing Activities

MidAmerican Energy's net cash flows from financing activities for the three-month periods ended March 31, 2023 and 2022 were $(108) million and $— million, respectively. MidAmerican Funding's net cash flows from financing activities for the three-month periods ended March 31, 2023 and 2022, were $(108) million and $7 million, respectively. In January 2023, MidAmerican Funding made a $100 million distribution to its sole member, BHE. MidAmerican Funding paid $— million and received $8 million in 2023 and 2022, respectively, through its note payable with BHE.

Debt Authorizations and Related Matters

Short-term Debt

MidAmerican Energy has authority from the FERC to issue, through April 2, 2024, commercial paper and bank notes aggregating $1.5 billion. MidAmerican Energy has a $1.5 billion unsecured credit facility expiring in June 2025. The credit facility, which supports MidAmerican Energy's commercial paper program and its variable-rate tax-exempt bond obligations and provides for the issuance of letters of credit, has a variable interest rate based on the Secured Overnight Financing Rate, plus a spread that varies based on MidAmerican Energy's credit ratings for senior unsecured long-term debt securities. Additionally, MidAmerican Energy has a $5 million unsecured credit facility for general corporate purposes.

Long-term Debt and Preferred Stock

MidAmerican Energy currently has an effective shelf registration statement with the SEC to issue up to $3.25 billion of long-term debt securities and preferred stock through March 10, 2026. MidAmerican Energy has authorization from the FERC to issue, through June 30, 2023, long-term debt securities up to an aggregate of $2.0 billion and preferred stock up to an aggregate of $500 million. MidAmerican Energy has authorization from the ICC through May 25, 2025, to issue long-term debt securities up to an aggregate of $2.2 billion and preferred stock up to an aggregate of $500 million; through October 15, 2024, to issue $750 million of long-term debt securities for the purpose of refinancing $250 million of its 3.70% Senior notes due September 2023 and $500 million of its 2.40% Senior notes due October 2024; and through January 1, 2025, to issue $105 million of long-term debt securities for the purpose of refinancing three of its variable-rate tax-exempt bond series, including $57 million due in May 2023, $35 million due in October 2024 and $13 million due in January 2025.

Future Uses of Cash

MidAmerican Energy and MidAmerican Funding have 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 and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which MidAmerican Energy and MidAmerican Funding have access to external financing depends on a variety of factors, including their credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.

100

Capital Expenditures

MidAmerican Energy 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 customer rates; changes in environmental and other rules and regulations; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital.

MidAmerican Energy'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
	2022		2023		2023

Wind generation	$	133	$	88	$	1,222
Electric distribution	54		73		296
Electric transmission	21		33		187
Solar generation	44		9		10
Other	207		179		609
Total	$	459	$	382	$	2,324

MidAmerican Energy's capital expenditures provided above consist of the following:

•Wind generation includes the construction, acquisition, repowering and operation of wind-powered generating facilities in Iowa.

◦Construction of wind-powered generating facilities totaling $75 million and $3 million for the three-month periods ended March 31, 2023 and 2022, respectively. The timing and amount of forecast wind generation capital expenditures may be substantially impacted by the ultimate outcome of MidAmerican Energy's Wind PRIME filing. Planned spending for the construction of additional wind-powered generating facilities totals $1,025 million for the remainder of 2023.

◦Repowering of wind-powered generating facilities totaling $5 million and $120 million for the three-month periods ended March 31, 2023 and 2022, respectively. Planned spending for the repowering of wind-powered generating facilities totals $16 million for the remainder of 2023. 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.

•Electric distribution includes expenditures for new facilities to meet retail demand growth and for replacement of existing facilities to maintain system reliability.

•Electric transmission includes expenditures to meet retail demand growth, upgrades to accommodate third-party generator requirements and replacement of existing facilities to maintain system reliability.

•Solar generation includes the construction and operation of solar-powered generating facilities, primarily consisting of 141 MWs of small- and utility-scale solar generation, all of which were placed in-service in 2022. For the three-month periods ended March 31, 2023 and 2022 solar generation spend totaled $9 million and $44 million, respectively. Planned spending totals $1 million for the remainder of 2023.

•Other includes primarily routine projects for other generation, natural gas distribution, technology, facilities and other operational needs to serve existing and expected demand.

Material Cash Requirements

As of March 31, 2023, there have been no material changes in MidAmerican Energy's and MidAmerican Funding's cash requirements from the information provided in Item 7 of their Annual Report on Form 10-K for the year ended December 31, 2022.

101

Regulatory Matters

MidAmerican Energy is subject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for discussion regarding MidAmerican Energy's current regulatory matters.

Environmental Laws and Regulations

MidAmerican Energy is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions performance standards, water quality, coal ash disposal and other environmental matters that have the potential to impact MidAmerican Energy'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 and local agencies. MidAmerican Energy believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and MidAmerican Energy is unable to predict the impact of the changing laws and regulations on its operations and financial results.

Refer to "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information regarding environmental laws and regulations.

Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the future. Amounts recognized on the 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 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 MidAmerican Energy's and MidAmerican Funding's critical accounting estimates, see Item 7 of their Annual Report on Form 10-K for the year ended December 31, 2022. There have been no significant changes in MidAmerican Energy's and MidAmerican Funding's assumptions regarding critical accounting estimates since December 31, 2022.

102

Nevada Power Company and its subsidiaries

Consolidated Financial Section

103

PART I

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Nevada Power Company

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Nevada Power Company and subsidiaries ("Nevada Power") as of March 31, 2023, the related consolidated statements of operations, changes in shareholder's equity, and cash flows for the three-month periods ended March 31, 2023 and 2022, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of Nevada Power as of December 31, 2022, and the related consolidated statements of operations, changes in shareholder's equity, and cash flows for the year then ended (not presented herein); and in our report dated February 24, 2023, 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, 2022, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

This interim financial information is the responsibility of Nevada Power's management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to Nevada Power in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

/s/ Deloitte & Touche LLP

Las Vegas, Nevada

May 5, 2023

104

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions, except share data)


	As of
	March 31,		December 31,
	2023		2022
ASSETS
Current assets:
Cash and cash equivalents	$	23	$	43
Trade receivables, net	301		388
Note receivable from affiliate	—		100
Inventories	106		93

Regulatory assets	983		666


Other current assets	83		89
Total current assets	1,496		1,379

Property, plant and equipment, net	7,649		7,406

Regulatory assets	655		628
Other assets	390		388

Total assets	$	10,190	$	9,801

LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	334	$	422
Accrued interest	51		40
Accrued property, income and other taxes	35		32
Short-term debt	33		—
Current portion of long-term debt	300		—
Regulatory liabilities	45		45
Customer deposits	52		51

Derivative contracts	90		51
Other current liabilities	52		49
Total current liabilities	992		690

Long-term debt	2,895		3,195
Finance lease obligations	290		295
Regulatory liabilities	1,059		1,093
Deferred income taxes	878		875
Other long-term liabilities	318		299
Total liabilities	6,432		6,447

Commitments and contingencies (Note 9)

Shareholder's equity:
Common stock - $1.00 stated value; 1,000 shares authorized, issued and outstanding	—		—
Additional paid-in capital	2,733		2,333
Retained earnings	1,026		1,022
Accumulated other comprehensive loss, net	(1)		(1)
Total shareholder's equity	3,758		3,354

Total liabilities and shareholder's equity	$	10,190	$	9,801

The accompanying notes are an integral part of the consolidated financial statements.

105

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)


	Three-Month Periods
	Ended March 31,
	2023		2022

Operating revenue	$	599	$	415

Operating expenses:
Cost of fuel and energy	384		212
Operations and maintenance	73		65
Depreciation and amortization	106		103
Property and other taxes	14		13
Total operating expenses	577		393

Operating income	22		22

Other income (expense):
Interest expense	(49)		(38)
Capitalized interest	2		1
Allowance for equity funds	4		3
Interest and dividend income	22		9
Other, net	4		1
Total other income (expense)	(17)		(24)

Income (loss) before income tax expense (benefit)	5		(2)
Income tax expense (benefit)	1		—
Net income (loss)	$	4	$	(2)

The accompanying notes are an integral part of these consolidated financial statements.

106

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited)

(Amounts in millions, except shares)


								Accumulated
				Additional				Other		Total
	Common Stock			Paid-in		Retained		Comprehensive		Shareholder's
	Shares	Amount		Capital		Earnings		Loss, Net		Equity







Balance, December 31, 2021	1,000	$	—	$	2,308	$	724	$	(2)	$	3,030
Net loss	—	—		—		(2)		—		(2)


Balance, March 31, 2022	1,000	$	—	$	2,308	$	722	$	(2)	$	3,028








Balance, December 31, 2022	1,000	$	—	$	2,333	$	1,022	$	(1)	$	3,354
Net income	—	—		—		4		—		4

Contributions	—	—		400		—		—		400

Balance, March 31, 2023	1,000	$	—	$	2,733	$	1,026	$	(1)	$	3,758

The accompanying notes are an integral part of these consolidated financial statements.

107

NEVADA POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)


	Three-Month Periods
	Ended March 31,
	2023		2022
Cash flows from operating activities:
Net income (loss)	$	4	$	(2)
Adjustments to reconcile net income (loss) to net cash flows from operating activities:


Depreciation and amortization	106		103
Allowance for equity funds	(4)		(3)
Changes in regulatory assets and liabilities	(9)		(8)
Deferred income taxes and amortization of investment tax credits	(10)		5
Deferred energy	(370)		(51)
Amortization of deferred energy	52		13
Other, net	1		4
Changes in other operating assets and liabilities:
Trade receivables and other assets	74		33
Inventories	(13)		3
Accrued property, income and other taxes	1		(15)
Accounts payable and other liabilities	(44)		3
Net cash flows from operating activities	(212)		85

Cash flows from investing activities:
Capital expenditures	(333)		(189)
Proceeds from repayment of affiliate note receivable	100		—



Net cash flows from investing activities	(233)		(189)

Cash flows from financing activities:
Net (repayments of) proceeds from long-term debt	(1)		200

Net (repayments of) proceeds from short-term debt	33		(76)

Contributions from parent	400		—

Other, net	(5)		(4)
Net cash flows from financing activities	427		120

Net change in cash and cash equivalents and restricted cash and cash equivalents	(18)		16
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	60		45
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	42	$	61

The accompanying notes are an integral part of these consolidated financial statements.

108

NEVADA POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) General

Nevada Power Company, together with its subsidiaries ("Nevada Power"), is a wholly owned subsidiary of NV Energy, Inc. ("NV Energy"), a holding company that also owns Sierra Pacific Power Company and its subsidiaries ("Sierra Pacific") and certain other subsidiaries. Nevada Power is a U.S. regulated electric utility company serving retail customers, including residential, commercial and industrial customers, primarily in the Las Vegas, North Las Vegas, Henderson and adjoining areas. NV Energy is an indirect wholly owned subsidiary of Berkshire Hathaway Energy Company ("BHE"). BHE is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and 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 disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of March 31, 2023, and for the three-month periods ended March 31, 2023 and 2022. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three-month periods ended March 31, 2023 and 2022. The results of operations for the three-month period ended March 31, 2023, are not necessarily indicative of the results to be expected for the full year.

The preparation of the unaudited Consolidated Financial Statements in 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 Nevada Power's Annual Report on Form 10-K for the year ended December 31, 2022, describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in Nevada Power's accounting policies or its assumptions regarding significant accounting estimates during the three-month period ended March 31, 2023.

(2)Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

Cash equivalents consist of funds invested in money market mutual funds, U.S. 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 consist of funds restricted by the Public Utilities Commission of Nevada ("PUCN") for a certain renewable energy contract. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as presented on 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,
	2023		2022

Cash and cash equivalents	$	23	$	43
Restricted cash and cash equivalents included in other current assets	19		17
Total cash and cash equivalents and restricted cash and cash equivalents	$	42	$	60

109

(3) Property, Plant and Equipment, Net

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


		As of
	Depreciable Life	March 31,		December 31,
		2023		2022
Utility plant:
Generation	30 - 55 years	$	3,977	$	3,977
Transmission	45 - 70 years	1,569		1,562
Distribution	20 - 65 years	4,189		4,134
General and intangible plant	5 - 65 years	887		871
Utility plant		10,622		10,544
Accumulated depreciation and amortization		(3,677)		(3,624)
Utility plant, net		6,945		6,920
Non-regulated, net of accumulated depreciation and amortization	45 years	1		1
		6,946		6,921
Construction work-in-progress		703		485
Property, plant and equipment, net		$	7,649	$	7,406

(4) Recent Financing Transactions

Long-Term Debt

In March 2023, Nevada Power repurchased and entered into a re-offering of the following series of fixed-rate tax-exempt bonds: $40 million of its Coconino County, Arizona Pollution Control Corporation Revenue Bonds, Series 2017A, due 2032; $13 million of its Coconino County, Arizona Pollution Control Corporation Revenue Bonds, Series 2017B, due 2039; and $40 million of its Clark County, Nevada Revenue Bonds, Series 2017, due 2036. The Coconino Series 2017A bond was offered at a fixed rate of 4.125% and the Coconino Series 2017B and Clark Series 2017 bonds were offered at a fixed rate of 3.750%.

(5) Income Taxes

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

~~(3)~~	~~Represents market prices beyond defined terms for Levels 1 and 2.~~
		Three-Month Period
		Ended March 31,
		2023

Federal statutory income tax rate		21	%
Effects of ratemaking		(9)

Income tax credits		(2)

Other		10
Effective income tax rate		20	%

~~(4)~~

~~Represents volatilities unrepresented in published markets~~.

~~Sensitivity~~

Effects of ratemaking is primarily attributable to the recognition of excess deferred income taxes related to the 2017 Tax Cuts and Jobs Act pursuant to an order issued by the PUCN effective January 1, 2021.

Berkshire Hathaway includes BHE and its subsidiaries in its U.S. federal income tax return. Consistent with established regulatory practice, Nevada Power's provision for federal income tax has been computed on a separate return basis, and substantially all of its currently payable or receivable income tax is remitted to or received from BHE.For the three-month periods ended March 31, 2023 and 2022, Nevada Power made no cash payments for federal income tax to BHE.

110

(6) Employee Benefit Plans

Nevada Power is a participant in benefit plans sponsored by NV Energy. The NV Energy Retirement Plan includes a qualified pension plan ("Qualified Pension Plan") and a supplemental executive retirement plan and a restoration plan (collectively, "Non‑Qualified Pension Plans") that provide pension benefits for eligible employees. The NV Energy Comprehensive Welfare Benefit and Cafeteria Plan provides certain postretirement health care and life insurance benefits for eligible retirees ("Other Postretirement Plans") on behalf of Nevada Power. Amounts attributable to Nevada Power were allocated from NV Energy based upon the current, or in the case of retirees, previous, employment location. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are included in accumulated other comprehensive loss, net.

Amounts receivable from (payable to) NV Energy are included on the Consolidated Balance Sheets and consist of the following (in millions):


	As of
	March 31,		December 31,
	2023		2022
Qualified Pension Plan:
Other non-current assets	$	26	$	27



Non-Qualified Pension Plans:

Other current liabilities	(1)		(1)
Other long-term liabilities	(6)		(6)

Other Postretirement Plans:
Other non-current assets	7		7

(7)Risk Management and Hedging Activities

Nevada Power is exposed to the impact of market fluctuations in commodity prices and interest rates. Nevada Power is principally exposed to electricity and natural gas market fluctuations primarily through Nevada Power's obligation to serve retail customer load in its regulated service territory. Nevada Power's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that is purchased and sold. Commodity prices are subject to wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. The actual cost of fuel and purchased power is recoverable through the deferred energy mechanism. Interest rate risk exists on variable-rate debt and future debt issuances. Nevada Power does not engage in proprietary trading activities.

Nevada Power has established a risk management process that is designed to identify, assess, manage and report on each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, Nevada Power uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. Nevada Power manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. Additionally, Nevada Power may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate Nevada Power's exposure to interest rate risk. Nevada Power does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices.

There have been no significant changes in Nevada Power's accounting policies related to derivatives. Refer to Note 8 for additional information on derivative contracts.

111

The following table, which excludes contracts that have been designated as normal under the normal purchases and normal sales exception afforded by GAAP, summarizes the fair value ~~measurements~~of Nevada Power's derivative contracts, on a gross basis, and reconciles those amounts presented on a net basis on the Consolidated Balance Sheets (in millions):


			Derivative
	Other		Contracts -		Other
	Current		Current		Long-term
	Assets		Liabilities		Liabilities		Total

As of March, 31 2023
Not designated as hedging contracts(1):
Commodity assets	$	4	$	—	$	—	$	4
Commodity liabilities	—		(90)		(30)		(120)





Total derivatives - net basis	$	4	$	(90)	$	(30)	$	(116)

As of December 31, 2022
Not designated as hedging contracts(1):
Commodity assets	$	23	$	—	$	—	$	23
Commodity liabilities	—		(51)		(24)		(75)




Total derivatives - net basis	$	23	$	(51)	$	(24)	$	(52)

(1)Nevada Power's commodity derivatives not designated as hedging contracts are included in regulated rates. As of March 31, 2023 a regulatory asset of $116 million was recorded related to ~~changes in~~ the ~~significant unobservable inputs is as follows:~~

net derivative liability of $116 million. As of December 31, 2022 a regulatory asset of $52 million was recorded related to the net derivative liability of $52 million.

~~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)~~

Derivative Contract Volumes

The following table ~~presents Virginia Power’s~~summarizes the net notional amounts of outstanding commodity derivative contracts with fixed price terms that comprise the mark-to-market values as of (in millions):


	Unit of	March 31,	December 31,
	Measure	2023	2022

Electricity purchases	Megawatt hours	2	2
Natural gas purchases	Decatherms	155	109

Credit Risk

Nevada Power is exposed to counterparty credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent Nevada Power's counterparties have similar economic, industry or other characteristics and due to direct and indirect relationships among the counterparties. Before entering into a transaction, Nevada Power analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, Nevada Power enters into netting and collateral arrangements that may include margining and cross-product netting agreements and obtain third-party guarantees, letters of credit and cash deposits. If required, Nevada Power exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.

112

Collateral and Contingent Features

In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other security if credit exposures on a net basis exceed specified rating-dependent threshold levels "credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance" if there is a material adverse change in Nevada Power's creditworthiness. These rights can vary by contract and by counterparty. As of March 31, 2023, Nevada Power's credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt from the recognized credit rating agencies were investment grade.

The aggregate fair value of Nevada Power's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $10 million and $5 million as of March 31, 2023 and December 31, 2022, respectively, which represents the amount of collateral to be posted if all credit risk related contingent features for derivative contracts in liability positions had been triggered. Nevada Power's collateral requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation or other factors.

(8) Fair Value Measurements

The carrying value of Nevada Power'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. Nevada Power has various financial assets and liabilities that are measured at fair value on ~~a recurring basis~~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 ~~each hierarchy level,~~identical assets or liabilities that Nevada Power has the ability to access at the measurement date.

•Level 3 — Unobservable inputs reflect Nevada Power's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. Nevada Power develops these inputs based on the best information available, including ~~both current and noncurrent portions:~~

Level 1

Level 2

Level 3

Total

(millions)

September 30, 2017

Assets

Derivatives:

Commodity

$
—

$
15

$
153

$
168

Investments⁽¹⁾:

Equity securities:

U.S.

1,471

—

—

1,471

Fixed income:

Corporate debt instruments

—

234

—

234

Government securities

193

302

—

495

Total assets

$
1,664

$
551

$
153

$
2,368

Liabilities

Derivatives:

Commodity

$
—

$
5

$
1

$
6

Interest rate

—

55

—

55

Total liabilities

$
—

$
60

$
1

$
61

December 31, 2016

Assets

Derivatives:

Commodity

$
—

$
43

$
145

$
188

Interest rate

—

6

—

6

Investments⁽¹⁾:

Equity securities:

U.S.

1,302

—

—

1,302

Fixed income:

Corporate debt instruments

—

277

—

277

Government securities

136

291

—

427

Total assets

$
1,438

$
617

$
145

$
2,200

Liabilities

Derivatives:

Commodity

$
—

$
8

$
2

$
10

Interest rate

—

21

—

21

Total liabilities

$
—

$
29

$
2

$
31

its own data.

~~(1)~~

Includes investments held in the nuclear decommissioning trusts. Excludes $29 million and $26 million of assets at September 30, 2017 and December 31, 2016, 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.

113

The following table presents Nevada Power'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		Total
As of March 31, 2023:
Assets:
Commodity derivatives	$	—	$	—	$	4	$	4
Money market mutual funds	21		—		—		21
Investment funds	3		—		—		3
	$	24	$	—	$	4	$	28

Liabilities - commodity derivatives	$	—	$	—	$	(120)	$	(120)

As of December 31, 2022:
Assets:
Commodity derivatives	$	—	$	—	$	23	$	23
Money market mutual funds	34		—		—		34
Investment funds	3		—		—		3
	$	37	$	—	$	23	$	60

Liabilities - commodity derivatives	$	—	$	—	$	(75)	$	(75)

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 Nevada Power transacts. When quoted prices for identical contracts are not available, Nevada Power uses forward price curves. Forward price curves represent Nevada Power's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. Nevada Power bases its forward price curves upon internally developed models, with internal and external fundamental data inputs. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to markets that are not active. Given that limited market data exists for these contracts, Nevada Power uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The model incorporates a mid-market pricing convention (the mid‑point price between bid and ask prices) as a practical expedient for valuing its assets and liabilities measured and reported at fair value. The determination of the fair value for derivative contracts not only includes counterparty risk, but also the impact of Nevada Power's nonperformance risk on its liabilities, which as of March 31, 2023 and December 31, 2022, had an immaterial impact to the fair value of its derivative contracts. As such, Nevada Power considers its derivative contracts to be valued using Level 3 inputs.

Nevada Power's investments in money market mutual funds and investment funds are stated at fair value. When available, a readily observable quoted market price or net ~~change~~asset value of an identical security in ~~Virginia Power’s~~an active market is used to record the fair value.

114

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


	Three-Month Periods
	Ended March 31,
	2023		2022

Beginning balance	$	(52)	$	(113)
Changes in fair value recognized in regulatory assets	(65)		(56)

Settlements	1		1
Ending balance	$	(116)	$	(168)

Nevada Power's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value ~~category:~~

Three Months Ended September 30,

Nine Months Ended September 30,

2017

2016

2017

2016

(millions)

Beginning balance

$
152

$
125

$
143

$
93

Total realized and unrealized gains (losses):

Included in earnings

(12
)

(7
)

(37
)

(24
)
Included in regulatory assets/liabilities

11

(37
)

34

(5
)
Settlements

1

7

12

24

Ending balance

$
152

$
88

$
152

$
88

~~The gains and losses included in earnings in the~~of Nevada Power's long‑term debt is a Level 32 fair value ~~category were classified in electric fuel~~measurement and ~~other energy-related purchases in Virginia~~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 Nevada Power's ~~Consolidated Statements of Income for the three and nine months ended September 30, 2017 and 2016. There were no unrealized gains or losses included in earnings in the Level 3~~variable-rate long-term debt approximates fair value ~~category relating to assets/liabilities still held~~because of the frequent repricing of these instruments at ~~the reporting date for the three and nine months ended September 30, 2017 and 2016.~~

~~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)

September 30, 2017

Assets

Commodity

$
—

$
1

$
—

$
1

Foreign currency

—

25

—

25

Total assets

$
—

$
26

$
—

$
26

Liabilities

Commodity

$
—

$
6

$
—

$
6

Foreign currency

—

4

—

4

Total liabilities

$
—

$
10

$
—

$
10

December 31, 2016

Liabilities

Commodity

$
—

$
3

$
2

$
5

Foreign currency

—

6

—

6

Total liabilities

$
—

$
9

$
2

$
11

market rates. The following table presents the ~~net change in Dominion Energy Gas' assets and liabilities for derivatives measured at fair~~carrying value on a recurring basis and included in the Level 3 fair value category. There were no net changes in assets and liabilities for derivatives measured at fair value on a recurring basis and included in the Level 3 fair value category for the three months ended September 30, 2017 and 2016.

Nine Months Ended September 30,

2017

2016

(millions)

Beginning balance

$
(2
)

$
6

Total realized and unrealized gains (losses):

Included in other comprehensive income (loss)

(1
)

2

Transfers out of Level 3

3

(8
)
Ending balance

$
—

$
—

There were no gains or losses included in earnings in the Level 3 fair value category for the three and nine months ended September 30, 2017 and 2016. 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 nine months ended September 30, 2017 and 2016.

~~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 and cash equivalents, restricted cash (which is recorded in Dominion Energy’s other current assets), 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:~~

September 30, 2017

December 31, 2016

Carrying
Amount

Estimated
Fair
Value⁽¹⁾

Carrying
Amount

Estimated
Fair
Value⁽¹⁾

(millions)

Dominion Energy

Long-term debt, including securities due within one year⁽²⁾

$
28,317

$
30,639

$
26,587

$
28,273

Junior subordinated notes⁽³⁾

3,980

4,128

2,980

2,893

Remarketable subordinated notes⁽³⁾

1,377

1,421

2,373

2,418

Virginia Power

Long-term debt, including securities due within one year⁽³⁾

$
11,346

$
12,686

$
10,530

$
11,584

Dominion Energy Gas

Long-term debt⁽⁴⁾

$
3,564

$
3,705

$
3,528

$
3,603

value of Nevada Power's long‑term debt (in millions):

~~(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 issues with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value.


	As of March 31, 2023				As of December 31, 2022
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	3,195	$	3,241	$	3,195	$	3,114

~~(2)~~

Carrying amount includes amounts which represent the unamortized debt issuance costs, discount or premium, and foreign currency remeasurement adjustments. At September 30, 2017 and December 31, 2016, includes the valuation of certain fair value hedges associated with fixed rate debt of $(4) million and $(1) million, respectively.

~~(3)~~

~~Carrying amount includes amounts which represent the unamortized debt issuance costs, discount or premium.~~

~~(4)~~

~~Carrying amount includes amounts which represent the unamortized debt issuance costs, discount or premium, and foreign currency remeasurement adjustments.~~

~~Note 9. Derivatives~~(9) Commitments and ~~Hedge Accounting Activities~~

Contingencies

Environmental Laws and Regulations

Nevada Power is subject to federal, state and local 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 Nevada Power's current and future operations. Nevada Power believes it is in material compliance with all applicable laws and regulations.

Legal Matters

Nevada Power is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. Nevada Power does not believe that such normal and routine litigation will have a material impact on its consolidated financial results.

115

(10) Revenue from Contracts with Customers

The ~~Companies' accounting policies, objectives~~following table summarizes Nevada Power's revenue from contracts with customers ("Customer Revenue") by line of business, with further disaggregation of retail by customer class (in millions):


	Three-Month Periods
	Ended March 31,
	2023		2022
Customer Revenue:
Retail:
Residential	$	293	$	214
Commercial	136		96
Industrial	138		78
Other	6		1
Total fully bundled	573		389
Distribution only service	3		5
Total retail	576		394
Wholesale, transmission and other	18		16
Total Customer Revenue	594		410
Other revenue	5		5
Total operating revenue	$	599	$	415

116

Item 2. Management's Discussion and ~~strategies for using derivative instruments are discussed~~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 Nevada Power during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should be read in ~~Note 2~~conjunction with Nevada Power's historical unaudited Consolidated Financial Statements and Notes to ~~the~~ Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. Nevada Power's actual results in the ~~Companies'~~future could differ significantly from the historical results.

Results of Operations for the First Quarter of 2023 and 2022

Overview

Net income for the first quarter of 2023 was $4 million, an increase of $6 million, compared to 2022 primarily due to higher interest and dividend income, mainly from higher carrying charges on regulatory balances, higher utility margin and higher cash surrender value of corporate-owned life insurance policies, partially offset by higher interest expense, primarily due to higher long-term debt, higher operations and maintenance expenses, mainly due to higher customer service operations expenses and higher plant operations and maintenance expenses, and higher depreciation and amortization, mainly due to higher plant placed in-service. Utility margin increased primarily due to higher retail customer volumes, higher other retail revenue and higher regulatory-related revenue deferrals. Retail customer volumes, including distribution only service customers, increased 3.3% primarily due to an increase in the average number of customers and the favorable impact of weather. Energy generated increased 37% for the first quarter of 2023 compared to 2022 due to higher natural gas-fueled generation. Wholesale electricity sales volumes decreased 50% and purchased electricity volumes decreased 35%.

Non-GAAP Financial Measure

Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as, utility margin, to help evaluate results of operations. Utility margin is calculated as electric operating revenue less cost of fuel and energy, which are captions presented on the Consolidated Statements of Operations.

Nevada Power's cost of fuel and energy are directly recovered from its customers through regulatory recovery mechanisms and as a result, changes in Nevada Power's expenses result in comparable changes to revenue. As such, management believes utility margin more appropriately and concisely explains profitability rather than a discussion of revenue and cost of sales separately. Management believes the presentation of utility margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.

Utility margin is not a measure calculated in accordance with GAAP and should be viewed as a supplement to, and not a substitute for, operating income which is the most directly comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to operating income (in millions):


	First Quarter
	2023		2022		Change
Utility margin:
Operating revenue	$	599	$	415	$	184	44	%
Cost of fuel and energy	384		212		172		81
Utility margin	215		203		12		6
Operations and maintenance	73		65		8		12
Depreciation and amortization	106		103		3		3
Property and other taxes	14		13		1		8
Operating income	$	22	$	22	$	—	—	%

117

Utility Margin

A comparison of key operating results related to utility margin is as follows:


	First Quarter
	2023		2022		Change
Utility margin (in millions):
Operating revenue	$	599	$	415	$	184	44	%
Cost of fuel and energy	384		212		172		81
Utility margin	$	215	$	203	$	12	6	%

Sales (GWhs):
Residential	1,636		1,585		51		3	%
Commercial	997		998		(1)		—
Industrial	1,242		1,175		67		6
Other	43		46		(3)		(7)
Total fully bundled(1)	3,918		3,804		114		3
Distribution only service	598		569		29		5
Total retail	4,516		4,373		143		3
Wholesale	63		125		(62)		(50)
Total GWhs sold	4,579		4,498		81		2	%

Average number of retail customers (in thousands)	999		995		4		—	%





Average revenue per MWh:
Retail - fully bundled(1)	$	146.17	$	102.11	$	44.06	43	%

Wholesale	$	98.31	$	42.91	$	55.40	*

Heating degree days	1,310		954		356		37	%
Cooling degree days	3		49		(46)		(94)	%

Sources of energy (GWhs)(2)(3):
Natural gas	3,263		2,378		885		37	%

Renewables	15		14		1		7
Total energy generated	3,278		2,392		886		37
Energy purchased	1,137		1,761		(624)		(35)
Total	4,415		4,153		262		6	%

Average cost of energy per MWh(4):
Energy generated	$	90.64	$	41.92	$	48.72	*
Energy purchased	$	76.11	$	63.27	$	12.84	20	%

* Not meaningful

(1) Fully bundled includes sales to customers for combined energy, transmission and distribution services.

(2) The average cost of energy per MWh and sources of energy excludes 283 GWhs and 424 GWhs of gas generated energy that is purchased at cost by related parties for the first quarter of 2023 and 2022, respectively.

(3) GWh amounts are net of energy used by the related generating facilities.

(4) The average cost of energy per MWh includes only the cost of fuel associated with the generating facilities, purchased power and deferrals.

118

Quarter Ended March 31, 2023 Compared to Quarter Ended March 31, 2022

Utility margin increased $12 million, or 6%, for the first quarter of 2023 compared to 2022 primarily due to:

•$3 million of higher electric retail utility margin due to higher retail customer volumes. Retail customer volumes, including distribution only service customers, increased 3.3% primarily due to an increase in the average number of customers and the favorable impact of weather;

•$3 million of higher energy efficiency program rates (offset in operations and maintenance expense);

•$3 million of higher other retail revenue; and

•$2 million of higher regulatory-related revenue deferrals.

Operations and maintenance increased $8 million, or 12%, for the first quarter of 2023 compared to 2022 primarily due to higher customer service operations expenses, higher energy efficiency program costs (offset in operating revenue) and higher plant operations and maintenance expenses.

Depreciation and amortization increased $3 million, or 3%, for the first quarter of 2023 compared to 2022 primarily due to higher plant placed in-service.

Interest expense increased $11 million, or 29%, for the first quarter of 2023 compared to 2022 primarily due to higher long-term debt.

Interest and dividend income increased $13 million for the first quarter of 2023 compared to 2022 primarily due to higher interest income, mainly from carrying charges on regulatory balances.

Other, net increased $3 million for the first quarter of 2023 compared to 2022 primarily due to higher cash surrender value of corporate-owned life insurance policies.

Liquidity and Capital Resources

As of March 31, 2023, Nevada Power's total net liquidity was as follows (in millions):


Cash and cash equivalents	$	23

Credit facility	400
Less -
Short-term debt	(33)

Net credit facility	367

Total net liquidity	$	390
Credit facility:
Maturity date	2025

Operating Activities

Net cash flows from operating activities for the three-month periods ended March 31, 2023 and 2022, were $(212) million and $85 million, respectively. The change was primarily due to higher payments related to fuel and energy costs, partially offset by higher collections from customers.

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

Investing Activities

Net cash flows from investing activities for the three-month periods ended March 31, 2023 and 2022, were $(233) million and $(189) million, respectively. The change was primarily due to increased capital expenditures, offset by the repayment of an affiliate note receivable. Refer to "Future Uses of Cash" for further discussion of capital expenditures.

119

Financing Activities

Net cash flows from financing activities for the three-month periods ended March 31, 2023 and 2022, were $427 million and $120 million, respectively. The change was primarily due to contributions from NV Energy, Inc. and higher proceeds from short-term debt, partially offset by lower proceeds from the issuance of long-term debt.

Long-Term Debt

Debt Authorizations

Nevada Power currently has financing authority from the PUCN consisting of the ability to: (1) establish debt issuances limited to a debt ceiling of $3.8 billion (excluding borrowings under Nevada Power's $400 million secured credit facility); and (2) maintain a revolving credit facility of up to $1.3 billion. Nevada Power currently has an effective shelf registration statement with the SEC to issue up to $2.6 billion of general and refunding mortgage securities through November 2025.

Future Uses of Cash

Nevada Power 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 use of its secured revolving credit facility, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which Nevada Power has access to external financing depends on a variety of factors, including regulatory approvals, Nevada Power's credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the utility industry.

Capital Expenditures

Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, changes in environmental and other rules and regulations; impacts to customer rates; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital. Prudently incurred expenditures for compliance-related items such as pollution control technologies, replacement generation and associated operating costs are generally incorporated into Nevada Power's regulated retail rates.

Nevada Power'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
	2022		2023		2023

Electric distribution	$	51	$	69	$	285
Electric transmission	21		34		130
Solar generation	7		30		205
Electric battery storage	—		39		190
Other	110		161		528
Total	$	189	$	333	$	1,338

120

Nevada Power received PUCN approval through its previous IRP filings for an increase in solar generation and electric transmission and through the fourth amendment to its 2021 Joint IRP filing for the addition of peaking turbines at a generating facility. Nevada Power has included estimates from its previous and latest IRP filings in its forecast capital expenditures for 2023. These estimates may change as a result of the RFP process. Nevada Power's historical and forecast capital expenditures include the following:

•Electric distribution includes both growth projects and operating expenditures consisting of routine expenditures for distribution needed to serve existing and expected demand.

•Electric transmission includes both growth projects and operating expenditures. Growth projects primarily relate to the Nevada Utilities' Greenlink Nevada transmission expansion program. Nevada Power has received approval from the PUCN to build a 350-mile, 525-kV transmission line, known as Greenlink West, connecting the Ft. Churchill substation to the Northwest substation to the Harry Allen substation; a 235-mile, 525-kV transmission line, known as Greenlink North, connecting the new Ft. Churchill substation to the Robinson Summit substation; a 46-mile, 345-kV transmission line from the new Ft. Churchill substation to the Mira Loma substation; and a 38-mile, 345-kV transmission line from the new Ft. Churchill substation to the Robinson Summit substation. Operating expenditures consist of routine expenditures for transmission and other infrastructure needed to serve existing and expected demand.

•Solar generation investment includes expenditures for a 150-MW solar photovoltaic facility with an additional 100 MWs of co-located battery storage that will be developed in Clark County, Nevada. Commercial operation is expected by the end of 2023.

•Electric battery storage includes two growth projects consisting of a 100-MW battery energy storage system co-located with a 150-MW solar photovoltaic facility that will be developed in Clark County, Nevada. Commercial operation is expected by the end of 2023. The second project is a 220-MW grid-tied battery energy storage system that will be developed on the site of the retired Reid Gardner generating facility in Clark County, Nevada. Commercial operation is expected by the end of 2023.

•Other includes both growth projects and operating expenditures. Growth projects primarily consist of an additional 400 MW of peaking combustion turbines that will be developed at the Silverhawk generating facility in Clark County, Nevada. Commercial operation is expected by the third quarter of 2024. Operating expenditures consist of turbine upgrades at several generating facilities, routine expenditures for generation, other operating projects and other infrastructure needed to serve existing and expected demand.

Material Cash Requirements

As of March 31, 2023, there have been no material changes in cash requirements from the information provided in Item 7 of Nevada Power's Annual Report on Form 10-K for the year ended December 31, ~~2016. See~~2022, other than those disclosed in Note 84 of the Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

Regulatory Matters

Nevada Power is subject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for discussion regarding Nevada Power's current regulatory matters.

Environmental Laws and Regulations

Nevada Power is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions performance standards, water quality, coal ash disposal and other environmental matters that have the potential to impact Nevada Power'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 and local agencies. Nevada Power believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and Nevada Power is unable to predict the impact of the changing laws and regulations on its operations and financial results.

Refer to "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information regarding environmental laws and regulations.

121

Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the 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 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 long-lived assets, income taxes and revenue recognition - unbilled revenue. For additional discussion of Nevada Power's critical accounting estimates, see Item 7 of Nevada Power's Annual Report on Form 10‑K for the year ended December 31, 2022. There have been no significant changes in Nevada Power's assumptions regarding critical accounting estimates since December 31, 2022.

122

Sierra Pacific Power Company and its subsidiaries

Consolidated Financial Section

123

PART I

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Sierra Pacific Power Company

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Sierra Pacific Power Company and subsidiaries ("Sierra Pacific") as of March 31, 2023, the related consolidated statements of operations, changes in shareholder's equity, and cash flows for the three-month periods ended March 31, 2023 and 2022, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of Sierra Pacific as of December 31, 2022, and the related consolidated statements of operations, changes in shareholder's equity, and cash flows for the year then ended (not presented herein); and in our report dated February 24, 2023, 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, 2022, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for ~~further~~Review Results

This interim financial information ~~about~~is the responsibility of Sierra Pacific's management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to Sierra Pacific in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

/s/ Deloitte & Touche LLP

Las Vegas, Nevada

May 5, 2023

124

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions, except share data)


	As of
	March 31,		December 31,
	2023		2022
ASSETS
Current assets:
Cash and cash equivalents	$	8	$	49
Trade receivables, net	181		175

Inventories	83		79

Regulatory assets	310		357

Other current assets	34		50
Total current assets	616		710

Property, plant and equipment, net	3,622		3,587

Regulatory assets	261		254
Other assets	184		181

Total assets	$	4,683	$	4,732

LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	162	$	224
Note payable to affiliate	—		70


Short-term debt	50		—
Current portion of long-term debt	250		250




Other current liabilities	140		108
Total current liabilities	602		652

Long-term debt	898		898
Finance lease obligations	98		100
Regulatory liabilities	428		436
Deferred income taxes	438		445
Other long-term liabilities	144		153
Total liabilities	2,608		2,684

Commitments and contingencies (Note 8)

Shareholder's equity:
Common stock - $3.75 stated value, 20,000,000 shares authorized and 1,000 issued and outstanding	—		—
Additional paid-in capital	1,576		1,576
Retained earnings	500		473
Accumulated other comprehensive loss, net	(1)		(1)
Total shareholder's equity	2,075		2,048

Total liabilities and shareholder's equity	$	4,683	$	4,732

The accompanying notes are an integral part of the consolidated financial statements.

125

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)


	Three-Month Periods
	Ended March 31,
	2023		2022
Operating revenue:
Regulated electric	$	304	$	227
Regulated natural gas	96		52
Total operating revenue	400		279

Operating expenses:
Cost of fuel and energy	181		124
Cost of natural gas purchased for resale	75		34
Operations and maintenance	56		41
Depreciation and amortization	46		36
Property and other taxes	7		6
Total operating expenses	365		241

Operating income	35		38

Other income (expense):
Interest expense	(16)		(13)
Allowance for borrowed funds	2		1
Allowance for equity funds	2		2
Interest and dividend income	7		3
Other, net	1		2
Total other income (expense)	(4)		(5)

Income before income tax expense (benefit)	31		33
Income tax expense (benefit)	4		5
Net income	$	27	$	28

The accompanying notes are an integral part of these consolidated financial statements.

126

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited)

(Amounts in millions, except shares)


								Accumulated
				Additional				Other		Total
	Common Stock			Paid-in		Retained		Comprehensive		Shareholder's
	Shares	Amount		Capital		Earnings		Loss, Net		Equity








Balance, December 31, 2021	1,000	$	—	$	1,111	$	425	$	(1)	$	1,535
Net income	—	—		—		28		—		28

Contributions	—	—		130		—		—		130

Balance, March 31, 2022	1,000	$	—	$	1,241	$	453	$	(1)	$	1,693








Balance, December 31, 2022	1,000	$	—	$	1,576	$	473	$	(1)	$	2,048
Net income	—	—		—		27		—		27



Balance, March 31, 2023	1,000	$	—	$	1,576	$	500	$	(1)	$	2,075

The accompanying notes are an integral part of these consolidated financial statements.

127

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)


	Three-Month Periods
	Ended March 31,
	2023		2022
Cash flows from operating activities:
Net income	$	27	$	28
Adjustments to reconcile net income to net cash flows from operating activities:

Depreciation and amortization	46		36
Allowance for equity funds	(2)		(2)
Changes in regulatory assets and liabilities	6		(4)
Deferred income taxes and amortization of investment tax credits	(11)		(3)
Deferred energy	2		(7)
Amortization of deferred energy	42		23

Changes in other operating assets and liabilities:
Trade receivables and other assets	(5)		12
Inventories	(4)		(6)
Accrued property, income and other taxes	17		7
Accounts payable and other liabilities	(31)		(21)
Net cash flows from operating activities	87		63

Cash flows from investing activities:
Capital expenditures	(104)		(83)


Net cash flows from investing activities	(104)		(83)

Cash flows from financing activities:



Net (repayments of) proceeds from short-term debt	50		(102)

Contributions from parent	—		130
Repayments of affiliate note payable	(70)		—
Other, net	(2)		(2)
Net cash flows from financing activities	(22)		26

Net change in cash and cash equivalents and restricted cash and cash equivalents	(39)		6
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	56		16
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	17	$	22

The accompanying notes are an integral part of these consolidated financial statements.

128

SIERRA PACIFIC POWER COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) General

Sierra Pacific Power Company, together with its subsidiaries ("Sierra Pacific"), is a wholly owned subsidiary of NV Energy, Inc. ("NV Energy"), a holding company that also owns Nevada Power Company and its subsidiaries ("Nevada Power") and certain other subsidiaries. Sierra Pacific is a U.S. regulated electric utility company serving retail customers, including residential, commercial and industrial customers and regulated retail natural gas customers primarily in northern Nevada. NV Energy is an indirect wholly owned subsidiary of Berkshire Hathaway Energy Company ("BHE"). BHE is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in energy businesses. BHE is a consolidated subsidiary of Berkshire Hathaway Inc. ("Berkshire Hathaway").

~~Derivative~~the three-month periods ended March 31, 2023 and 2022. The Consolidated Statements of Comprehensive Income have been omitted as net income equals comprehensive income for the three-month periods ended March 31, 2023 and 2022. The results of operations for the three-month period ended March 31, 2023, are not necessarily indicative of the results to be expected for the full year.

The preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities ~~are~~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 Sierra Pacific's Annual Report on Form 10-K for the year ended December 31, 2022, describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in Sierra Pacific's accounting policies or its assumptions regarding significant accounting estimates during the three-month period ended March 31, 2023.

(2)Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

Cash equivalents consist of funds invested in money market mutual funds, U.S. 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 consist of funds restricted by the Public Utilities Commission of Nevada ("PUCN") for a certain renewable energy contract. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as presented ~~gross~~ on the ~~Companies'~~Consolidated Statements of Cash Flows is outlined below and disaggregated by the line items in which they appear on the Consolidated Balance ~~Sheets. Dominion Energy's derivative contracts include both over-the-counter transactions~~Sheets (in millions):


	As of
	March 31,		December 31,
	2023		2022

Cash and cash equivalents	$	8	$	49
Restricted cash and cash equivalents included in other current assets	9		7
Total cash and cash equivalents and restricted cash and cash equivalents	$	17	$	56

129

(3) Property, Plant and ~~those~~Equipment, Net

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


		As of
	Depreciable Life	March 31,		December 31,
		2023		2022
Utility plant:
Electric generation	25 - 70 years	$	1,301	$	1,298
Electric transmission	50 - 76 years	995		993
Electric distribution	20 - 76 years	1,999		1,983
Electric general and intangible plant	5 - 65 years	221		219
Natural gas distribution	35 - 70 years	459		455
Natural gas general and intangible plant	5 - 65 years	16		15
Common general	5 - 65 years	380		380
Utility plant		5,371		5,343
Accumulated depreciation and amortization		(2,024)		(1,992)
		3,347		3,351


Construction work-in-progress		275		236
Property, plant and equipment, net		$	3,622	$	3,587

During 2022, Sierra Pacific revised its electric and gas depreciation rates effective January 2023 based on the results of a new depreciation study, the most significant impact of which was shorter average service lives for intangible software. The net effect of this change along with various changes to the average service lives of other utility plant groups will increase depreciation and amortization expense by $19 million annually based on depreciable plant balances at the time of the change.

(4)Income Taxes

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


	Three-Month Periods
	Ended March 31,
	2023		2022

Federal statutory income tax rate	21	%	21	%
Effects of ratemaking	(9)		(7)




Other	1		1
Effective income tax rate	13	%	15	%

Berkshire Hathaway includes BHE and its subsidiaries in its U.S. federal income tax return. Consistent with established regulatory practice, Sierra Pacific's provision for federal income tax has been computed on a separate return basis, and substantially all of its currently payable or receivable income tax is remitted to or received from BHE.For the three-month periods ended March 31, 2023 and 2022, Sierra Pacific made no cash payments for federal income tax to BHE.

130

(5) Employee Benefit Plans

Sierra Pacific is a participant in benefit plans sponsored by NV Energy. The NV Energy Retirement Plan includes a qualified pension plan ("Qualified Pension Plan") and a supplemental executive retirement plan and a restoration plan (collectively, "Non‑Qualified Pension Plans") that provide pension benefits for eligible employees. The NV Energy Comprehensive Welfare Benefit and Cafeteria Plan provides certain postretirement health care and life insurance benefits for eligible retirees ("Other Postretirement Plans") on behalf of Sierra Pacific. Amounts attributable to Sierra Pacific were allocated from NV Energy based upon the current, or in the case of retirees, previous, employment location. Offsetting regulatory assets and liabilities have been recorded related to the amounts not yet recognized as a component of net periodic benefit costs that will be included in regulated rates. Net periodic benefit costs not included in regulated rates are ~~executed~~included in accumulated other comprehensive loss, net.

Amounts receivable from (payable to) NV Energy are included on ~~an exchange or other trading platform (exchange contracts)~~the Consolidated Balance Sheets and ~~centrally cleared. Virginia Power's and Dominion Energy Gas' derivative contracts~~ consist of ~~over-the-counter transactions. Over-the-counter contracts are bilateral contracts~~the following (in millions):


	As of
	March 31,		December 31,
	2023		2022
Qualified Pension Plan:

Other non-current assets	$	44	$	43



Non-Qualified Pension Plans:


Other current liabilities	(1)		(1)
Other long-term liabilities	(5)		(5)

Other Postretirement Plans:



Other long-term liabilities	(2)		(2)

(6)Risk Management and Hedging Activities

Sierra Pacific is exposed to the impact of market fluctuations in commodity prices and interest rates. Sierra Pacific is principally exposed to electricity, natural gas and coal market fluctuations primarily through Sierra Pacific's obligation to serve retail customer load in its regulated service territory. Sierra Pacific's load and generating facilities represent substantial underlying commodity positions. Exposures to commodity prices consist mainly of variations in the price of fuel required to generate electricity and wholesale electricity that ~~are transacted directly with a counterparty. Exchange contracts utilize a financial intermediary, exchange, or clearinghouse to enter, execute, or clear the transactions. Certain over-the-counter~~is purchased and ~~exchange contracts contain contractual rights of setoff through master netting arrangements, derivative clearing agreements, and contract default provisions. In addition, the contracts~~sold. Commodity prices are subject to ~~conditional rights~~wide price swings as supply and demand are impacted by, among many other unpredictable items, weather, market liquidity, generating facility availability, customer usage, storage, and transmission and transportation constraints. The actual cost of ~~setoff~~fuel and purchased power is recoverable through the deferred energy mechanism. Interest rate risk exists on variable-rate debt and future debt issuances. Sierra Pacific does not engage in proprietary trading activities.

Sierra Pacific has established a risk management process that is designed to identify, assess, manage and report on each of the various types of risk involved in its business. To mitigate a portion of its commodity price risk, Sierra Pacific uses commodity derivative contracts, which may include forwards, futures, options, swaps and other agreements, to effectively secure future supply or sell future production generally at fixed prices. Sierra Pacific manages its interest rate risk by limiting its exposure to variable interest rates primarily through the issuance of fixed-rate long-term debt and by monitoring market changes in interest rates. Additionally, Sierra Pacific may from time to time enter into interest rate derivative contracts, such as interest rate swaps or locks, to mitigate Sierra Pacific's exposure to interest rate risk. Sierra Pacific does not hedge all of its commodity price and interest rate risks, thereby exposing the unhedged portion to changes in market prices.

There have been no significant changes in Sierra Pacific's accounting policies related to derivatives. Refer to Note 7 for additional information on derivative contracts.

131

The following table, which excludes contracts that have been designated as normal under the normal purchases and normal sales exception afforded by GAAP, summarizes the fair value of Sierra Pacific's derivative contracts, on a gross basis, and reconciles those amounts presented on a net basis on the Consolidated Balance Sheets (in millions):



	Other				Other
	Current		Current		Long-term
	Assets		Liabilities		Liabilities		Total

As of March, 31 2023
Not designated as hedging contracts(1):
Commodity assets	$	1	$	—	$	—	$	1
Commodity liabilities	—		(27)		(7)		(34)




Total derivatives - net basis	$	1	$	(27)	$	(7)	$	(33)

As of December 31, 2022
Not designated as hedging contracts(1):
Commodity assets	$	8	$	—	$	—	$	8
Commodity liabilities	—		(14)		(7)		(21)




Total derivatives - net basis	$	8	$	(14)	$	(7)	$	(13)

(1)Sierra Pacific's commodity derivatives not designated as hedging contracts are included in regulated rates. As of March 31, 2023 a net regulatory asset of $33 million was recorded related to the net derivative liability of $33 million. As of December 31, 2022 a net regulatory asset of $13 million was recorded related to the net derivative liability of $13 million.

The following table summarizes the net notional amounts of outstanding commodity derivative contracts with fixed price terms that comprise the mark-to-market values as of (in millions):


	Unit of	March 31,	December 31,
	Measure	2023	2022

Electricity purchases	Megawatt hours	1	1
Natural gas purchases	Decatherms	67	52

Credit Risk

Sierra Pacific is exposed to counterparty ~~nonperformance, insolvency,~~credit risk associated with wholesale energy supply and marketing activities with other utilities, energy marketing companies, financial institutions and other market participants. Credit risk may be concentrated to the extent Sierra Pacific's counterparties have similar economic, industry or other ~~conditions.~~

~~In general, most over-the-counter transactions~~characteristics and ~~all exchange contracts are subject~~due to direct and indirect relationships among the counterparties. Before entering into a transaction, Sierra Pacific analyzes the financial condition of each significant wholesale counterparty, establishes limits on the amount of unsecured credit to be extended to each counterparty and evaluates the appropriateness of unsecured credit limits on an ongoing basis. To further mitigate wholesale counterparty credit risk, Sierra Pacific enters into netting and collateral ~~requirements. Types of collateral for over-the-counter~~arrangements that may include margining and ~~exchange contracts include cash,~~cross-product netting agreements and obtain third-party guarantees, letters of credit and cash deposits. If required, Sierra Pacific exercises rights under these arrangements, including calling on the counterparty's credit support arrangement.

Collateral and Contingent Features

In accordance with industry practice, certain wholesale agreements, including derivative contracts, contain credit support provisions that in ~~some cases~~part base certain collateral requirements on credit ratings for senior unsecured debt as reported by one or more of the recognized credit rating agencies. These agreements may either specifically provide bilateral rights to demand cash or other ~~forms~~security if credit exposures on a net basis exceed specified rating-dependent threshold levels ("credit-risk-related contingent features") or provide the right for counterparties to demand "adequate assurance" if there is a material adverse change in Sierra Pacific's creditworthiness. These rights can vary by contract and by counterparty. As of ~~security, none~~March 31, 2023, Sierra Pacific's credit ratings for its senior secured debt and its issuer credit ratings for senior unsecured debt from the recognized credit rating agencies were investment grade.

132

The aggregate fair value of Sierra Pacific's derivative contracts in liability positions with specific credit-risk-related contingent features totaled $1 million and $— million as of March 31, 2023 and December 31, 2022, respectively, which ~~are subject~~represents the amount of collateral to ~~restrictions. Cash~~be posted if all credit risk related contingent features for derivative contracts in liability positions had been triggered. Sierra Pacific's collateral ~~is used~~requirements could fluctuate considerably due to market price volatility, changes in credit ratings, changes in legislation or regulation or other factors.

(7) Fair Value Measurements

The carrying value of Sierra Pacific's cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the ~~table below to offset derivative~~short-term maturity of these instruments. Sierra Pacific has various financial assets and ~~liabilities. Certain accounts receivable~~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 Sierra Pacific 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 ~~accounts payable~~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 Sierra Pacific's judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. Sierra Pacific develops these inputs based on the best information available, including its own data.

The following table presents Sierra Pacific's financial assets and liabilities recognized on the ~~Companies'~~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		Total
As of March 31, 2023:
Assets:
Commodity derivatives	$	—	$	—	$	1	$	1
Money market mutual funds	7		—		—		7
Investment funds	1		—		—		1
	$	8	$	—	$	1	$	9

Liabilities - commodity derivatives	$	—	$	—	$	(34)	$	(34)

As of December 31, 2022:
Assets:
Commodity derivatives	$	—	$	—	$	8	$	8
Money market mutual funds	49		—		—		49
Investment funds	1		—		—		1
	$	50	$	—	$	8	$	58

Liabilities - commodity derivatives	$	—	$	—	$	(21)	$	(21)

133

Derivative contracts are recorded on the Consolidated Balance Sheets as ~~well~~either assets or liabilities and are stated at estimated fair value unless they are designated as ~~letters~~normal purchases or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of ~~credit and other forms of security, all of~~derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which Sierra Pacific transacts. When quoted prices for identical contracts are not ~~included~~available, Sierra Pacific uses forward price curves. Forward price curves represent Sierra Pacific's estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. Sierra Pacific bases its forward price curves upon internally developed models, with internal and external fundamental data inputs. Market price quotations for certain electricity and natural gas trading hubs are not as readily obtainable due to markets that are not active. Given that limited market data exists for these contracts, Sierra Pacific uses forward price curves derived from internal models based on perceived pricing relationships to major trading hubs that are based on unobservable inputs. The model incorporates a mid-market pricing convention (the mid‑point price between bid and ask prices) as a practical expedient for valuing its assets and liabilities measured and reported at fair value. The determination of the fair value for derivative contracts not only includes counterparty risk, but also the impact of Sierra Pacific's nonperformance risk on its liabilities, which as of March 31, 2023 and December 31, 2022, had an immaterial impact to the fair value of its derivative contracts. As such, Sierra Pacific considers its derivative contracts to be valued using Level 3 inputs.

Sierra Pacific's investments in money market mutual funds and investment funds 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 ~~tables below, are subject to offset under master netting~~fair value.

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


	Three-Month Periods
	Ended March 31,
	2023		2022

Beginning balance	$	(13)	$	(33)
Changes in fair value recognized in regulatory assets	(20)		(19)


Ending balance	$	(33)	$	(52)

Sierra Pacific's long-term debt is carried at cost on the Consolidated Balance Sheets. The fair value of Sierra Pacific'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 ~~arrangements and would reduce~~credit risks. The carrying value of Sierra Pacific's variable-rate long-term debt approximates fair value because of the ~~net exposure.~~

~~Dominion Energy~~

~~Balance Sheet Presentation~~

~~The tables below present Dominion Energy's derivative asset and liability balances by type~~frequent repricing of ~~financial instrument, before and after the effects of offsetting:~~

September 30, 2017

December 31, 2016

Gross
Amounts of Recognized
Assets

Gross
Amounts
Offset in the Consolidated Balance Sheet

Net Amounts of Assets
Presented in the Consolidated Balance Sheet

Gross
Amounts of Recognized
Assets

Gross
Amounts
Offset in the Consolidated
Balance Sheet

Net Amounts of
Assets
Presented in the Consolidated
Balance Sheet

(millions)

Commodity contracts:

Over-the-counter

$
186

$
—

$
186

$
211

$
—

$
211

Exchange

24

—

24

44

—

44

Interest rate contracts:

Over-the-counter

11

—

11

17

—

17

Foreign currency contracts:

Over-the-counter

25

—

25

—

—

—

Total derivatives, subject to a master netting or
similar arrangement

246

—

246

272

—

272

Total derivatives, not subject to a master netting or
similar arrangement

3

—

3

7

—

7

Total

$
249

$
—

$
249

$
279

$
—

$
279

September 30, 2017

December 31, 2016

Gross Amounts Not Offset
in the Consolidated
Balance Sheet

Gross Amounts Not Offset
in the Consolidated
Balance Sheet

Net Amounts of
Assets Presented
in the
Consolidated
Balance Sheet

Financial
Instruments

Cash
Collateral
Received

Net
Amounts

Net Amounts of
Assets Presented
in the
Consolidated
Balance Sheet

Financial
Instruments

Cash
Collateral
Received

Net
Amounts

(millions)

Commodity contracts:

Over-the-counter

$
186

$
8

$
—

$
178

$
211

$
14

$
—

$
197

Exchange

24

21

—

3

44

44

—

—

Interest rate contracts:

Over-the-counter

11

6

—

5

17

9

—

8

Foreign currency contracts:

Over-the-counter

25

4

—

21

—

—

—

—

Total

$
246

$
39

$
—

$
207

$
272

$
67

$
—

$
205

September 30, 2017

December 31, 2016

Gross
Amounts of
Recognized
Liabilities

Gross
Amounts
Offset in the
Consolidated
Balance Sheet

Net Amounts of
Liabilities
Presented in the
Consolidated
Balance Sheet

Gross
Amounts of
Recognized
Liabilities

Gross
Amounts
Offset in the
Consolidated
Balance Sheet

Net Amounts of
Liabilities
Presented in the
Consolidated
Balance Sheet

(millions)

Commodity contracts:

Over-the-counter

$
19

$
—

$
19

$
23

$
—

$
23

Exchange

21

—

21

71

—

71

Interest rate contracts:

Over-the-counter

72

—

72

53

—

53

Foreign currency contracts:

Over-the-counter

4

—

4

6

—

6

Total derivatives, subject to a master netting or
similar arrangement

116

—

116

153

—

153

Total derivatives, not subject to a master netting or
similar arrangement

2

—

2

2

—

2

Total

$
118

$
—

$
118

$
155

$
—

$
155

September 30, 2017

December 31, 2016

Gross Amounts Not Offset
in the Consolidated
Balance Sheet

Gross Amounts Not Offset
in the Consolidated
Balance Sheet

Net Amounts of
Liabilities
Presented in the
Consolidated
Balance Sheet

Financial
Instruments

Cash
Collateral
Paid

Net
Amounts

Net Amounts of
Liabilities
Presented in the
Consolidated
Balance Sheet

Financial
Instruments

Cash
Collateral
Paid

Net
Amounts

(millions)

Commodity contracts:

Over-the-counter

$
19

$
8

$
—

$
11

$
23

$
14

$
—

$
9

Exchange

21

21

—

—

71

44

27

—

Interest rate contracts:

Over-the-counter

72

6

—

66

53

9

—

44

Foreign currency contracts:

Over-the-counter

4

4

—

—

6

—

—

6

Total

$
116

$
39

$
—

$
77

$
153

$
67

$
27

$
59

~~Volumes~~

these instruments at market rates. The following table presents the ~~volume of Dominion Energy’s derivative activity at September 30, 2017. These volumes are based on open derivative positions~~carrying value and ~~represent the combined absolute~~estimated fair value of ~~its long~~Sierra Pacific's long-term debt (in millions):


	As of March 31, 2023				As of December 31, 2022
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	1,148	$	1,148	$	1,148	$	1,111

(8) Commitments and ~~short positions, except~~Contingencies

Environmental Laws and Regulations

Sierra Pacific is subject to federal, state and local 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 Sierra Pacific's current and future operations. Sierra Pacific believes it is in ~~the case~~material compliance with all applicable laws and regulations.

134

Legal Matters

Sierra Pacific is party to a variety of ~~offsetting transactions, for which they represent the absolute value~~legal actions arising out of the ~~net volume~~normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. Sierra Pacific does not believe that such normal and routine litigation will have a material impact on its ~~long and short positions.~~

Current

Noncurrent

Natural Gas (bcf):

Fixed price⁽¹⁾

62

17

Basis

165

612

Electricity (MWh):

Fixed price

6,749,288

902,069

FTRs

72,126,361

—

Liquids (Gal)⁽²⁾

36,940,288

—

Interest rate⁽³⁾

$
1,100,000,000

$
5,049,890,127

Foreign currency⁽³⁾⁽⁴⁾

$
—

$
280,000,000

consolidated financial results.

~~(1)~~

~~Includes options.~~

~~(2)~~

~~Includes NGLs and oil.~~

~~(3)~~

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

(9) Revenue from Contracts with Customers

~~(4)~~

~~Euro equivalent volumes are €250,000,000.~~

~~Ineffectiveness and AOCI~~

For the three and nine months ended September 30, 2017 and 2016, gains or losses on hedging instruments determined to be ineffective and amounts excluded from the assessment of effectiveness were not material. Amounts excluded from the assessment of effectiveness include changes in the differences between spot prices and forward prices.

The following table ~~presents selected~~summarizes Sierra Pacific's revenue from contracts with customers ("Customer Revenue") by line of business, with further disaggregation of retail by customer class, including a reconciliation to Sierra Pacific's reportable segment information included in Note 10 (in millions):


	Three-Month Periods
	Ended March 31,
	2023						2022
	Electric		Natural Gas		Total		Electric		Natural Gas		Total
Customer Revenue:
Retail:
Residential	$	115	$	60	$	175	$	85	$	32	$	117
Commercial	91		27		118		70		15		85
Industrial	63		9		72		49		4		53
Other	2		—		2		1		—		1
Total fully bundled	271		96		367		205		51		256
Distribution only service	1		—		1		1		—		1
Total retail	272		96		368		206		51		257
Wholesale, transmission and other	32		—		32		21		—		21
Total Customer Revenue	304		96		400		227		51		278
Other revenue	—		—		—		—		1		1
Total operating revenue	$	304	$	96	$	400	$	227	$	52	$	279

(10)Segment Information

Sierra Pacific has identified two reportable operating segments: regulated electric and regulated natural gas. The regulated electric segment derives most of its revenue from regulated retail sales of electricity to residential, commercial, and industrial customers and from wholesale sales. The regulated natural gas segment derives most of its revenue from regulated retail sales of natural gas to residential, commercial, and industrial customers and also obtains revenue by transporting natural gas owned by others through its distribution system. Pricing for regulated electric and regulated natural gas sales are established separately by the PUCN; therefore, management also reviews each segment separately to make decisions regarding allocation of resources and in evaluating performance.

135

The following tables provide information on a reportable segment basis (in millions):


	Three-Month Periods
	Ended March 31,
		2023		2022
Operating revenue:
Regulated electric		$	304	$	227
Regulated natural gas		96		52
Total operating revenue		$	400	$	279





















Operating income:
Regulated electric		$	25	$	30
Regulated natural gas		10		8
Total operating income		35		38
Interest expense		(16)		(13)
Allowance for borrowed funds		2		1
Allowance for equity funds		2		2
Interest and dividend income		7		3
Other, net		1		2
Total income before income tax expense (benefit)		$	31	$	33










	As of
		March 31,		December 31,
		2023		2022
Assets:
Regulated electric		$	4,193	$	4,224
Regulated natural gas		460		441
Other(1)		30		67
Total assets		$	4,683	$	4,732

(1) Consists principally of cash and cash equivalents not included in either the regulated electric or regulated natural gas segments.

136

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 Sierra Pacific during the periods included herein. Explanations include management's best estimate of the impact of weather, customer growth, usage trends and other factors. This discussion should be read in conjunction with Sierra Pacific's historical unaudited Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. Sierra Pacific's actual results in the future could differ significantly from the historical results.

Results of Operations for the First Quarterof 2023 and 2022

Overview

Net income for the first quarter of 2023 was $27 million, a decrease of $1 million, or 4%, compared to 2022 primarily due to higher operations and maintenance expenses, mainly due to higher plant operations and maintenance expenses and higher customer service operations expenses, higher depreciation and amortization, mainly due to higher plant placed in-service and higher regulatory amortizations, and higher interest expense, primarily due to higher interest rates and debt, partially offset by higher utility margin and higher interest and dividend income, primarily from carrying charges on regulatory balances. Electric utility margin increased primarily due to higher retail rates due to the 2022 regulatory rate review with new rates effective January 2023, higher customer volumes and higher transmission and wholesale revenue. Electric retail customer volumes, including distribution only service customers, increased by 2.3% primarily due to the favorable impact of weather and an increase in the average number of customers. Natural gas utility margin increased primarily due to higher customer volumes from the favorable impact of weather. Energy generated increased 11% for the first quarter of 2023 compared to 2022 primarily due to higher natural gas- and coal-fueled generation. Wholesale electricity sales volumes decreased 21% and purchased electricity volumes decreased 20%.

Non-GAAP Financial Measure

Management utilizes various key financial measures that are prepared in accordance with GAAP, as well as non-GAAP financial measures such as, electric utility margin and natural gas utility margin, to help evaluate results of operations. Electric utility margin is calculated as electric operating revenue less cost of fuel and energy while natural gas utility margin is calculated as natural gas operating revenue less cost of natural gas purchased for resale, which are captions presented on the Consolidated Statements of Operations.

Sierra Pacific's cost of fuel and energy and cost of natural gas purchased for resale are generally recovered from its customers through regulatory recovery mechanisms and as a result, changes in Sierra Pacific's expenses result in comparable changes to revenue. As such, management believes electric utility margin and natural gas utility margin more appropriately and concisely explain profitability rather than a discussion of revenue and cost of sales separately. Management believes the presentation of electric utility margin and natural gas utility margin provides meaningful and valuable insight into the information management considers important to running the business and a measure of comparability to others in the industry.

137

Electric utility margin and natural gas utility margin are not measures calculated in accordance with GAAP and should be viewed as a supplement to, and not a substitute for, operating income which is the most directly comparable financial measure prepared in accordance with GAAP. The following table provides a reconciliation of utility margin to operating income (in millions):


	First Quarter
	2023		2022		Change
Electric utility margin:
Operating revenue	$	304	$	227	$	77	34	%
Cost of fuel and energy	181		124		57		46
Electric utility margin	123		103		20		19	%

Natural gas utility margin:
Operating revenue	96		52		44		85	%
Natural gas purchased for resale	75		34		41		*
Natural gas utility margin	21		18		3		17	%

Utility margin	144		121		23		19	%

Operations and maintenance	56		41		15		37	%
Depreciation and amortization	46		36		10		28
Property and other taxes	7		6		1		17
Operating income	$	35	$	38	$	(3)	(8)	%

* Not meaningful

138

Electric Utility Margin

A comparison of key operating results related to ~~gains (losses)~~electric utility margin is as follows:


	First Quarter
	2023		2022		Change
Utility margin (in millions):
Operating revenue	$	304	$	227	$	77	34	%
Cost of fuel and energy	181		124		57		46
Utility margin	$	123	$	103	$	20	19	%

Sales (GWhs):
Residential	732		663		69		10	%
Commercial	721		700		21		3
Industrial	646		755		(109)		(14)
Other	3		4		(1)		(25)
Total fully bundled(1)	2,102		2,122		(20)		(1)
Distribution only service	668		585		83		14
Total retail	2,770		2,707		63		2
Wholesale	229		291		(62)		(21)
Total GWhs sold	2,999		2,998		1		—	%

Average number of retail customers (in thousands)	372		369		3		1	%





Average revenue per MWh:
Retail - fully bundled(1)	$	128.99	$	96.40	$	32.59	34	%

Wholesale	$	107.76	$	51.14	$	56.62	*

Heating degree days	2,652		2,037		615		30	%


Sources of energy (GWhs)(2):
Natural gas	1,066		990		76		8	%
Coal	201		153		48		31
Renewables	4		5		(1)		(20)
Total energy generated	1,271		1,148		123		11
Energy purchased	823		1,033		(210)		(20)
Total	2,094		2,181		(87)		(4)	%

Average cost of energy per MWh(3):
Energy generated	$	102.35	$	59.86	$	42.49	71	%
Energy purchased	$	61.37	$	53.19	$	8.18	15	%

* Not meaningful

(1) Fully bundled includes sales to customers for combined energy, transmission and distribution services.

(2) GWh amounts are net of energy used by the related generating facilities.

(3) The average cost of energy per MWh includes only the cost of fuel associated with the generating facilities, purchased power and deferrals.

139

Natural Gas Utility Margin

A comparison of key operating results related to natural gas utility margin is as follows:


	First Quarter
	2023		2022		Change
Utility margin (in millions):
Operating revenue	$	96	$	52	$	44	85	%
Natural gas purchased for resale	75		34		41		*
Utility margin	$	21	$	18	$	3	17	%

Sold (000's Dths):
Residential	5,866		4,552		1,314		29	%
Commercial	2,938		2,512		426		17
Industrial	1,066		653		413		63
Total retail	9,870		7,717		2,153		28	%

Average number of retail customers (in thousands)	182		179		3		2	%

Average revenue per retail Dth sold	$	9.74	$	6.69	$	3.05	46	%

Heating degree days	2,652		2,037		615		30	%

Average cost of natural gas per retail Dth sold	$	7.63	$	4.36	$	3.27	75	%

* Not meaningful

Quarter Ended March 31, 2023 Compared to Quarter Ended March 31, 2022

Electric utility margin increased$20 million, or 19%, for the first quarter of 2023 compared to 2022 primarily due to:

•$14 million of higher retail rates due to the 2022 regulatory rate review with new rates effective January 2023 and higher customer volumes. Retail customer volumes, including distribution only service customers, increased by 2.3% primarily due to the favorable impact of weather and an increase in the average number of customers; and

•$6 million of higher transmission and wholesale revenue.

Natural gas utility margin increased $3 million, or 17%, for the first quarter of 2023 compared to 2022 primarily due to higher customer volumes from the favorable impact of weather.

Operations and maintenance increased $15 million, or 37%, for the first quarter of 2023 compared to 2022 primarily due to higher plant operations and maintenance expenses, higher regulatory-approved cost recovery for the ON Line reallocation (offset in operating revenue) and higher customer service operations expenses.

Depreciation and amortization increased $10 million, or 28%, for the first quarter of 2023 compared to 2022 primarily due to higher plant placed in-service and higher regulatory amortizations.

Interest expense increased $3 million, or 23%, for the first quarter of 2023 compared to 2022 primarily due to higher interest rates and debt.

Interest and dividend income increased $4 million, for the first quarter of 2023 compared to 2022 primarily due to higher interest income, mainly from carrying charges on regulatory balances.

140

Liquidity and Capital Resources

As of March 31, 2023, Sierra Pacific's total net liquidity was as follows (in millions):


Cash and cash equivalents	$	8

Credit facility	250
Less:

Short-term debt	(50)
Net credit facility	200

Total net liquidity	$	208
Credit facility:
Maturity date	2025

Operating Activities

Net cash ~~flow hedges included in AOCI in Dominion Energy’s Consolidated Balance Sheet at September 30, 2017:~~

AOCI
After-Tax

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

Maximum Term
(millions)

Commodities:

Gas

$
(1
)

$
(1
)

37 months
Electricity

7

7

15 months
Other

(4
)

(4
)

6 months
Interest rate

(260
)

(11
)

387 months
Foreign currency

4

(2
)

105 months
Total

$
(254
)

$
(11
)

flows from operating activities for the three-month periods ended March 31, 2023 and 2022, were $87 million and $63 million, respectively. The ~~amounts that will be reclassified~~change was primarily due to higher collections from ~~AOCI to earnings will generally be~~customers, partially offset by higher payments related to fuel and energy costs.

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

Investing Activities

Net cash flows from investing activities for the three-month periods ended March 31, 2023 and 2022, were $(104) million and $(83) million, respectively. The change was primarily due to increased capital expenditures. Refer to "Future Uses of Cash" for further discussion of capital expenditures.

Financing Activities

Net cash flows from financing activities for the three-month periods ended March 31, 2023 and 2022, were $(22) million and $26 million, respectively. The change was primarily due to lower contributions from NV Energy, Inc. and higher repayments of an affiliate note payable, partially offset by higher proceeds from short-term debt.

Debt Authorizations

Sierra Pacific currently has financing authority from the PUCN consisting of the ~~hedged transactions (e.g., interest payments)~~ability to: (1) establish debt issuances limited to a debt ceiling of $1.9 billion (excluding borrowings under Sierra Pacific's $250 million secured credit facility); and (2) maintain a revolving credit facility of up to $600 million.

Future Uses of Cash

Sierra Pacific 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 use of its secured revolving credit facility, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, debt retirements and other capital requirements. The availability and terms under which Sierra Pacific has access to external financing depends on a variety of factors, including regulatory approvals, Sierra Pacific's credit ratings, investors' judgment of risk and conditions in ~~earnings, thereby achieving~~ the ~~realization~~overall capital markets, including the condition of ~~prices contemplated~~the utility industry.

141

Capital Expenditures

Capital expenditure needs are reviewed regularly by ~~the underlying risk~~ management ~~strategies~~ and ~~will vary from the expected amounts presented above~~may change significantly as a result of these reviews, which may consider, among other factors, changes in ~~market prices, interest rates~~environmental and ~~foreign currency exchange~~other rules and regulations; impacts to customer rates; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; load projections; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital. Prudently incurred expenditures for compliance-related items such as pollution-control technologies, replacement generation and associated operating costs are generally incorporated into Sierra Pacific's regulated retail rates.

~~Fair Value~~

Sierra Pacific's historical and ~~Gains~~forecast capital expenditures, each of which exclude amounts for non-cash equity AFUDC and ~~Losses on Derivative Instruments~~

~~The following table presents the fair values of Dominion Energy’s derivatives~~other non-cash items are as follows (in millions):


	Three-Month Periods				Annual
	Ended March 31,				Forecast
	2022		2023		2023


Electric distribution	$	20	$	32	$	164
Electric transmission	20		19		73
Solar generation	—		—		3
Electric battery storage	—		—		8
Other	43		53		165
Total	$	83	$	104	$	413

Sierra Pacific received PUCN approval through its previous IRP filings for an increase in solar generation and ~~where they are presented~~electric transmission. Sierra Pacific has included estimates from its latest IRP filing in its ~~Consolidated Balance Sheets:~~

Fair Value –
Derivatives under
Hedge
Accounting

Fair Value –
Derivatives not under
Hedge
Accounting

Total Fair Value

(millions)

September 30, 2017

ASSETS

Current Assets

Commodity

$
19

$
83

$
102

Interest rate

9

—

9

Total current derivative assets⁽¹⁾

28

83

111

Noncurrent Assets

Commodity

1

110

111

Interest rate

2

—

2

Foreign currency

25

—

25

Total noncurrent derivative assets⁽²⁾

28

110

138

Total derivative assets

$
56

$
193

$
249

LIABILITIES

Current Liabilities

Commodity

$
15

$
25

$
40

Interest rate

21

—

21

Foreign currency

4

—

4

Total current derivative liabilities⁽³⁾

40

25

65

Noncurrent Liabilities

Commodity

—

2

2

Interest rate

51

—

51

Total noncurrent derivative liabilities⁽⁴⁾

51

2

53

Total derivative liabilities

$
91

$
27

$
118

December 31, 2016

ASSETS

Current Assets

Commodity

$
29

$
101

$
130

Interest rate

10

—

10

Total current derivative assets⁽¹⁾

39

101

140

Noncurrent Assets

Commodity

—

132

132

Interest rate

7

—

7

Total noncurrent derivative assets⁽²⁾

7

132

139

Total derivative assets

$
46

$
233

$
279

LIABILITIES

Current Liabilities

Commodity

$
51

$
41

$
92

Interest rate

33

—

33

Foreign currency

3

—

3

Total current derivative liabilities⁽³⁾

87

41

128

Noncurrent Liabilities

Commodity

1

3

4

Interest rate

20

—

20

Foreign currency

3

—

3

Total noncurrent derivative liabilities⁽⁴⁾

24

3

27

Total derivative liabilities

$
111

$
44

$
155

~~(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.~~

~~(3)~~

~~Current derivative liabilities are presented in other current liabilities in Dominion Energy's Consolidated Balance Sheets.~~

~~(4)~~

~~Noncurrent derivative liabilities are presented in other deferred credits and other liabilities 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 (Effective
Portion)⁽¹⁾

Amount of Gain
(Loss) Reclassified
From AOCI to
Income

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

(millions)

Three Months Ended September 30, 2017

Derivative type and location of gains (losses):

Commodity:

Operating revenue

$
32

Electric fuel and other energy-related purchases

(1
)

Total commodity

$
8

$
31

$
—

Interest rate⁽³⁾

(4
)

(16
)

(26
)
Foreign currency⁽⁴⁾

12

10

—

Total

$
16

$
25

$
(26
)
Three Months Ended September 30, 2016

Derivative type and location of gains (losses):

Commodity:

Operating revenue

$
64

Purchased gas

(1
)

Electric fuel and other energy-related purchases

(1
)

Total commodity

$
7

$
62

$
—

Interest rate⁽³⁾

3

(10
)

(16
)
Foreign currency⁽⁴⁾

12

3

—

Total

$
22

$
55

$
(16
)
Nine Months Ended September 30, 2017

Derivative type and location of gains (losses):

Commodity:

Operating revenue

$
114

Electric fuel and other energy-related purchases

1

Total commodity

$
139

$
115

$
—

Interest rate⁽³⁾

(18
)

(39
)

(60
)
Foreign currency⁽⁴⁾

10

15

—

Total

$
131

$
91

$
(60
)
Nine Months Ended September 30, 2016

Derivative type and location of gains (losses):

Commodity:

Operating revenue

$
266

Purchased gas

(9
)

Electric fuel and other energy-related purchases

(8
)

Total commodity

$
193

$
249

$
—

Interest rate⁽³⁾

(107
)

(21
)

(258
)
Foreign currency⁽⁴⁾

4

1

—

Total

$
90

$
229

$
(258
)

~~(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.~~

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

Three Months Ended September 30,

Nine Months Ended September 30,

Derivatives Not Designated as Hedging Instruments

2017

2016

2017

2016

(millions)

Derivative type and location of gains (losses):

Commodity:

Operating revenue

$
7

$
25

$
22

$
19

Purchased gas

(6
)

(21
)

2

(14
)
Electric fuel and other energy-related purchases

(19
)

(12
)

(51
)

(43
)
Other operations and maintenance

1

—

(1
)

—

Total

$
(17
)

$
(8
)

$
(28
)

$
(38
)

~~(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.

~~Virginia Power~~

~~Balance Sheet Presentation~~

~~The tables below present Virginia Power's derivative asset and liability balances by type of financial instrument, before and after the effects of offsetting:~~

September 30, 2017

December 31, 2016

Gross
Amounts of
Recognized
Assets

Gross
Amounts
Offset in the
Consolidated
Balance Sheet

Net Amounts of
Assets
Presented in the
Consolidated
Balance Sheet

Gross
Amounts of
Recognized Assets

Gross
Amounts
Offset in the
Consolidated
Balance Sheet

Net Amounts of
Assets Presented
in the
Consolidated
Balance Sheet

(millions)

Commodity contracts:

Over-the-counter

$
156

$
—

$
156

$
147

$
—

$
147

Interest rate contracts:

Over-the-counter

—

—

—

6

—

6

Total derivatives, subject to a master netting or
similar arrangement

156

—

156

153

—

153

Total derivatives, not subject to a master netting or
similar arrangement

12

—

12

41

—

41

Total

$
168

$
—

$
168

$
194

$
—

$
194

September 30, 2017

December 31, 2016

Gross Amounts Not Offset
in the Consolidated
Balance Sheet

Gross Amounts Not Offset
in the Consolidated
Balance Sheet

Net Amounts of
Assets Presented
in the
Consolidated
Balance Sheet

Financial
Instruments

Cash
Collateral
Received

Net
Amounts

Net Amounts of
Assets Presented
in the
Consolidated
Balance Sheet

Financial
Instruments

Cash
Collateral
Received

Net
Amounts

(millions)

Commodity contracts:

Over-the-counter

$
156

$
1

$
—

$
155

$
147

$
2

$
—

$
145

Interest rate contracts:

Over-the-counter

—

—

—

—

6

—

—

6

Total

$
156

$
1

$
—

$
155

$
153

$
2

$
—

$
151

September 30, 2017

December 31, 2016

Gross
Amounts of
Recognized
Liabilities

Gross
Amounts
Offset in the
Consolidated
Balance Sheet

Net Amounts of
Liabilities
Presented in the
Consolidated
Balance Sheet

Gross
Amounts of
Recognized
Liabilities

Gross
Amounts
Offset in the
Consolidated
Balance Sheet

Net Amounts of
Liabilities
Presented in the
Consolidated
Balance Sheet

(millions)

Commodity contracts:

Over-the-counter

$
1

$
—

$
1

$
2

$
—

$
2

Interest rate contracts:

Over-the-counter

55

—

55

21

—

21

Total derivatives, subject to a master netting or
similar arrangement

56

—

56

23

—

23

Total derivatives, not subject to a master netting or
similar arrangement

5

—

5

8

—

8

Total

$
61

$
—

$
61

$
31

$
—

$
31

September 30, 2017

December 31, 2016

Gross Amounts Not Offset
in the Consolidated
Balance Sheet

Gross Amounts Not Offset
in the Consolidated
Balance Sheet

Net Amounts of
Liabilities
Presented in the
Consolidated
Balance Sheet

Financial
Instruments

Cash
Collateral
Paid

Net
Amounts

Net Amounts of
Liabilities
Presented in the
Consolidated
Balance Sheet

Financial
Instruments

Cash
Collateral
Paid

Net
Amounts

(millions)

Commodity contracts:

Over-the-counter

$
1

$
1

$
—

$
—

$
2

$
2

$
—

$
—

Interest rate contracts:

Over-the-counter

55

—

—

55

21

—

—

21

Total

$
56

$
1

$
—

$
55

$
23

$
2

$
—

$
21

~~Volumes~~

~~The following table presents the volume of Virginia Power’s derivative activity at September 30, 2017.~~forecast capital expenditures for 2023. These volumes are based on open derivative positions and represent the combined absolute value of its 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⁾

28

6

Basis

85

562

Electricity (MWh):

Fixed price⁽¹⁾

1,426,093

611,629

FTRs

68,673,158

—

Interest rate⁽²⁾

$
300,000,000

$
1,150,000,000

~~(1)~~

~~Includes options.~~

~~(2)~~

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

~~Ineffectiveness and AOCI~~

~~For the three and nine months ended September 30, 2017 and 2016, gains or losses on hedging instruments determined to be ineffective were not material.~~

~~The following table presents selected information related to losses on cash flow hedges included in AOCI in Virginia Power’s Consolidated Balance Sheet at September 30, 2017:~~

AOCI
After-Tax

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

Maximum Term
(millions)

Interest rate

$
(12
)

$
(1
)

387 months
Total

$
(12
)

$
(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 prices contemplated by the underlying risk management strategies and will vary from the expected amounts presented aboveestimates may change as a result of the RFP process. Sierra Pacific's historical and forecast capital expenditures include the following:

•Electric distribution includes both growth projects and operating expenditures consisting of routine expenditures for distribution needed to serve existing and expected demand.

•Electric transmission includes both growth projects and operating expenditures. Growth projects primarily relate to the Nevada Utilities' Greenlink Nevada transmission expansion program. Sierra Pacific has received approval from the PUCN to build a 350-mile, 525-kV transmission line, known as Greenlink West, connecting the Ft. Churchill substation to the Northwest substation to the Harry Allen substation; a 235-mile, 525-kV transmission line, known as Greenlink North, connecting the new Ft. Churchill substation to the Robinson Summit substation; a 46-mile, 345-kV transmission line from the new Ft. Churchill substation to the Mira Loma substation; and a 38-mile, 345-kV transmission line from the new Ft. Churchill substation to the Robinson Summit substation. Operating expenditures consist of routine expenditures for transmission and other infrastructure needed to serve existing and expected demand.

•Other includes both growth projects and operating expenditures consisting of turbine upgrades at the Tracy generating facility, routine expenditures for generation, other operating projects and other infrastructure needed to serve existing and expected demand.

Material Cash Requirements

As of March 31, 2023, there have been no material changes outside the normal course of business in ~~interest rates.~~

material cash requirements from the information provided in Item 7 of Sierra Pacific's Annual Report on Form 10-K for the year ended December 31, 2022.

~~Fair Value~~

Regulatory Matters

Sierra Pacific is subject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for discussion regarding Sierra Pacific's current regulatory matters.

142

Environmental Laws and ~~Gains~~Regulations

Sierra Pacific is subject to federal, state and ~~Losses~~local laws and regulations regarding air quality, climate change, emissions performance standards, water quality, coal ash disposal and other environmental matters that have the potential to impact Sierra Pacific'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 and local agencies. Sierra Pacific believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and Sierra Pacific is unable to predict the impact of the changing laws and regulations on ~~Derivative Instruments~~

~~The following table presents~~its operations and financial results.

Refer to "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information regarding environmental laws and regulations.

Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the ~~fair values~~future. Amounts recognized on the Consolidated Financial Statements based on such estimates involve numerous assumptions subject to varying and potentially significant degrees of ~~Virginia Power’s derivatives~~judgment and ~~where they~~uncertainty and will likely change in the future as additional information becomes available. Estimates are ~~presented in its Consolidated Balance Sheets:~~

Fair Value –
Derivatives under
Hedge
Accounting

Fair Value –
Derivatives not under
Hedge
Accounting

Total Fair Value

(millions)

September 30, 2017

ASSETS

Current Assets

Commodity

$
—

$
61

$
61

Total current derivative assets⁽¹⁾

—

61

61

Noncurrent Assets

Commodity

—

107

107

Total noncurrent derivative assets⁽²⁾

—

107

107

Total derivative assets

$
—

$
168

$
168

LIABILITIES

Current Liabilities

Commodity

$
—

$
6

$
6

Interest rate

17

—

17

Total current derivative liabilities⁽³⁾

17

6

23

Noncurrent Liabilities

Interest rate

38

—

38

Total noncurrent derivatives liabilities ⁽⁴⁾

38

—

38

Total derivative liabilities

$
55

$
6

$
61

December 31, 2016

ASSETS

Current Assets

Commodity

$
—

$
60

$
60

Interest rate

6

—

6

Total current derivative assets⁽¹⁾

6

60

66

Noncurrent Assets

Commodity

—

128

128

Total noncurrent derivative assets⁽²⁾

—

128

128

Total derivative assets

$
6

$
188

$
194

LIABILITIES

Current Liabilities

Commodity

$
—

$
10

$
10

Interest rate

8

—

8

Total current derivative liabilities⁽³⁾

8

10

18

Noncurrent Liabilities

Interest rate

13

—

13

Total noncurrent derivative liabilities⁽⁴⁾

13

—

13

Total derivative liabilities

$
21

$
10

$
31

~~(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)~~

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

~~(4)~~

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

~~The following tables present~~used for, but not limited to, 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, before and after~~accounting for the effects of ~~offsetting.~~

September 30, 2017

December 31, 2016

Gross
Amounts of Recognized
Assets

Gross
Amounts
Offset in the Consolidated Balance Sheet

Net Amounts of Assets
Presented in the Consolidated Balance Sheet

Gross Amounts of Recognized
Assets

Gross
Amounts
Offset in the Consolidated
Balance Sheet

Net Amounts of Assets
Presented in the Consolidated
Balance Sheet

(millions)

Commodity contracts:

Over-the-counter

$
1

$
—

$
1

$
—

$
—

$
—

Foreign currency contracts:

Over-the-counter

25

—

25

—

—

—

Total derivatives, subject to a master netting or
similar arrangement

26

—

26

—

—

—

Total

$
26

$
—

$
26

$
—

$
—

$
—

September 30, 2017

December 31, 2016

Gross Amounts Not Offset
in the Consolidated
Balance Sheet

Gross Amounts Not Offset
in the Consolidated
Balance Sheet

Net Amounts of
Assets Presented
in the
Consolidated
Balance Sheet

Financial
Instruments

Cash
Collateral
Received

Net
Amounts

Net Amounts of
Assets Presented
in the
Consolidated
Balance Sheet

Financial
Instruments

Cash
Collateral
Received

Net
Amounts

(millions)

Commodity contracts:

Over-the-counter

$
1

$
—

$
—

$
1

$
—

$
—

$
—

$
—

Foreign currency contracts:

Over-the-counter

25

4

—

21

—

—

—

—

Total

$
26

$
4

$
—

$
22

$
—

$
—

$
—

$
—

September 30, 2017

December 31, 2016

Gross
Amounts of Recognized Liabilities

Gross
Amounts
Offset in the Consolidated Balance Sheet

Net Amounts of Liabilities Presented in the Consolidated Balance Sheet

Gross
Amounts of Recognized Liabilities

Gross
Amounts
Offset in the Consolidated Balance Sheet

Net Amounts of Liabilities
Presented in the
Consolidated
Balance Sheet

(millions)

Commodity contracts:

Over-the-counter

$
6

$
—

$
6

$
5

$
—

$
5

Foreign currency contracts:

Over-the-counter

4

—

4

6

—

6

Total derivatives, subject to a master netting or
similar arrangement

10

—

10

11

—

11

Total

$
10

$
—

$
10

$
11

$
—

$
11

certain types of regulation, derivatives, impairment of long-lived assets, income taxes and revenue recognition - unbilled revenue. For additional discussion of Sierra Pacific's critical accounting estimates, see Item 7 of Sierra Pacific's Annual Report on Form 10‑K for the year ended December 31, 2022. There have been no significant changes in Sierra Pacific's assumptions regarding critical accounting estimates since December 31, 2022.

September 30, 2017

December 31, 2016

Gross Amounts Not Offset
in the Consolidated
Balance Sheet

Gross Amounts Not Offset
in the Consolidated
Balance Sheet

Net Amounts of
Liabilities
Presented in the
Consolidated
Balance Sheet

Financial Instruments

Cash
Collateral
Paid

Net
Amounts

Net Amounts of
Liabilities
Presented in the
Consolidated
Balance Sheet

Financial Instruments

Cash
Collateral
Paid

Net
Amounts

(millions)

Commodity contracts

Over-the-counter

$
6

$
—

$
—

$
6

$
5

$
—

$
—

$
5

Foreign currency contracts:

Over-the-counter

4

4

—

—

6

—

—

6

Total

$
10

$
4

$
—

$
6

$
11

$
—

$
—

$
11

143

~~Volumes~~

~~The following table presents~~

Eastern Energy Gas Holdings, LLC and its subsidiaries

Consolidated Financial Section

144

PART I

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the ~~volume~~Board of ~~Dominion~~Directors of

Eastern Energy Gas Holdings, LLC

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Eastern Energy Gas Holdings, LLC and subsidiaries ("Eastern Energy Gas") as of March 31, 2023, the related consolidated statements of operations, comprehensive income, changes in equity and cash flows for the three-month periods ended March 31, 2023 and 2022, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of Eastern Energy Gas as of December 31, 2022, and the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for the year then ended (not presented herein); and in our report dated February 24, 2023, 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, 2022, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

This interim financial information is the responsibility of Eastern Energy Gas' ~~derivative activity at September 30, 2017. These volumes~~management. We are ~~based on open derivative positions~~a public accounting firm registered with the PCAOB and ~~represent~~are required to be independent with respect to Eastern Energy Gas in accordance with the ~~combined absolute value~~U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

/s/ Deloitte & Touche LLP

Richmond, Virginia

May 5, 2023

145

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in millions)


	As of
	March 31,		December 31,
	2023		2022
ASSETS
Current assets:
Cash and cash equivalents	$	103	$	65

Trade receivables, net	177		202
Receivables from affiliates	29		30

Notes receivable from affiliates	629		536

Inventories	130		127
Prepayments and other deferred charges	57		78
Natural gas imbalances	60		193
Other current assets	54		72
Total current assets	1,239		1,303

Property, plant and equipment, net	10,281		10,202
Goodwill	1,286		1,286

Investments	285		278

Other assets	94		95

Total assets	$	13,185	$	13,164

The accompanying notes are an integral part of these consolidated financial statements.

146

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions)


	As of
	March 31, 2023		December 31, 2022
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	42	$	86
Accounts payable to affiliates	8		10
Accrued interest	54		19
Accrued property, income and other taxes	69		77


Regulatory liabilities	34		126

Current portion of long-term debt	650		649
Other current liabilities	144		146
Total current liabilities	1,001		1,113

Long-term debt	3,247		3,243


Regulatory liabilities	592		596

Other long-term liabilities	340		324
Total liabilities	5,180		5,276

Commitments and contingencies (Note 8)

Equity:
Member's equity:

Membership interests	4,109		3,983


Accumulated other comprehensive loss, net	(45)		(42)
Total member's equity	4,064		3,941
Noncontrolling interests	3,941		3,947
Total equity	8,005		7,888

Total liabilities and equity	$	13,185	$	13,164

The accompanying notes are an integral part of these consolidated financial statements.

147

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)


	Three-Month Periods
	Ended March 31,
	2023		2022




Operating revenue	$	553	$	482

Operating expenses:

Cost of (excess) gas	20		(1)
Operations and maintenance	143		118
Depreciation and amortization	80		85
Property and other taxes	37		29

Total operating expenses	280		231

Operating income	273		251

Other income (expense):
Interest expense	(37)		(36)

Allowance for equity funds	2		2
Interest and dividend income	9		—

Other, net	—		(1)
Total other income (expense)	(26)		(35)

Income before income tax expense (benefit) and equity income (loss)	247		216
Income tax expense (benefit)	39		30
Equity income (loss)	32		19


Net income	240		205
Net income attributable to noncontrolling interests	118		111
Net income attributable to Eastern Energy Gas	$	122	$	94

The accompanying notes are an integral part of these consolidated financial statements.

148

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

(Amounts in millions)


	Three-Month Periods
	Ended March 31,
	2023		2022

Net income	$	240	$	205

Other comprehensive (loss) income, net of tax:
Unrecognized amounts on retirement benefits, net of tax of $— and $—	(1)		1


Unrealized (losses) gains on cash flow hedges, net of tax of $(1) and $1	(2)		4
Total other comprehensive (loss) income, net of tax	(3)		5

Comprehensive income	237		210
Comprehensive income attributable to noncontrolling interests	118		111
Comprehensive income attributable to Eastern Energy Gas	$	119	$	99

The accompanying notes are an integral part of these consolidated financial statements.

149

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited)

(Amounts in millions)


			Accumulated
			Other
	Membership		Comprehensive		Noncontrolling		Total
	Interests		Loss, Net		Interests		Equity








Balance, December 31, 2021	$	3,501	$	(43)	$	4,036	$	7,494
Net income	94		—		111		205
Other comprehensive income	—		5		—		5


Distributions	—		—		(114)		(114)





Balance, March 31, 2022	$	3,595	$	(38)	$	4,033	$	7,590








Balance, December 31, 2022	$	3,983	$	(42)	$	3,947	$	7,888
Net income	122		—		118		240
Other comprehensive loss	—		(3)		—		(3)
Distributions	(6)		—		(124)		(130)
Contributions	10		—		—		10

Balance, March 31, 2023	$	4,109	$	(45)	$	3,941	$	8,005

The accompanying notes are an integral part of these consolidated financial statements.

150

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)


	Three-Month Periods
	Ended March 31,
	2023		2022
Cash flows from operating activities:
Net income	$	240	$	205
Adjustments to reconcile net income to net cash flows from operating activities:

Losses on other items, net	1		1
Depreciation and amortization	80		85
Allowance for equity funds	(2)		(2)
Equity (income) loss, net of distributions	(6)		(8)
Changes in regulatory assets and liabilities	(92)		(14)
Deferred income taxes	20		27
Other, net	2		2
Changes in other operating assets and liabilities:
Trade receivables and other assets	40		40

Gas balancing activities	19		4
Derivative collateral, net	1		2

Accrued property, income and other taxes	9		(29)

Accounts payable and other liabilities	7		28
Net cash flows from operating activities	319		341

Cash flows from investing activities:
Capital expenditures	(59)		(75)


Repayment of notes by affiliates	40		3
Notes to affiliates	(134)		(117)

Other, net	(3)		(5)
Net cash flows from investing activities	(156)		(194)

Cash flows from financing activities:







Distributions to noncontrolling interests	(124)		(114)


Net cash flows from financing activities	(124)		(114)



Net change in cash and cash equivalents and restricted cash and cash equivalents	39		33
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	95		39
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	134	$	72

The accompanying notes are an integral part of these consolidated financial statements.

151

EASTERN ENERGY GAS HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) General

Eastern Energy Gas Holdings, LLC is a holding company, and together with its ~~long~~subsidiaries ("Eastern Energy Gas") conducts business activities consisting of Federal Energy Regulatory Commission ("FERC")-regulated interstate natural gas transmission systems and ~~short positions, except~~underground storage operations in the ~~case of offsetting transactions, for which they represent the absolute value~~eastern region of the ~~net volume~~U.S. and operates Cove Point LNG, LP ("Cove Point"), a liquefied natural gas ("LNG") export, import and storage facility. Eastern Energy Gas owns 100% of ~~its long~~the general partner interest and ~~short positions.~~

Current

Noncurrent

Natural Gas (bcf):

Fixed price

2

—

Basis

2

—

NGLs (Gal)

30,514,288

—

Foreign currency⁽¹⁾

$
—

$
280,000,000

25% of the limited partnership interest in Cove Point. In addition, Eastern Energy Gas owns a 50% noncontrolling interest in Iroquois Gas Transmission System, L.P. ("Iroquois"), a 416-mile FERC-regulated interstate natural gas transmission system. Eastern Energy Gas is an indirect wholly owned subsidiary of Berkshire Hathaway Energy Company ("BHE"). BHE is a holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in the energy industry. BHE is a consolidated subsidiary of Berkshire Hathaway Inc.

~~(1)~~

~~Maturity is determined based on final settlement period. Euro equivalent volumes are €250,000,000.~~

~~Ineffectiveness~~

~~For~~ the ~~three~~United States Securities and ~~nine months~~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 disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of March 31, 2023 and for the three-month periods ended ~~September 30, 2017~~March 31, 2023 and ~~2016, gains or losses on hedging instruments determined~~2022. The results of operations for the three-month period ended March 31, 2023 are not necessarily indicative of the results to be ~~ineffective were not material.~~

expected for the full year.

The preparation of the unaudited Consolidated Financial Statements in 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 Eastern Energy Gas' Annual Report on Form 10-K for the year ended December 31, 2022 describes the most significant accounting policies used in the preparation of the unaudited Consolidated Financial Statements. There have been no significant changes in Eastern Energy Gas' accounting policies or its assumptions regarding significant accounting estimates during the three-month period ended March 31, 2023.

152

(2) Property, Plant and Equipment, Net

Property, plant and equipment, net consists of the following ~~table presents selected information~~(in millions):


		As of
		March 31,		December 31,
	Depreciable Life	2023		2022
Utility plant:

Interstate natural gas transmission and storage assets	21 - 52 years	$	9,053	$	8,922
Intangible plant	5 - 18 years	116		113
Utility plant in-service		9,169		9,035
Accumulated depreciation and amortization		(3,075)		(3,039)
Utility plant in-service, net		6,094		5,996

Nonutility plant:

LNG facility	40 years	4,526		4,522
Intangible plant	14 years	25		25
Nonutility plant		4,551		4,547
Accumulated depreciation and amortization		(574)		(542)
Nonutility plant, net		3,977		4,005

		10,071		10,001
Construction work-in-progress		210		201
Property, plant and equipment, net		$	10,281	$	10,202

Construction work-in-progress includes $192 million and $181 million as of March 31, 2023 and December 31, 2022, respectively, related to ~~gains (losses) on cash flow hedges included~~the construction of utility plant.

(3) Regulatory Matters

In September 2021, Eastern Gas Transmission and Storage, Inc. ("EGTS") filed a general rate case for its FERC-jurisdictional services, with proposed rates to be effective November 1, 2021. EGTS proposed an annual cost-of-service of approximately $1.1 billion, and requested increases in ~~AOCI~~various rates, including general system storage rates by 85% and general system transmission rates by 60%. In October 2021, the FERC issued an order that accepted the November 1, 2021 effective date for certain changes in ~~Dominion Energy Gas' Consolidated Balance Sheet at~~rates, while suspending the other changes for five months following the proposed effective date, until April 1, 2022, subject to refund. In September ~~30, 2017:~~

AOCI
After-Tax

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

Maximum Term
(millions)

Commodities:

NGLs

$
(4
)

$
(4
)

6 months
Interest rate

(26
)

(3
)

327 months
Foreign currency

4

(2
)

105 months
Total

$
(26
)

$
(9
)

~~The amounts that will be reclassified from AOCI to earnings will generally be offset by~~2022, a settlement agreement was filed with the ~~recognition~~FERC, which provided for increased service rates and decreased depreciation rates. Under the terms of the ~~hedged transactions (e.g.,~~settlement agreement, EGTS' rates result in an increase to annual firm transmission and storage services revenues of approximately $160 million and a decrease in annual depreciation expense of approximately $30 million, compared to the rates in effect prior to April 1, 2022. EGTS' provision for rate refund for April 2022 through February 2023, including accrued interest, ~~payments)~~totaled $91 million. In November 2022, the FERC approved the settlement agreement and the rate refunds to customers were processed in ~~earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies~~late February 2023.

153

(4) Investments and ~~will vary from the expected amounts presented above as a result of changes in market prices, interest rates~~Restricted Cash and ~~foreign currency exchange rates.~~

Cash Equivalents

~~Fair Value~~

Investments 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)

September 30, 2017

ASSETS

Current Assets

Commodity

$
—

$
1

$
1

Total current derivative assets⁽¹⁾

—

1

1

Noncurrent Assets

Foreign currency

25

—

25

Total noncurrent derivative assets⁽²⁾

25

—

25

Total derivative assets

$
25

$
1

$
26

LIABILITIES

Current Liabilities

Commodity

$
6

$
—

$
6

Foreign currency

4

—

4

Total current derivative liabilities⁽³⁾

10

—

10

Total derivative liabilities

$
10

$
—

$
10

December 31, 2016

LIABILITIES

Current Liabilities

Commodity

$
4

$
—

$
4

Foreign currency

3

—

3

Total current derivative liabilities⁽³⁾

7

—

7

Noncurrent Liabilities

Commodity

1

—

1

Foreign currency

3

—

3

Total noncurrent derivative liabilities⁽⁴⁾

4

—

4

Total derivative liabilities

$
11

$
—

$
11

~~(1)~~

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

~~(2)~~

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

~~(3)~~

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

~~(4)~~

~~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 (Effective Portion)⁽¹⁾

Amount of Gain
(Loss) Reclassified From AOCI
to Income

(millions)

Three Months Ended September 30, 2017

Derivative Type and Location of Gains (Losses):

Commodity:

Operating revenue

$
(2
)
Total commodity

$
(10
)

$
(2
)
Interest rate⁽²⁾

—

(1
)
Foreign currency⁽³⁾

12

10

Total

$
2

$
7

Three Months Ended September 30, 2016

Derivative Type and Location of Gains (Losses):

Commodity:

Operating revenue

$
1

Total commodity

$
—

$
1

Interest rate⁽²⁾

—

(1
)
Foreign currency⁽³⁾

12

3

Total

$
12

$
3

Nine Months Ended September 30, 2017

Derivative Type and Location of Gains (Losses):

Commodity:

Operating revenue

$
(4
)
Total commodity

$
(5
)

$
(4
)
Interest rate⁽²⁾

—

(3
)
Foreign currency⁽³⁾

10

15

Total

$
5

$
8

Nine Months Ended September 30, 2016

Derivative Type and Location of Gains (Losses):

Commodity:

Operating revenue

$
6

Total commodity

$
(7
)

$
6

Interest rate⁽²⁾

(8
)

(2
)
Foreign currency⁽³⁾

4

1

Total

$
(11
)

$
5

~~(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.~~

Amount of Gain (Loss) Recognized in Income on Derivatives

Three Months Ended September 30,

Nine Months Ended September 30,

Derivatives Not Designated as Hedging Instruments

2017

2016

2017

2016

(millions)

Derivative type and location of gains (losses):

Commodity:

Operating revenue

$
—

$
5

$
—

$
3

Total

$
—

$
5

$
—

$
3

~~Note 10. Investments~~

~~Dominion Energy~~

~~Equity and Debt Securities~~

~~Rabbi Trust Securities~~

~~Marketable equity and debt securities~~restricted cash and cash equivalents ~~held~~consists of the following (in millions):


	As of
	March 31,		December 31,
	2023		2022
Investments:
Investment funds	$	17	$	14


Equity method investments:
Iroquois	268		264


Total investments	285		278

Restricted cash and cash equivalents:
Customer deposits	31		30
Total restricted cash and cash equivalents	31		30

Total investments and restricted cash and cash equivalents	$	316	$	308

Reflected as:
Current assets	$	31	$	30
Noncurrent assets	285		278
Total investments and restricted cash and cash equivalents	$	316	$	308

Equity Method Investments

Eastern Energy Gas, through subsidiaries, owns 50% of Iroquois, which owns and operates an interstate natural gas transmission system located in ~~Dominion Energy’s rabbi trusts~~the states of New York and ~~classified as trading totaled $109 million and $104 million at September 30, 2017~~Connecticut.

As of March 31, 2023 and December 31, ~~2016, respectively.~~

~~Decommissioning Trust Securities~~

Dominion Energy holds marketable equity and debt securities (classified as available-for-sale), cash equivalents and cost method investments 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⁽¹⁾

Total
Unrealized
Losses⁽¹⁾

Fair Value

(millions)

September 30, 2017

Marketable equity securities:

U.S.

$
1,562

$
1,664

$
—

$
3,226

Fixed income:

Corporate debt instruments

438

15

(1
)

452

Government securities

1,041

28

(4
)

1,065

Common/collective trust funds

66

—

—

66

Cost method investments

67

—

—

67

Cash equivalents and other⁽²⁾

5

—

—

5

Total

$
3,179

$
1,707

$
(5
)
⁽³⁾

$
4,881

December 31, 2016

Marketable equity securities:

U.S.

$
1,449

$
1,408

$
—

$
2,857

Fixed income:

Corporate debt instruments

478

13

(4
)

487

Government securities

978

22

(8
)

992

Common/collective trust funds

67

—

—

67

Cost method investments

69

—

—

69

Cash equivalents and other⁽²⁾

12

—

—

12

Total

$
3,053

$
1,443

$
(12
)
⁽³⁾

$
4,484

~~(1)~~

~~Included in AOCI and the nuclear decommissioning trust regulatory liability.~~

~~(2)~~

~~Includes net pending sales of securities of $4 million and $9 million at September 30, 2017 and December 31, 2016, respectively.~~

~~(3)~~

~~The fair value of securities in an unrealized loss position was $402 million and $576 million at September 30, 2017 and December 31, 2016, respectively.~~

~~The fair value of Dominion Energy’s marketable debt securities held in nuclear decommissioning trust funds at September 30, 2017 by contractual maturity is as follows:~~

Amount

(millions)

Due in one year or less

$
183

Due after one year through five years

410

Due after five years through ten years

366

Due after ten years

624

Total

$
1,583

~~Presented below is selected information regarding Dominion Energy’s marketable equity and debt securities held in nuclear decommissioning trust funds.~~

Three Months Ended September 30,

Nine Months Ended September 30,

2017

2016

2017

2016

(millions)

Proceeds from sales

$
377

$
300

$
1,496

$
1,009

Realized gains⁽¹⁾

25

40

142

102

Realized losses⁽¹⁾

16

9

52

43

~~(1)~~

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

~~Dominion Energy recorded other-than-temporary impairment losses on investments held in nuclear decommissioning trust funds as follows:~~

Three Months Ended September 30,

Nine Months Ended September 30,

2017

2016

2017

2016

(millions)

Total other-than-temporary impairment losses⁽¹⁾

$
7

$
9

$
33

$
34

Losses recorded to the nuclear decommissioning trust
regulatory liability

(2
)

(4
)

(13
)

(15
)
Losses recognized in other comprehensive income
(before taxes)

(1
)

—

(2
)

(1
)
Net impairment losses recognized in earnings

$
4

$
5

$
18

$
18

~~(1)~~

Amounts include other-than-temporary impairment losses for debt securities of less than $1 million for both the three months ended September 2017 and 2016, respectively, and $2 million for both the nine months ended September 30, 2017 and 2016, respectively.

~~Virginia Power~~

Virginia Power holds marketable equity and debt securities (classified as available-for-sale), cash equivalents and cost method investments 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⁽¹⁾

Total Unrealized
Losses⁽¹⁾

Fair Value

(millions)

September 30, 2017

Marketable equity securities:

U.S.

$
729

$
741

$
—

$
1,470

Fixed income:

Corporate debt instruments

226

8

—

234

Government securities

483

13

(2
)

494

Common/collective trust funds

29

—

—

29

Cost method investments

67

—

—

67

Cash equivalents and other⁽²⁾

(2
)

—

—

(2
)
Total

$
1,532

$
762

$
(2
)
⁽³⁾
$
2,292

December 31, 2016

Marketable equity securities:

U.S.

$
677

$
624

$
—

$
1,301

Fixed income:

Corporate debt instruments

274

6

(4
)

276

Government securities

420

9

(2
)

427

Common/collective trust funds

26

—

—

26

Cost method investments

69

—

—

69

Cash equivalents and other⁽²⁾

7

—

—

7

Total

$
1,473

$
639

$
(6
)
⁽³⁾
$
2,106

~~(1)~~

~~Included in AOCI and the nuclear decommissioning trust regulatory liability.~~

~~(2)~~

~~Includes pending purchases of securities of $2 million and pending sales of securities of $7 million at September 30, 2017 and December 31, 2016, respectively.~~

~~(3)~~

~~The fair value of securities in an unrealized loss position was $165 million and $287 million at September 30, 2017 and December 31, 2016, respectively.~~

~~The fair value of Virginia Power’s marketable debt securities held in nuclear decommissioning trust funds at September 30, 2017 by contractual maturity is as follows:~~

Amount

(millions)

Due in one year or less

$
60

Due after one year through five years

192

Due after five years through ten years

189

Due after ten years

316

Total

$
757

~~Presented below is selected information regarding Virginia Power’s marketable equity and debt securities held in nuclear decommissioning trust funds.~~

Three Months Ended September 30,

Nine Months Ended September 30,

2017

2016

2017

2016

(millions)

Proceeds from sales

$
156

$
131

$
654

$
478

Realized gains⁽¹⁾

9

18

64

48

Realized losses⁽¹⁾

6

4

24

21

~~(1)~~

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

Other-than-temporary impairment losses on investments held in nuclear decommissioning trust funds recognized in earnings for Virginia Power were not material for the three and nine months ended September 30, 2017 and 2016.

~~Equity Method Investments~~

~~Dominion Energy~~

~~Atlantic Coast Pipeline~~

In October 2016, Dominion Energy purchased an additional 3% membership interest in Atlantic Coast Pipeline from Duke for $14 million, which adjusted Dominion Energy’s and Duke’s membership interest to 48% and 47%, respectively.

Dominion Energy contributed $84 million and $286 million during the three and nine months ended September 30, 2017 and $74 million and $143 million during the three and nine months ended September 30, 2016, respectively, to Atlantic Coast Pipeline.

~~Dominion Energy Gas~~

~~Iroquois~~

Dominion Energy Gas' equity earnings totaled $15 million and $14 million for the nine months ended September 30, 2017 and 2016, respectively. Dominion Energy Gas received distributions from this investment of $17 million for both the nine months ended September 30, 2017 and 2016. At September 30, 2017 and December 31, 2016,2022, the carrying amount of ~~Dominion~~Eastern Energy Gas' ~~investment of $96 million and $98 million, respectively,~~investments exceeded its share of underlying equity in net assets by $8$130 million. The difference reflects equity method goodwill and is not being amortized. ~~In May 2016, Dominion~~Eastern Energy Gas ~~sold 0.65%~~received distributions from its investments of $26 million and $11 million for the three-month periods ended March 31, 2023 and 2022, respectively.

Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

Cash equivalents consist of funds invested in money market mutual funds, U.S. 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 consist of customer deposits as allowed under the FERC gas tariffs. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as presented on 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,
	2023		2022

Cash and cash equivalents	$	103	$	65
Restricted cash and cash equivalents included in other current assets	31		30
Total cash and cash equivalents and restricted cash and cash equivalents	$	134	$	95

154

(5) Income Taxes

A reconciliation of the ~~non-controlling partnership interest~~federal statutory income tax rate to the effective income tax rate applicable to income before income tax expense (benefit) is as follows:


	Three-Month Periods
	Ended March 31,
	2023		2022

Federal statutory income tax rate	21	%	21	%
State income tax, net of federal income tax benefit	2		5



Equity interest	3		2
Effects of ratemaking	—		(4)





Noncontrolling interest	(10)		(11)

Other, net	—		1
Effective income tax rate	16	%	14	%

For the period ended March 31, 2023, Eastern Energy Gas' reconciliation of the federal statutory income tax rate to the effective income tax rate is driven primarily by an absence of tax on income attributable to Cove Point's 75% noncontrolling interest.

(6) Employee Benefit Plans

Eastern Energy Gas is a participant in ~~Iroquois~~benefit plans sponsored by MidAmerican Energy Company ("MidAmerican Energy"), an affiliate. The MidAmerican Energy Company Retirement Plan includes a qualified pension plan that provides pension benefits for eligible employees. The MidAmerican Energy Company Welfare Benefit Plan provides certain postretirement health care and life insurance benefits for eligible retirees on behalf of Eastern Energy Gas. Eastern Energy Gas contributed $2 million and $3 million to ~~TransCanada Corporation~~the MidAmerican Energy Company Retirement Plan for ~~approximately $7~~the three-month periods ended March 31, 2023 and 2022, respectively, and $1 million ~~which resulted~~to the MidAmerican Energy Company Welfare Benefit Plan for the three-month periods ended March 31, 2023 and 2022. Contributions related to these plans are reflected as net periodic benefit cost in ~~a $5 million ($3 million after-tax) gain, included~~operations and maintenance expense on the Consolidated Statements of Operations. Amounts attributable to Eastern Energy Gas were allocated from MidAmerican Energy in ~~other income in Dominion Energy Gas’ Consolidated Statement of Income.~~

~~Note 11. Regulatory Assets and Liabilities~~

~~Regulatory~~accordance with the intercompany administrative service agreement. Offsetting regulatory assets and liabilities ~~include the following:~~

September 30, 2017

December 31, 2016

(millions)

Dominion Energy

Regulatory assets:

Deferred rate adjustment clause costs⁽¹⁾

$
67

$
63

Deferred nuclear refueling outage costs⁽²⁾

67

71

Unrecovered gas costs⁽³⁾

51

19

Deferred cost of fuel used in electric generation⁽⁴⁾

30

—

Other

96

91

Regulatory assets-current

311

244

Unrecognized pension and other postretirement benefit costs⁽⁵⁾

1,296

1,401

Deferred rate adjustment clause costs⁽¹⁾

333

329

Derivatives⁽⁶⁾

230

174

PJM transmission rates⁽⁷⁾

215

192

Income taxes recoverable through future rates⁽⁸⁾

157

123

Utility reform legislation⁽⁹⁾

134

99

Other

138

155

Regulatory assets-noncurrent

2,503

2,473

Total regulatory assets

$
2,814

$
2,717

Regulatory liabilities:

PIPP⁽¹⁰⁾

$
20

$
28

Deferred cost of fuel used in electric generation⁽⁴⁾

5

61

Other

63

74

Regulatory liabilities-current

88

163

Provision for future cost of removal and AROs⁽¹¹⁾

1,477

1,427

Nuclear decommissioning trust⁽¹²⁾

1,034

902

Unrecognized pension and other postretirement benefit costs⁽⁵⁾

106

105

Derivatives⁽⁶⁾

78

69

Other

211

119

Regulatory liabilities-noncurrent

2,906

2,622

Total regulatory liabilities

$
2,994

$
2,785

Virginia Power

Regulatory assets:

Deferred nuclear refueling outage costs⁽²⁾

$
67

$
71

Deferred rate adjustment clause costs⁽¹⁾

47

51

Deferred cost of fuel used in electric generation⁽⁴⁾

30

—

Other

62

57

Regulatory assets-current⁽¹³⁾

206

179

Deferred rate adjustment clause costs⁽¹⁾

256

246

PJM transmission rates⁽⁷⁾

215

192

Derivatives⁽⁶⁾

197

133

Income taxes recoverable through future rates⁽⁸⁾

67

76

Other

103

123

Regulatory assets-noncurrent

838

770

Total regulatory assets

$
1,044

$
949

Regulatory liabilities:

Deferred cost of fuel used in electric generation⁽⁴⁾

$
5

$
61

Other

38

54

Regulatory liabilities-current⁽¹⁴⁾

43

115

Nuclear decommissioning trust⁽¹²⁾

1,034

902

Provision for future cost of removal⁽¹¹⁾

985

946

Derivatives⁽⁶⁾

78

69

September 30, 2017

December 31, 2016

(millions)

Other

105

45

Regulatory liabilities-noncurrent

2,202

1,962

Total regulatory liabilities

$
2,245

$
2,077

Dominion Energy Gas

Regulatory assets:

Deferred rate adjustment clause costs⁽¹⁾

$
20

$
12

Unrecovered gas costs⁽³⁾

—

12

Other

2

2

Regulatory assets-current⁽¹³⁾

22

26

Unrecognized pension and other postretirement benefit costs⁽⁵⁾

300

358

Utility reform legislation⁽⁹⁾

134

99

Deferred rate adjustment clause costs⁽¹⁾

77

79

Income taxes recoverable through future rates⁽⁸⁾

32

23

Other

13

18

Regulatory assets-noncurrent⁽¹⁵⁾

556

577

Total regulatory assets

$
578

$
603

Regulatory liabilities:

PIPP⁽¹⁰⁾

$
20

$
28

Other

19

7

Regulatory liabilities-current⁽¹⁴⁾

39

35

Provision for future cost of removal and AROs⁽¹¹⁾

178

174

Other

74

45

Regulatory liabilities-noncurrent⁽¹⁶⁾

252

219

Total regulatory liabilities

$
291

$
254

~~(1)~~

Reflects deferrals under the electric transmission FERC formula rate and the deferral of costs associated with certain current and prospective rider projects for Virginia Power. Reflects deferrals of costs associated with certain current and prospective rider projects for Dominion Energy Gas. See Note 12 for more information.

~~(2)~~

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.

~~(3)~~

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

~~(4)~~

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

~~(5)~~

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 and Dominion Energy Gas' rate-regulated subsidiaries.

~~(6)~~

For jurisdictions subject to cost-based rate regulation, changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities as they are expected to be recovered from or refunded to customers.

~~(7)~~

~~Reflects amounts~~have been recorded related ~~to the PJM transmission cost allocation matter. See Note 12 for more information.~~

~~(8)~~

Amounts to be recovered through future rates to pay income taxes that become payable when rate revenue is provided to recover AFUDC-equity and depreciation of property, plant and equipment for which deferred income taxes were not recognized for ratemaking purposes, including amounts attributable to tax rate changes.

~~(9)~~

Ohio legislation under House Bill 95, which became effective in September 2011. This law updates natural gas legislation by enabling gas companies to include more up-to-date cost levels when filing rate cases. It also allows gas companies to seek approval of capital expenditure plans under which gas companies can recognize carrying costs on associated capital investments placed in service and can defer the carrying costs plus depreciation and property tax expenses for recovery from ratepayers in the future.

~~(10)~~

Under PIPP, eligible customers can make reduced payments based on their ability to pay. The difference between the customer's total bill and the PIPP plan amount is deferred and collected or returned annually under the PIPP rate adjustment clause according to East Ohio tariff provisions.

~~(11)~~

~~Rates charged to customers by the Companies' 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.~~

~~(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.

~~(13)~~

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

~~(14)~~

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

~~(15)~~

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

~~(16)~~

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

At September 30, 2017, $323 million of Dominion Energy's and $242 million of Virginia Power's regulatory assets represented past expenditures on which they do not currently earn a return. With the exception of the $215 million PJM transmission cost allocation matter, the majority of these expenditures are expected to be recovered within the next two years.

~~Note 12. 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~~amounts not possible for the Companies to estimate a range of possible loss. For matters for which the Companies cannot estimate a range of possible loss, 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 for which 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 available information, involves elements of judgment and significant uncertainties 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 - Electric~~

Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public utilities. Dominion Energy’s merchant generators sell electricity in the PJM, MISO, CAISO and ISO-NE wholesale markets, and to wholesale purchasers in the states of Virginia, North Carolina, Indiana, Connecticut, Tennessee, Georgia, California, South Carolina and Utah, under Dominion Energy’s market-based sales tariffs authorized by FERC or pursuant to FERC authority to sellyet recognized as a ~~qualified facility. Virginia Power purchases and, under its FERC market-based rate authority, sells electricity in the wholesale market. In addition, Virginia Power has FERC approval~~component of a tariff to sell wholesale power at capped rates based on its embedded cost of generation. This cost-based sales tariff could be used to sell to loads within or outside Virginia Power’s service territory. Any such sales would be voluntary.

~~Rates~~

In April 2008, FERC granted an application for Virginia Power’s electric transmission operations to establish a forward-looking formula rate mechanism that updates transmission rates on an annual basis and approved an ROE of 11.4%, effective as of January 1, 2008. The formula rate is designed to recover the expected revenue requirement for each calendar year and is updated based on actual costs. The FERC-approved formula method, which is based on projectednet periodic benefit costs ~~allows Virginia Power to earn a current return on its growing investment in electric transmission infrastructure.~~

In March 2010, Old Dominion Electric Cooperative and North Carolina Electric Membership Corporation filed a complaint with FERC against Virginia Power claiming, among other issues, that the incremental costs of undergrounding certain transmission line projects were unjust, unreasonable and unduly discriminatory or preferential and should be excluded from Virginia Power’s transmission formula rate. A settlement of the other issues raised in the complaint was approved by FERC in May 2012.

In March 2014, FERC issued an order excluding from Virginia Power’s transmission rates for wholesale transmission customers located outside Virginia the incremental costs of undergrounding certain transmission line projects. FERC found it is not just and reasonable for non-Virginia wholesale transmission customers to be allocated the incremental costs of undergrounding the facilities because the projects are a direct result of Virginia legislation and Virginia Commission pilot programs intended to benefit the citizens of Virginia. The order is retroactively effective as of March 2010 and will cause the reallocation of the costs charged to wholesale transmission customers with loads outside Virginia to wholesale transmission customers with loads in Virginia. FERC determined that there was not sufficient evidence on the record to determine the magnitude of the underground increment and held a hearing to determine the appropriate amount of undergrounding cost to be allocated to each wholesale transmission customer in Virginia.

In October 2017, FERC issued an order determining the calculation of the incremental costs of undergrounding the transmission projects and affirming that the costs are to be recovered from the wholesale transmission customers with loads located in Virginia. FERC directed Virginia Power to rebill all wholesale transmission customers retroactively to March 2010 within 30 days of when the proceeding becomes final and no longer subject to rehearing. Parties have until November 2017 to seek rehearing. Virginia Power is evaluating the order, which is not expected to have a material effect on results of operations.

~~PJM Transmission Rates~~

In April 2007, FERC issued an order regarding its transmission rate design for the allocation of costs among PJM transmission customers, including Virginia Power, for transmission service provided by PJM. For new PJM-planned transmission facilities that operate at or above 500 kV, FERC established a PJM regional rate design where customers pay according to each customer’s share of the region’s load. For recovery of costs of existing facilities, FERC approved the existing methodology whereby a customer pays the cost of facilities located in the same zone as the customer. A number of parties appealed the order to the U.S. Court of Appeals for the Seventh Circuit.

In August 2009, the court issued its decision affirming the FERC order with regard to the existing facilities, but remanded to FERC the issue of the cost allocation associated with the new facilities 500 kV and above for further consideration by FERC. On remand, FERC reaffirmed its earlier decision to allocate the costs of new facilities 500 kV and above according to the customer’s share of the region’s load. A number of parties filed appeals of the order to the U.S. Court of Appeals for the Seventh Circuit. In June 2014, the court again remanded the cost allocation issue to FERC. In December 2014, FERC issued an order setting an evidentiary hearing and settlement proceeding regarding the cost allocation issue. The hearing only concerns the costs of new facilities approved by PJM prior to February 1, 2013. Transmission facilities approved after February 1, 2013 are allocated on a hybrid cost allocation method approved by FERC and not subject to any court review.

In June 2016, PJM, the PJM transmission owners and state commissions representing substantially all of the load in the PJM market submitted a settlement to FERC to resolve the outstanding issues regarding this matter. Under the terms of the settlement, Virginia Power would be required to pay in excess of $200 million to PJM over the next 10 years. Although the settlement agreement has not been accepted by FERC, and the settlement is opposed by a small group of parties to the proceeding, Virginia Power believes it is probable it will be required to make payment as an outcome of the settlement. Accordingly, as of September 30, 2017, Virginia Power has recorded a contingent liability of $223 million in other deferred credits and other liabilities, which is offset by a $215 million regulatory asset for the amount that will be ~~recovered through retail~~included in regulated rates. Net periodic benefit costs not included in regulated rates are included in ~~Virginia.~~

~~FERC –~~accumulated other comprehensive loss, net. As of March 31, 2023 and December 31, 2022, Eastern Energy Gas' amount due to MidAmerican Energy associated with these plans and reflected in other long-term liabilities on the Consolidated Balance Sheets was $51 million.

(7) Fair Value Measurements

The carrying value of Eastern Energy Gas' cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. Eastern Energy Gas

~~DETI~~

~~In July 2017, FERC audit staff communicated~~ 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 ~~DETI~~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 ~~it had substantially completed~~Eastern Energy Gas 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 Eastern Energy Gas' judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. Eastern Energy Gas develops these inputs based on the best information available, including its own data.

155

The following table presents Eastern Energy Gas' 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		Total
As of March 31, 2023:
Assets:


Money market mutual funds	$	95	$	—	$	—	$	95
Equity securities:
Investment funds	17		—		—		17
	$	112	$	—	$	—	$	112

Liabilities:

Foreign currency exchange rate derivatives	$	—	$	(20)	$	—	$	(20)

	$	—	$	(20)	$	—	$	(20)

As of December 31, 2022:
Assets:
Commodity derivatives	$	—	$	1	$	—	$	1
Money market mutual funds	42		—		—		42
Equity securities:
Investment funds	14		—		—		14
	$	56	$	1	$	—	$	57

Liabilities:

Foreign currency exchange rate derivatives	$	—	$	(20)	$	—	$	(20)

	$	—	$	(20)	$	—	$	(20)

Eastern Energy Gas' investments in money market mutual funds and investment funds are stated at fair value. When available, a readily observable quoted market price or net asset value of an ~~audit~~identical security in an active market is used to record the fair value.

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 purchase or normal sales and qualify for the exception afforded by GAAP. When available, the fair value of ~~DETI’s compliance~~derivative contracts is estimated using unadjusted quoted prices for identical contracts in the market in which Eastern Energy Gas transacts. When quoted prices for identical contracts are not available, Eastern Energy Gas uses forward price curves. Forward price curves represent Eastern Energy Gas' estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. Eastern Energy Gas 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 Eastern Energy Gas. Market price quotations are generally readily obtainable for the ~~accounting~~applicable term of Eastern Energy Gas' outstanding derivative contracts; therefore, Eastern Energy Gas' forward price curves reflect observable market quotes. Market price quotations for certain natural gas trading hubs are not as readily obtainable due to the length of the contracts. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, Eastern Energy Gas 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 ~~reporting requirements~~duration of ~~FERC’s Uniform System~~contracts.

156

Eastern Energy Gas' long-term debt is carried at cost on the Consolidated Financial Statements. The fair value of ~~Accounts~~Eastern Energy Gas' long-term debt is a Level 2 fair value measurement and ~~provided a description~~has been estimated based upon quoted market prices, where available, or at the present value of ~~matters~~future cash flows discounted at rates consistent with comparable maturities with similar credit risks. The carrying value of Eastern Energy Gas' 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 ~~preliminary recommendations~~estimated fair value of Eastern Energy Gas' long-term debt (in millions):


	As of March 31, 2023				As of December 31, 2022
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value

Long-term debt	$	3,897	$	3,604	$	3,892	$	3,510

(8) Commitments and Contingencies

Environmental Laws and Regulations

Legal Matters

Eastern Energy Gas is party to ~~Dominion~~a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. Eastern Energy Gas does not believe that such normal and ~~Dominion~~routine litigation will have a material impact on its consolidated financial results.

(9) Revenue from Contracts with Customers

The following table summarizes Eastern Energy ~~Gas’~~Gas' revenue from contracts with customers ("Customer Revenue") by regulated and nonregulated, with further disaggregation of regulated by line of business (in millions):


	Three-Month Periods
	Ended March 31,
	2023		2022
Customer Revenue:
Regulated:
Gas transmission and storage	$	332	$	285

Other	2		—
Total regulated	334		285




Nonregulated	217		203
Total Customer Revenue	551		488
Other revenue(1)	2		(6)
Total operating revenue	$	553	$	482

(1)Other revenue consists primarily of revenue recognized in accordance with Accounting Standards Codification 815, "Derivative and Hedging" and includes unrealized gains and losses for derivatives not designated as hedges related to natural gas sales contracts.

Eastern Energy Gas has recognized contract liabilities of $70 million and $80 million as of March 31, 2023 and December 31, 2022, respectively, due to the relationship between Eastern Energy Gas' performance and the customer's payment. Eastern Energy Gas recognizes revenue as it fulfills its obligations to provide services to its customers. During the three-month period ended March 31, 2023, Eastern Energy Gas recognized revenue of $22 million from the beginning contract liability balance.

157

Remaining Performance Obligations

The following table summarizes Eastern Energy Gas' 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, 2023 (in millions):


	Performance obligations expected to be satisfied
	Less than 12 months		More than 12 months		Total

Eastern Energy Gas	$	1,657	$	15,340	$	16,997

(10) Components of Accumulated Other Comprehensive Loss, Net

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


	Unrecognized						Accumulated
	Amounts On		Unrealized				Other
	Retirement		Losses on Cash		Noncontrolling		Comprehensive
	Benefits		Flow Hedges		Interests		Loss, Net

Balance, December 31, 2021	$	(6)	$	(42)	$	5	$	(43)
Other comprehensive income	1		4		—		5
Balance, March 31, 2022	$	(5)	$	(38)	$	5	$	(38)

Balance, December 31, 2022	$	(1)	$	(43)	$	2	$	(42)
Other comprehensive loss	(1)		(2)		—		(3)
Balance, March 31, 2023	$	(2)	$	(45)	$	2	$	(45)

158

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. DETI submitted its initial response~~operations of Eastern Energy Gas during the periods included herein. This discussion should be read in conjunction with Eastern Energy Gas' historical Consolidated Financial Statements and Notes to ~~the audit staff~~Consolidated Financial Statements in ~~September 2017. In connection with one preliminary recommendation that management did not challenge, DETI recognized~~Part I, Item 1 of this Form 10-Q. Eastern Energy Gas' actual results in the ~~second~~future could differ significantly from the historical results.

Results of Operations for the First Quarter of 2023 and 2022

Overview

Net income attributable to Eastern Energy Gas for the first quarter of ~~2017, a charge~~2023 was $122 million, an increase of ~~$15~~$28 million ~~($9~~compared to 2022. Net income increased primarily due to higher margin from EGTS' regulated gas transmission and storage operations of $32 million ~~after-tax) recorded within other~~and higher earnings from Iroquois due to favorable fixed negotiated rate agreements and hedges, partially offset by higher operations and maintenance ~~expense~~expenses.

Quarter Ended March 31, 2023 Compared to Quarter Ended March 31, 2022

Operating revenue increased $71 million, or 15%, for the first quarter of 2023 compared to 2022, primarily due to an increase in ~~Dominion Energy’s~~regulated gas transmission and ~~Dominion Energy Gas’ Consolidated Statements~~storage services revenues due to the settlement of ~~Income to write-off the balance~~EGTS' general rate case of $42 million, increased LNG revenues as a ~~regulatory asset, originally established in 2008, that is no longer considered probable of recovery. Pending final resolution~~result of the ~~audit process~~timing of the release of contract liabilities from scheduled outage days in 2022 of $19 million, an increase in variable revenue related to park and loan activity of $10 million and derivative losses in 2022 of $7 million, partially offset by a net decrease in regulated gas transmission and storage services revenues due to volumes primarily from the expiration of the Appalachian Gateway Project contracts in August 2022 of $6 million.

Cost of (excess) gas was an expense of $20 million for the first quarter of 2023 compared to a credit of $1 million for the first quarter of 2022. The change is primarily from the unfavorable revaluation of the volumes retained prior to the effective date of the new fuel tracker, due to lower natural gas prices.

Operations and maintenance increased $25 million, or 21%, for the first quarter of 2023 compared to 2022, primarily due to higher corporate charges of $10 million, an increase in salaries, wages and benefits of $6 million and an increase in Cove Point outside services of $4 million.

Depreciation and amortization decreased $5 million, or 6%, for the first quarter of 2023 compared to 2022, primarily due to the settlement of depreciation rates in EGTS' general rate case of $8 million, partially offset by higher plant placed in-service of $3 million.

Property and other taxes increased $8 million, or 28%, for the first quarter of 2023 compared to 2022, primarily due to lower 2021 tax assessments that were finalized in 2022.

Interest and dividend income increased $9 million for the first quarter of 2023 compared to 2022, primarily due to higher outstanding borrowings and higher interest rates from BHE GT&S' intercompany revolving credit agreement with Eastern Energy Gas.

Income tax expense increased $9 million, or 30%, for the first quarter of 2023 compared to 2022, primarily due to higher pre-tax income. The effective tax rate was 16% for 2023 and 14% for 2022.

Equity income increased $13 million, or 68%, for the first quarter of 2023 compared to 2022, primarily due to higher earnings from Iroquois due to favorable fixed negotiated rate agreements and hedges.

Net income attributable to noncontrolling interests increased $7 million, or 6%, for the first quarter of 2023 compared to 2022, primarily due to increased LNG revenues as a result of the timing of the release of contract liabilities from scheduled outage days in 2022, partially offset by an increase in Cove Point outside services.

159

Liquidity and Capital Resources

As of March 31, 2023, Eastern Energy Gas' total net liquidity was as follows (in millions):


Cash and cash equivalents	$	103

Intercompany revolving credit agreement	400





Total net liquidity	$	503

Intercompany revolving credit agreement:
Maturity date	2024

Operating Activities

Net cash flows from operating activities for the three-month periods ended March 31, 2023 and 2022 were $319 million and $341 million, respectively. The change is primarily due to the repayment of EGTS rate refunds to customers, partially offset by the impacts from the rate increase in effect April 1, 2022 for the EGTS general rate case and other changes in working capital.

The timing of Eastern Energy Gas' income tax cash flows from period to period can be significantly affected by the estimated federal income tax payment methods elected and assumptions made for each payment date.

Investing Activities

Net cash flows from investing activities for the three-month periods ended March 31, 2023 and 2022 were $(156) million and $(194) million, respectively. The change is primarily due to an increase in repayments of loans by affiliates of $37 million and a ~~determination~~decrease in capital expenditures of $16 million, partially offset by ~~FERC, management is unable~~an increase in loans to ~~estimate~~its parent under an intercompany revolving credit agreement of $17 million.

Financing Activities

Net cash flows from financing activities for the ~~potential impact~~three-month period ended March 31, 2023 were $(124) million and consisted of distributions to noncontrolling interests from Cove Point.

Net cash flows from financing activities for the three-month period ended March 31, 2022 were $(114) million and consisted of distributions to noncontrolling interests from Cove Point.

Future Uses of Cash

Eastern Energy Gas 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, intercompany revolving credit agreements, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, investments, debt retirements and other capital requirements. The availability and terms under which Eastern Energy Gas and each subsidiary has access to external financing depends on a variety of factors, including regulatory approvals, Eastern Energy Gas' credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the natural gas transmission and storage and LNG export, import and storage industries.

Capital Expenditures

Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other ~~preliminary recommendations~~factors, new growth projects and nothe timing of growth projects; changes in environmental and other rules and regulations; impacts to customer rates; outcomes of regulatory proceedings; changes in income tax laws; general business conditions; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital.

160

Eastern Energy Gas' historical and forecasted capital expenditures, each of which exclude amounts ~~have been recognized.~~

for non-cash equity AFUDC and other non-cash items, are as follows (in millions):


	Three-Month Periods				Annual
	Ended March 31,				Forecast
	2022		2023		2023

Natural gas transmission and storage	$	7	$	4	$	36
Other	68		55		390
Total	$	75	$	59	$	426

Natural gas transmission and storage primarily includes growth capital expenditures related to planned regulated projects. Other ~~Regulatory Matters~~

~~Other than the following matters,~~includes primarily nonregulated and routine capital expenditures for natural gas transmission, storage and LNG terminalling infrastructure needed to serve existing and expected demand.

Material Cash Requirements

As of March 31, 2023, there have been no ~~significant developments regarding~~material changes in cash requirements from the ~~pending regulatory matters disclosed~~information provided in ~~Note 13 to the Consolidated Financial Statements in the Companies’~~Item 7 of Eastern Energy Gas' Annual Report on Form 10-K for the year ended December 31, ~~2016~~2022.

Regulatory Matters

Eastern Energy Gas is subject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for discussion regarding Eastern Energy Gas' current regulatory matters.

Environmental Laws and ~~Note 12~~Regulations

Eastern Energy Gas is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions performance standards, water quality and other environmental matters that have the potential to impact its 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 and local agencies. Eastern Energy Gas believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and Eastern Energy Gas is unable to predict the impact of the changing laws and regulations on its operations and financial results.

Refer to "Environmental Laws and Regulations" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for additional information regarding environmental laws and regulations.

Critical Accounting Estimates

~~Virginia Regulation~~

~~Regulation Act Legislation~~

The Supreme Court of Virginia previously granted appeals to certain industrial customers of Appalachian Power Company that challenged the constitutionality of legislation enacted in 2015 keeping Appalachian Power Company’s base rates unchanged until at least 2020. This legislation also keeps Virginia Power’s base rates unchanged until at least 2022. In September 2017, the Supreme Court of Virginia affirmed that the legislation is constitutional.

~~Rate Adjustment Clauses~~

~~Below is a~~long-lived assets and income taxes. For additional discussion of ~~significant riders associated with various Virginia Power projects:~~

~~Virginia Power previously filed an application with the Virginia Commission to recover through Rider U costs for the first and second phases~~Eastern Energy Gas' critical accounting estimates, see Item 7 of a program to underground outage-prone overhead distribution lines. In September 2017, the Virginia Commission approved a total $22 million annual revenue requirement effective October 1, 2017, using a 9.4% ROE, and a total capital investment of $40 million for second phase conversions.

The Virginia Commission previously approved Riders C1A and C2A in connection with cost recovery for DSM programs. In October 2017, Virginia Power requested approval to extend one existing energy efficiency program for five years with a new $25 million cost cap, and proposed a total $31 million revenue requirement for the rate year beginning July 1, 2018, which represents a $3 million increase over the previous year. This case is pending.

The Virginia Commission previously approved Rider BW in conjunction with Brunswick County. In October 2017, Virginia Power proposed a $132 million revenue requirement for the rate year beginning September 1, 2018, which represents a $5 million increase over the previous year. This case is pending.

The Virginia Commission previously approved Rider US-2 in conjunction with the Scott Solar, Whitehouse, and Woodland solar facilities. In October 2017, Virginia Power proposed a $15 million revenue requirement for the rate year beginning September 1, 2018, which represents a $5 million increase over the previous year. This case is pending.

~~Electric Transmission Projects~~

Virginia Power previously filed an application with the Virginia Commission for a CPCN to rebuild and rearrange its Idylwood substation in Fairfax County, Virginia. In September 2017, the Virginia Commission granted a CPCN for the project. The total estimated cost of the project is approximately $110 million.

Virginia Power previously filed an application with the Virginia Commission for a CPCN to construct and operate in multiple Virginia counties an approximately 38-mile overhead 230 kV transmission line between the Remington and Gordonsville substations, along with associated facilities. In August 2017, the Virginia Commission granted a CPCN for the project. The total estimated cost of the project is approximately $105 million.

In November 2013, the Virginia Commission issued an order granting Virginia Power a CPCN to construct approximately 7 miles of new overhead 500 kV transmission line from the existing Surry switching station in Surry County to a new Skiffes Creek switching station in James City County, and approximately 20 miles of new 230 kV transmission line in James City County, York County, and the City of Newport News from the proposed new Skiffes Creek switching station to Virginia Power’s existing Whealton substation in the City of Hampton. As of July 2017, Virginia Power has received all major required permits and approvals and is proceeding with construction of the project. In connection with the receipt of the permit from the U.S. Army Corps of Engineers in July 2017, Virginia Power was required to make payments totaling approximately $90 million to fund improvements to historical and cultural resources near the project. Accordingly, in July 2017, Virginia Power recorded an increase to property, plant and equipment and a corresponding liability for these payment obligations. Through September 30, 2017, Virginia Power had made $70 million of such payments, with the remaining $20 million paid in October 2017. Also in July 2017, the National Parks Conservation Association filed a lawsuit in U.S. District Court for the D.C. Circuit seeking to set aside the permit granted by the U.S. Army Corps of Engineers for the project and requested a preliminary injunction against the permit. In August 2017, the National Trust for Historic Preservation and Preservation Virginia filed a similar lawsuit in U.S. District Court for the D.C. Circuit. In October 2017, the preliminary injunction requests were denied. These lawsuits are pending.

~~North Carolina Regulation~~

In August 2017, Virginia Power submitted its annual filing to the North Carolina Utilities Commission to adjust the fuel component of its electric rates. Virginia Power proposed a total $15 million increase to the fuel component of its electric rates for the rate year beginning January 1, 2018. This case is pending.

~~Ohio Regulation~~

~~UEX Rider~~

East Ohio has approval for a UEX Rider through which it recovers the bad debt expense of most customers not participating in the PIPP Plus Program. The UEX Rider is adjusted annually to achieve dollar for dollar recovery of East Ohio’s actual write-offs of uncollectible amounts. In September 2017, the Ohio Commission approved East Ohio’s application requesting approval of its UEX Rider to reflect a refund of over-recovered accumulated bad debt expense of approximately $12 million as of March 31, 2017, and recovery of prospective net bad debt expense projected to total approximately $22 million for the twelve-month period from April 2017 to March 2018.

~~Utah and Wyoming Regulation~~

In October 2017, Questar Gas submitted filings with both the Public Service Commission of Utah and the Wyoming Public Service Commission for an approximately $25 million gas cost increase reflecting forecasted increases in commodity and transportation costs. The Public Service Commission of Utah and the Wyoming Public Service Commission both approved the filings in October 2017 with rates effective November 2017.

~~West Virginia Regulation~~

In October 2017, the Public Service Commission of West Virginia approved Hope’s application for new PREP customer rates, for the year beginning November 1, 2017, that provide for projected revenue of $4 million related to capital investments of $21 million, $27 million and $31 million for 2016, 2017 and 2018, respectively.

~~FERC – Gas~~

~~DETI~~

In December 2014, DETI entered into a precedent agreement with Atlantic Coast Pipeline for the Supply Header Project, a project to provide approximately 1,500,000 Dths per day of firm transportation service to various customers. This project is expected to be placed into service in late 2019 and cost approximately $550 million to $600 million to construct, excluding financing costs. In October 2017, DETI received FERC authorization to construct and operate the project facilities.

In September 2017, DETI submitted its annual transportation cost rate adjustment to FERC requesting approval to recover $39 million. Also in September 2017, DETI submitted its annual electric power cost adjustment to FERC requesting approval to recover $6 million. In October 2017, FERC approved these adjustments.

~~Cove Point~~

In November 2016, pursuant to the terms of a previous settlement, Cove Point filed a general rate case for its FERC-jurisdictional services, with 23 proposed rates to be effective January 1, 2017. Cove Point proposed an annual cost-of-service of approximately $140 million. In December 2016, FERC accepted a January 1, 2017 effective date for all proposed rates but five which were suspended to be effective June 1, 2017. In August 2017, Cove Point filed a proposed stipulation and settlement agreement with FERC, which was supported or not opposed by the active parties. Under the terms of the settlement agreement, Cove Point’s rates effective October 2017 would result in decreases to annual revenues and depreciation expense of approximately $18 million and $3 million, respectively, compared to the rates in effect through December 2016. In September 2017, the Presiding Administrative Law Judge certified the uncontested settlement to FERC. Cove Point is awaiting final FERC approval of the settlement. This case is pending.

~~Note 13. Variable Interest Entities~~

~~There have been no significant changes regarding the entities the Companies consider VIEs as described in Note 15 to the Consolidated Financial Statements in the Companies'~~Eastern Energy Gas' Annual Report on Form 10-K for the year ended December 31, ~~2016.~~

~~Dominion~~2022. There have been no significant changes in Eastern Energy

~~Dominion Energy’s~~ Gas' assumptions regarding critical accounting estimates since December 31, 2022.

161

Eastern Gas Transmission and Storage, Inc. and its subsidiaries

Consolidated Financial Section

162

PART I

Item 1.Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of

Eastern Gas Transmission and Storage, Inc.

Results of Review of Interim Financial Information

We have reviewed the accompanying consolidated balance sheet of Eastern Gas Transmission and Storage, Inc. and subsidiaries ("EGTS") as of March 31, 2023, the related consolidated statements of operations, comprehensive income, changes in shareholder's equity and cash flows for the three-month periods ended March 31, 2023 and 2022, and the related notes (collectively referred to as the "interim financial information"). Based on our reviews, we are not aware of any material modifications that should be made to the accompanying interim financial information for it to be in conformity with accounting principles generally accepted in the United States of America.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of EGTS as of December 31, 2022 and the related consolidated statements of operations, comprehensive income (loss), changes in equity, and cash flows for the year then ended (not presented herein); and in our report dated February 24, 2023 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, 2022, is fairly stated, in all material respects, in relation to the consolidated balance sheet from which it has been derived.

Basis for Review Results

This interim financial information is the responsibility of EGTS' management. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to EGTS in accordance with the U.S. federal securities ~~due within one year~~laws and ~~long-term debt include $29 million~~the applicable rules and ~~$356 million, respectively,~~regulations of ~~debt issued~~the Securities and Exchange Commission and the PCAOB.

We conducted our reviews in ~~2016 by SBL Holdco,~~accordance with standards of the PCAOB. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the PCAOB, the objective of which is the expression of an opinion regarding the financial statements taken as a ~~VIE, net of issuance costs that is nonrecourse to Dominion Energy and is secured by SBL Holdco’s interest~~whole. Accordingly, we do not express such an opinion.

/s/ Deloitte & Touche LLP

Richmond, Virginia

May 5, 2023

163

EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited)

(Amounts in ~~certain merchant solar facilities.~~

millions)


	As of
	March 31,		December 31,
	2023		2022
ASSETS
Current assets:
Cash and cash equivalents	$	46	$	16
Restricted cash and cash equivalents	29		29
Trade receivables, net	84		113
Receivables from affiliates	13		13

Inventories	51		50

Prepayments and other deferred charges	34		36
Natural gas imbalances	62		193
Other current assets	12		30
Total current assets	331		480

Property, plant and equipment, net	4,604		4,504



Other assets	185		190

Total assets	$	5,120	$	5,174

~~Virginia Power~~

~~Virginia Power had long-term power and capacity contracts with three non-utility generators. Contracts with two~~

The accompanying notes are an integral part of these ~~non-utility generators expired during~~consolidated financial statements.

164

EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (Unaudited) (continued)

(Amounts in millions, except share data)


	As of
	March 31, 2023		December 31, 2022
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	30	$	46
Accounts payable to affiliates	5		5
Accrued interest	23		7
Accrued property, income and other taxes	59		71
Accrued employee expenses	19		13
Notes payable to affiliates	13		36
Regulatory liabilities	21		109
Customer and security deposits	29		29
Asset retirement obligations	22		25
Other current liabilities	31		32
Total current liabilities	252		373

Long-term debt	1,582		1,582
Regulatory liabilities	517		518
Other long-term liabilities	102		101
Total liabilities	2,453		2,574

Commitments and contingencies (Note 8)

Shareholder's equity:
Common stock - 75,000 shares authorized, $10,000 par value, 60,101 issued and outstanding	609		609
Additional paid-in capital	1,282		1,275
Retained earnings	805		746
Accumulated other comprehensive loss, net	(29)		(30)
Total shareholder's equity	2,667		2,600

Total liabilities and shareholder's equity	$	5,120	$	5,174

The accompanying notes are an integral part of these consolidated financial statements.

165

EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(Amounts in millions)


	Three-Month Periods
	Ended March 31,
	2023		2022

Operating revenue	$	278	$	223

Operating expenses:
Cost of (excess) gas	20		(3)
Operations and maintenance	99		84
Depreciation and amortization	37		43
Property and other taxes	14		9

Total operating expenses	170		133

Operating income	108		90

Other income (expense):
Interest expense	(18)		(17)

Allowance for equity funds	1		1


Total other income (expense)	(17)		(16)

Income before income tax expense (benefit)	91		74
Income tax expense (benefit)	23		19
Net income	$	68	$	55

The accompanying notes are an integral part of these consolidated financial statements.

166

EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)

(Amounts in millions)


	Three-Month Periods
	Ended March 31,
	2023		2022

Net income	$	68	$	55

Other comprehensive income, net of tax:
Unrealized gains on cash flow hedges, net of tax of $— and $—	1		1

Total other comprehensive income, net of tax	1		1
Comprehensive income	$	69	$	56

The accompanying notes are an integral part of these consolidated financial statements.

167

EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY (Unaudited)

(Amounts in millions, except shares)


								Accumulated
				Additional				Other		Total
	Common Stock			Paid-in		Retained		Comprehensive		Shareholder's
	Shares	Amount		Capital		Earnings		Loss, Net		Equity

Balance, December 31, 2021	60,101	$	609	$	1,241	$	721	$	(31)	$	2,540
Net income	—	—		—		55		—		55
Other comprehensive income	—	—		—		—		1		1



Balance, March 31, 2022	60,101	$	609	$	1,241	$	776	$	(30)	$	2,596

Balance, December 31, 2022	60,101	$	609	$	1,275	$	746	$	(30)	$	2,600
Net income	—	—		—		68		—		68
Other comprehensive income	—	—		—		—		1		1
Dividends declared	—	—		—		(9)		—		(9)
Contributions	—	—		7		—		—		7

Balance, March 31, 2023	60,101	$	609	$	1,282	$	805	$	(29)	$	2,667

The accompanying notes are an integral part of these consolidated financial statements.

168

EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(Amounts in millions)


	Three-Month Periods
	Ended March 31,
	2023		2022
Cash flows from operating activities:
Net income	$	68	55
Adjustments to reconcile net income to net cash flows from operating activities:


Depreciation and amortization	37		43
Allowance for equity funds	(1)		(1)

Changes in regulatory assets and liabilities	(85)		(6)
Deferred income taxes	8		13
Other, net	1		3
Changes in other operating assets and liabilities:
Trade receivables and other assets	42		37
Receivables from affiliates	—		(9)
Gas balancing activities	17		(1)

Accrued property, income and other taxes	(15)		(18)
Accounts payable and other liabilities	21		20
Accounts payable to affiliates	—		(8)
Net cash flows from operating activities	93		128

Cash flows from investing activities:
Capital expenditures	(37)		(53)




Other, net	(3)		(3)
Net cash flows from investing activities	(40)		(56)

Cash flows from financing activities:



Repayment of notes payable to affiliates, net	(23)		(68)






Net cash flows from financing activities	(23)		(68)



Net change in cash and cash equivalents and restricted cash and cash equivalents	30		4
Cash and cash equivalents and restricted cash and cash equivalents at beginning of period	45		26
Cash and cash equivalents and restricted cash and cash equivalents at end of period	$	75	$	30

The accompanying notes are an integral part of these consolidated financial statements.

169

EASTERN GAS TRANSMISSION AND STORAGE, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) General

Eastern Gas Transmission and Storage, Inc. and its subsidiaries ("EGTS") conduct business activities consisting of Federal Energy Regulatory Commission ("FERC")-regulated interstate natural gas transmission systems and underground storage. EGTS' operations include transmission assets located in Maryland, New York, Ohio, Pennsylvania, Virginia and West Virginia. EGTS also operates one of the ~~third quarter~~nation's largest underground natural gas storage systems located in New York, Pennsylvania and West Virginia. EGTS is a wholly owned subsidiary of ~~2017 leaving~~Eastern Energy Gas Holdings, LLC ("Eastern Energy Gas"), which is an indirect wholly owned subsidiary of Berkshire Hathaway Energy Company ("BHE"). BHE is a ~~remaining aggregate summer generation capacity~~holding company based in Des Moines, Iowa that owns subsidiaries principally engaged in the energy industry. BHE is a consolidated subsidiary of ~~approximately 218 MW. Virginia Power is~~Berkshire Hathaway Inc.

The unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and the United States Securities and Exchange Commission's rules and regulations for Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not ~~subject to any risk~~include all of ~~loss from this remaining potential VIE other than its remaining purchase commitments which totaled $213 million~~the disclosures required by GAAP for annual financial statements. Management believes the unaudited Consolidated Financial Statements contain all adjustments (consisting only of normal recurring adjustments) considered necessary for the fair presentation of the unaudited Consolidated Financial Statements as of ~~September 30, 2017. Virginia Power paid $17 million~~March 31, 2023 and ~~$37 million for electric capacity and $5 million and $11 million for electric energy to these entities~~ for the ~~three months~~three-month periods ended ~~September 30, 2017~~March 31, 2023 and 2016, respectively. Virginia Power paid $73 million and $111 million for electric capacity and $20 million and $23 million for electric energy to these entities for the nine months ended September 30, 2017 and 2016, respectively.

~~Virginia Power and Dominion Energy Gas~~

Virginia Power and Dominion Energy Gas purchased shared services from DES, an affiliated VIE, of $83 million and $31 million for the three months ended September 30, 2017, $80 million and $31 million for the three months ended September 30, 2016, $251 million and $93 million for the nine months ended September 30, 2017 and $268 million and $95 million for the nine months ended September 30, 2016, respectively.

~~Note 14. Significant Financing Transactions~~

~~Credit Facilities and Short-term Debt~~

2022. 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 September 30, 2017, Dominion Energy’s commercial paper and letters of credit outstanding, as well as its capacity available under credit facilities, were as follows:~~

Facility
Limit

Outstanding
Commercial
Paper

Outstanding
Letters of
Credit

Facility
Capacity
Available

(millions)

Joint revolving credit facility⁽¹⁾

$
5,000

$
3,060

$
—

$
1,940

Joint revolving credit facility⁽¹⁾

500

—

73

427

Total

$
5,500

$
3,060

$
73

$
2,367

~~(1)~~

These credit facilities mature in April 2020 and can be used by the Companies 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.

Questar Gas’ short-term financing is supported through its access as co-borrower to the two joint revolving credit facilities discussed above with Dominion Energy, Virginia Power and Dominion Energy Gas. At September 30, 2017 the aggregate sub-limit for Questar Gas was $250 million.

In addition to the credit facilities mentioned above, SBL Holdco has $30 million of credit facilities which have a 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 have a 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 September 30, 2017, no amounts were outstanding under either of these facilities.

~~Virginia Power~~

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

At September 30, 2017, Virginia Power’s share of commercial paper and letters of credit outstanding under its joint credit facilities with Dominion Energy, Dominion Energy Gas and Questar Gas were as follows:

Facility
Limit⁽¹⁾

Outstanding
Commercial
Paper

Outstanding
Letters of
Credit

(millions)

Joint revolving credit facility⁽¹⁾

$
5,000

$
320

$
—

Joint revolving credit facility⁽¹⁾

500

—

1

Total

$
5,500

$
320

$
1

~~(1)~~

The full amount of the facilities is available to Virginia Power, less any amounts outstanding to co-borrowers Dominion Energy, Dominion Energy Gas and Questar Gas. Sub-limits for Virginia Power are set within the facility limit but can be changed at the option of the Companies multiple times per year. In May 2017, the aggregate sub-limit for Virginia Power was decreased from $2.0 billion to $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. These credit facilities mature in April 2020 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.

In addition to the credit facility commitments mentioned above, Virginia Power also has a $100 million credit facility with a maturity date of April 2020. At September 30, 2017, this facility supports $100 million of certain variable rate tax-exempt financings of Virginia Power.

~~Dominion Energy Gas~~

Dominion Energy Gas’ short-term financing is supported by its access as co-borrower to the two joint revolving credit facilities. These credit facilities can be used for working capital, as support for the combined commercial paper programs of the Companies and for other general corporate purposes.

At September 30, 2017, Dominion Energy Gas' share of commercial paper and letters of credit outstanding under its joint credit facilities with Dominion Energy, Virginia Power and Questar Gas were as follows:

Facility
Limit⁽¹⁾

Outstanding
Commercial
Paper

Outstanding
Letters of
Credit

(millions)

Joint revolving credit facility⁽¹⁾

$
1,000

$
620

$
—

Joint revolving credit facility⁽¹⁾

500

—

—

Total

$
1,500

$
620

$
—

~~(1)~~

A maximum of a combined $1.5 billion of the facilities is available to Dominion Energy Gas, assuming adequate capacity is available after giving effect to uses by co-borrowers Dominion Energy, Virginia Power and Questar Gas. Sub-limits for Dominion Energy Gas are set within the facility limit but can be changed at the option of the Companies multiple times per year. In May 2017, the aggregate sub-limit for Dominion Energy Gas was increased from $500 million to $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. These credit facilities mature in April 2020 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~~

~~In January 2017, Dominion Energy issued $400 million of 1.875% senior notes and $400 million of 2.75% senior notes that mature in 2019 and 2022, respectively.~~

In March 2017, Dominion Energy issued through private placement $300 million of 3.496% senior notes that mature in 2024. Also in March 2017, Dominion Energy issued an additional $100 million of its 3.90% senior notes that mature in 2025.

~~In March 2017, Virginia Power issued $750 million of 3.50% senior notes that mature in 2027.~~

In May 2017, Dominion Solar Projects III, Inc. borrowed $280 million under a term loan agreement that bears interest at a variable rate. The term loan amortizes over an 18-year period and matures in May 2024. The debt is nonrecourse to Dominion Energy and is secured by Dominion Solar Projects III, Inc.’s interest in certain solar facilities.

~~In June 2017, Dominion Energy issued through private placement $500 million of variable rate senior notes that mature in 2019.~~

In August 2017, Dominion Energy retired its $75 million variable rate Massachusetts Development Finance Agency Solid Waste Disposal Revenue Bonds, Series 2010B that would otherwise have matured in December 2041.

In September 2017, Virginia Power issued $550 million of 3.80% senior notes that mature in 2047. Also in September 2017, Virginia Power issued an additional $200 million of its 2.75% senior notes that mature in 2023.

In October 2017, Questar Gas entered into an agreement with certain investors to issue through private placements in November 2017, $100 million of 3.38% 15-year senior notes and, in April 2018, $50 million of 3.30% 12-year senior notes and $100 million of 3.97% 30-year senior notes.

~~Remarketable Subordinated Notes~~

In May 2017, Dominion Energy successfully remarketed the $1.0 billion 2014 Series A 1.50% RSNs due in 2020 pursuant to the terms of the 2014 Equity Units. In connection with the remarketing, the interest rate on the junior subordinated notes was reset to 2.579%, payable on a semi-annual basis and Dominion Energy ceased to have the ability to redeem the notes at its option or defer interest payments. At September 30, 2017, these securities are included in junior subordinated notes in Dominion Energy’s Consolidated Balance Sheets. Dominion Energy did not receive any proceeds from the remarketing. Remarketing proceeds belonged to the investors holding the related 2014 Equity Units and were temporarily used to purchase a portfolio of treasury securities. Upon maturity of the portfolio, the proceeds were applied on behalf of investors on the related stock purchase contracts settlement date in July 2017 to pay the purchase price to Dominion Energy for the issuance of 12.5 million shares of its common stock related to Dominion Energy’s 2014 Equity Units.

~~Issuance of Common Stock~~

In June 2017, Dominion Energy filed an SEC shelf registration for the sale of debt and equity securities including the ability to sell common stock through an at-the-market program. Also in June 2017, Dominion Energy entered into three separate sales agency agreements to effect sales under the program and pursuant to which it may offer from time to time up to $500 million aggregate amount of its common stock. Sales of common stock can be made by means of privately negotiated transactions, as transactions on the New York Stock Exchange at market prices or in such other transactions as are agreed upon by Dominion Energy and the sales agents in conformance with applicable securities laws. No issuances have occurred under these agreements in 2017.

~~In July 2017, Dominion Energy issued 12.5 million shares under the related stock purchase contracts entered into as part of Dominion Energy’s 2014 Equity Units.~~

~~Note 15. Commitments and Contingencies~~

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 subject to governmental examinations (including by regulatory authorities), inquiries and investigations. Certain legal proceedings and governmental examinations involve demands for unspecified amounts of damages, are in an initial procedural phase, involve uncertainty as to the outcome of pending appeals or motions, or involve significant factual issues that need to be resolved, such that it is not possible for the Companies to estimate a range of possible loss. For such matters for which the Companies cannot estimate a range of possible loss, a statement to this effect is made in the description of the matter. Other matters may have progressed sufficiently through the litigation or investigative processes such that the Companies are able to estimate a range of possible loss. For legal proceedings and governmental examinations for which 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 accrued liability is recorded on a gross basis with a receivable also recorded for any probable insurance recoveries. Estimated ranges of loss are inclusive of legal fees and net of any anticipated insurance recoveries. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the Companies' maximum possible loss exposure. The circumstances of such legal proceedings and governmental examinations will change from time to time and actual results may vary significantly from the current estimate. For current proceedings not specifically reported below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial position, liquidity or results of operations for the three-month period ended March 31, 2023 are not necessarily indicative of the ~~Companies.~~

~~Environmental Matters~~

results to be expected for the full year.

The ~~Companies are subject~~preparation of the unaudited Consolidated Financial Statements in conformity with GAAP requires management to ~~costs resulting from a number~~make estimates and assumptions that affect the reported amounts of ~~federal, state~~assets and ~~local laws and regulations designed to protect human health~~liabilities at the date of the unaudited Consolidated Financial Statements and the ~~environment. These laws~~reported amounts of revenue 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.

~~Air~~

~~CAA~~

The CAA, as amended, is a comprehensive program utilizing a broad range of regulatory tools to protect and preserve the nation's air quality. At a minimum, states are required to establish regulatory programs to address all requirements of the CAA. However, states may choose to develop regulatory programs that are more restrictive. Many of the Companies' facilities are subject to the CAA's permitting and other requirements.

~~MATS~~

In December 2011, the EPA issued MATS for coal- and oil-fired electric utility steam generating units. The rule establishes strict emission limits for mercury, particulate matter as a surrogate for toxic metals and hydrogen chloride as a surrogate for acid gases. The rule includes a limited use provision for oil-fired units with annual capacity factors under 8% that provides an exemption from emission limits, and allows compliance with operational work practice standards. Compliance was required by April 16, 2015, with certain limited exceptions. However, in June 2014, the VDEQ granted a one-year MATS compliance extension for two coal-fired units at Yorktown power station to defer planned retirements and allow for continued operation of the units to address reliability concerns while necessary electric transmission upgrades are being completed. These coal units needed to continue operating through at least April 2017 due to delays in transmission upgrades needed to maintain electric reliability. Therefore, in October 2015, Virginia Power submitted a request to the EPA for an additional one year compliance extension under an EPA Administrative Order. The order was signed by the EPA in April 2016 allowing the Yorktown power station units to operate for up to one additional year, as required to maintain reliable power availability while transmission upgrades are being made. Virginia Power ceased operating the coal units at Yorktown power station in April 2017 as planned.

In June 2017, the U.S. DOE issued an order to PJM to direct Virginia Power to operate Yorktown power station’s Units 1 and 2 as needed to avoid reliability issues on the Virginia Peninsula. The order was effective for 90 days and can be reissued upon PJM’s request, if necessary, until required electricity transmission upgrades are completed approximately 23 months following the receipt in July 2017 of final permits and approvals for construction. In July 2017, the Sierra Club filed a petition for rehearing of the U.S. DOE order, which was denied by the U.S. DOE in September 2017. In August 2017, PJM filed a request for a 90-day renewal of the U.S. DOE order, which the U.S. DOE subsequently granted in September 2017. In October 2017, the Sierra Club filed a petition for rehearing of the U.S. DOE order granted in September 2017. This matter is pending.

In June 2015, the U.S. Supreme Court issued a decision holding that the EPA failed to take cost into account when the agency first decided to regulate the emissions from coal- and oil-fired plants, and remanded the MATS rule back to the U.S. Court of Appeals for the D.C. Circuit. However, the Supreme Court did not vacate or stay the effective date and implementation of the MATS rule. In November 2015, in response to the Supreme Court decision, the EPA proposed a supplemental finding that consideration of cost does not alter the agency’s previous conclusion that it is appropriate and necessary to regulate coal- and oil-fired electric utility steam generating units under Section 112 of the CAA. In December 2015, the U.S. Court of Appeals for the D.C. Circuit issued an order remanding the MATS rulemaking proceeding back to the EPA without setting aside judgment, noting that EPA had represented it was on track to issue a final finding regarding its consideration of cost. In April 2016, the EPA issued a final supplemental finding that consideration of costs does not alter its conclusion regarding appropriateness and necessity for the regulation. This regulation has been challenged in court. In April 2017, the EPA requested that the U.S. Court of Appeals for the D.C. Circuit delay oral arguments in the case to allow agency review of the rule. Since the MATS rule remains in effect and Dominion Energy is complying with the applicable requirements of the rule, Dominion Energy does not expect any adverse impacts to its operations at this time.

~~Ozone Standards~~

~~In October 2015, the EPA issued a final rule tightening the ozone standard from 75-ppb to 70-ppb. To comply with this standard, in April 2016 Virginia Power submitted the NO~~_X ~~Reasonable Available Control Technology analysis for Unit 5 at Possum Point power station. In December 2016, the VDEQ determined that NO~~_X ~~controls are required on Unit 5. Installation and operation of these NO~~_X ~~controls including an associated water treatment system will be required by mid-2019 with an expected cost in the range of $25 million to $35 million.~~

The statutory deadline for the EPA to complete attainment designations for a new standard was October 2017. While it is uncertain when the EPA will make final designations, states will have up to three years to develop plans to address the new standard. Until the states have developed implementation plans, the Companies are unable to predict whether or to what extent the new rules will ultimately require additional controls. However, if significant expenditures are required to implement additional controls, it could adversely affect the Companies’ results of operations and cash flows.

~~NSPS~~

In August 2012, the EPA issued the first NSPS impacting new and modified facilities in the natural gas production and gathering sectors and made revisions to the NSPS for natural gas processing and transmission facilities. These rules establish equipment performance specifications and emissions standards for control of VOC emissions for natural gas production wells, tanks, pneumatic controllers, and compressors in the upstream sector. In June 2016, the EPA issued a final NSPS regulation, for the oil and natural gas sector, to regulate methane and VOC emissions from new and modified facilities in transmission and storage, gathering and boosting, production and processing facilities. All projects which commenced construction after September 2015 are required to comply with this regulation. In April 2017, the EPA issued a notice that it is reviewing and, if appropriate, will issue a rulemaking to suspend, revise or rescind the June 2016 final NSPS for certain oil and gas facilities. In June 2017, the EPA published notice of reconsideration and partial stay of the rule for 90 days and proposed extending the stay for two years. In July 2017, the U.S. Court of Appeals for the D.C. Circuit vacated the 90-day stay. Dominion Energy and Dominion Energy Gas are implementing the final regulation. Dominion Energy and Dominion Energy Gas are still evaluating whether potential impacts on results of operations, financial condition and/or cash flows related to this matter will be material.

~~Climate Change Regulation~~

~~Carbon Regulations~~

In October 2013, the U.S. Supreme Court granted petitions filed by several industry groups, states, and the U.S. Chamber of Commerce seeking review of the U.S. Court of Appeals for the D.C. Circuit’s June 2012 decision upholding the EPA’s regulation of GHG emissions from stationary sources under the CAA’s permitting programs. In June 2014, the U.S. Supreme Court ruled that the EPA lacked the authority under the CAA to require PSD or Title V permits for stationary sources based solely on GHG emissions. However, the Court upheld the EPA’s ability to require BACT for GHG for sources that are otherwise subject to PSD or Title V permitting for conventional pollutants. In August 2016, the EPA issued a draft rule proposing to reaffirm that a source’s obligation to obtain a PSD or Title V permit for GHGs is triggered only if such permitting requirements are first triggered by non-GHG, or conventional, pollutants that are regulated by the New Source Review program, and to set a significant emissions rate at 75,000 tons per year of CO₂ equivalent emissions under which a source would not be required to apply BACT for its GHG emissions. Until the EPA ultimately takes final action on this rulemaking, the Companies cannot predict the impact to their financial statements.

~~In July 2011, the EPA signed a final rule deferring the need for PSD and Title V permitting for CO~~₂ ~~emissions for biomass projects. This rule temporarily deferred for a period of up to three years the consideration of CO~~₂ emissions from biomass projects when determining whether a stationary source meets the PSD and Title V applicability thresholds, including those for the application of BACT. The deferral policy expired in July 2014. In July 2013, the U.S. Court of Appeals for the D.C. Circuit vacated this rule; however, a mandate making this decision effective has not been issued. Virginia Power converted three coal-fired generating stations, Altavista, Hopewell and Southampton, to biomassexpenses during the CO₂ ~~deferral~~ period. It is unclear how the court's decision or the EPA's final policy regarding the treatment of specific feedstock will affect biomass sources that were permitted during the deferral period; however, the expenditures to comply with any new requirements could be material to Dominion Energy's and Virginia Power's financial statements.

~~Methane Emissions~~

In July 2015, the EPA announced the next generation of its voluntary Natural Gas STAR Program, the Natural Gas STAR Methane Challenge Program. The program covers the entire natural gas sector from production to distribution, with more emphasis on transparency and increased reporting for both annual emissions and reductions achieved through implementation measures. In March 2016, East Ohio, Hope, DETI and Questar Gas (prior to the Dominion Energy Questar Combination) joined the EPA as founding partners in the new Methane Challenge program and submitted implementation plans in September 2016. DECG joined the EPA’s voluntary Natural Gas STAR Program in July 2016 and submitted an implementation plan in September 2016. Dominion Energy and Dominion Energy Gas do not expect the costs related to these programs to have a material impact on theirActual results ~~of operations, financial condition and/or cash flows.~~

~~Water~~

The CWA, as amended, is a comprehensive program requiring a broad range of regulatory tools including a permit program to authorize and regulate discharges to surface waters with strong enforcement mechanisms. The Companies must comply with applicable aspects of the CWA programs at their operating facilities.

In October 2014, the final regulations under Section 316(b) of the CWA that govern existing facilities and new units at existing facilities that employ a cooling water intake structure and that have flow levels exceeding a minimum threshold became effective. The rule establishes a national standard for impingement based on seven compliance options, but forgoes the creation of a single technology standard for entrainment. Instead, the EPA has delegated entrainment technology decisions to state regulators. State regulators are to make case-by-case entrainment technology determinations after an examination of five mandatory facility-specific factors, including a social cost-benefit test, and six optional facility-specific factors. The rule governs all electric generating stations with water withdrawals above two MGD, with a heightened entrainment analysis for those facilities over 125 MGD. Dominion Energy and Virginia Power have 14 and 11 facilities, respectively, that may be subject to the final regulations. Dominion Energy anticipates that it will have to install impingement control technologies at many of these stations that have once-through cooling systems. Dominion Energy and Virginia Power are currently evaluating the need or potential for entrainment controls under the final rule as these decisions will be made on a case-by-case basis after a thorough review of detailed biological, technology, cost and benefit studies. While the impacts of this rule could be material to Dominion Energy’s and Virginia Power’s results of operations, financial condition and/or cash flows, the existing regulatory framework in Virginia provides rate recovery mechanisms that could substantially mitigate any such impacts for Virginia Power.

In September 2015, the EPA released a final rule to revise the Effluent Limitations Guidelines for the Steam Electric Power Generating Category. The final rule establishes updated standards for wastewater discharges that apply primarily at coal and oil steam generating stations. Affected facilities are required to convert from wet to dry or closed cycle coal ash management, improve existing wastewater treatment systems and/or install new wastewater treatment technologies in order to meet the new discharge limits. Virginia Power has eight facilities that may be subject to additional wastewater treatment requirements associated with the final rule. In April 2017, the EPA granted two separate petitions for reconsideration of the Effluent Limitations Guidelines final rule and stayed future compliance dates in the rule. Also in April 2017, the U.S. Court of Appeals for the Fifth Circuit granted the U.S.’s request for a stay of the pending consolidated litigation challenging the rule while the EPA addresses the petitions for reconsideration. In September 2017, the EPA signed a rule to postpone the earliest compliance dates of the Effluent Limitations Guidelines final rule for compliance with certain wastewater regulations from November 2018 to November 2020; however, the latest date for compliance for these regulations remains December 2023. The EPA is proposing to complete new rulemaking for these waste streams. While the impacts of this rule could be material to Dominion Energy’s and Virginia Power’s results of operations, financial condition and/or cash flows, the existing regulatory framework in Virginia provides rate recovery mechanisms that could substantially mitigate any such impacts for Virginia Power.

~~Solid and Hazardous Waste~~

The CERCLA, as amended, provides for immediate response and removal actions coordinated by the EPA in the event of threatened releases of hazardous substances into the environment and authorizes the U.S. government either to clean up sites at which hazardous substances have created actual or potential environmental hazards or to order persons responsible for the situation to do so. Under the CERCLA, as amended, generators and transporters of hazardous substances, as well as past and present owners and operators of contaminated sites, can be jointly, severally and strictly liable for the cost of cleanup. These potentially responsible parties can be ordered to perform a cleanup, be sued for costs associated with an EPA-directed cleanup, voluntarily settle with the U.S. government concerning their liability for cleanup costs, or voluntarily begin a site investigation and site remediation under state oversight.

From time to time, Dominion Energy, Virginia Power, or Dominion Energy Gas may be identified as a potentially responsible party to a Superfund site. The EPA (or a state) can either allow such a party to conduct and pay for a remedial investigation, feasibility study and remedial action or conduct the remedial investigation and action itself and then seek reimbursement from the potentially responsible parties. Each party can be held jointly, severally and strictly liable for the cleanup costs. These parties can also bring contribution actions against each other and seek reimbursement from their insurance companies. As a result, Dominion Energy, Virginia Power, or Dominion Energy Gas may be responsible for the costs of remedial investigation and actions under the Superfund law or other laws or regulations regarding the remediation of waste. The Companies do not believe these matters will have a material effect on results of operations, financial condition and/or cash flows.

Dominion Energy has determined that it is associated with 19 former manufactured gas plant sites, three of which pertain to Virginia Power and 12 of which pertain to Dominion Energy Gas. Studies conducted by other utilities at their former manufactured gas plant sites have indicated that those sites contain coal tar and other potentially harmful materials. None of the former sites with which the Companies are associated is under investigation by any state or federal environmental agency. At one of the former sites, Dominion Energy is conducting a state-approved post closure groundwater monitoring program and an environmental land use restriction has been recorded. Another site has been accepted into a state-based voluntary remediation program. Virginia Power is currently evaluating the nature and extent of the contamination from this site as well as potential remedial options. Preliminary costs for options under evaluation for the site range from $1 million to $22 million. Due to the uncertainty surrounding the other sites, the Companies are unable to make an estimate of the potential financial statement impacts.

~~See below for discussion on ash pond and landfill closure costs.~~

~~Other Legal Matters~~

The Companies are defendants in a number of lawsuits and claims involving unrelated incidents of property damage and personal injury. Due to the uncertainty surrounding these matters, the Companies are unable to make an estimate of the potential financial statement impacts; however, they could have a material impact on results of operations, financial condition and/or cash flows.

~~Appalachian Gateway~~

~~Pipeline Contractor Litigation~~

Following the completion of the Appalachian Gateway project in 2012, DETI received multiple change order requests and other claims for additional payments from a pipeline contractor for the project. In July 2013, DETI filed a complaint in U.S. District Court for the Eastern District of Virginia for breach of contract as well as accounting and declaratory relief. The contractor filed a motion to dismiss, or in the alternative, a motion to transfer venue to Pennsylvania and/or West Virginia, where the pipelines were constructed. DETI filed an opposition to the contractor’s motion in August 2013. In November 2013, the court granted the contractor’s motion on the basis that DETI must first comply with the dispute resolution process. In July 2015, the contractor filed a complaint against DETI in U.S. District Court for the Western District of Pennsylvania. In August 2015, DETI filed a motion to dismiss, or in the alternative, a motion to transfer venue to Virginia. In March 2016, the Pennsylvania court granted the motion to dismiss and transferred the case to the U.S. District Court for the Eastern District of Virginia. In April 2016, the Virginia court issued an order staying the proceedings and ordering mediation. A mediation occurred in May 2016 but was unsuccessful. In July 2016, DETI filed a motion to dismiss. In March 2017, the court dismissed three of eight counts in the complaint. In May 2017, the contractor withdrew one of the counts in the complaint. This case is pending. DETI has accrued a liability of $6 million for this matter. Dominion Energy Gas cannot currently estimate additional financial statement impacts, but there could be a material impact to its financial condition and/or cash flows.

~~Gas Producers Litigation~~

In connection with the Appalachian Gateway project, Dominion Energy Field Services, Inc. (formerly known as Dominion Field Services, Inc.) entered into contracts for firm purchase rights with a group of small gas producers. In June 2016, certain of the gas producers filed a complaint in the Circuit Court of Marshall County, West Virginia against Dominion Energy, DETI and Dominion Energy Field Services, Inc., among other defendants, claiming that the contracts are unenforceable and seeking compensatory and punitive damages. In the third quarter of 2016, Dominion Energy and DETI, with the consent of the other defendants, removed the case to the U.S. District Court for the Northern District of West Virginia. In October 2016, the defendants filed a motion to dismiss and the plaintiffs filed a motion to remand. In February 2017, the U.S. District Court entered an order remanding the matter to the Circuit Court of Marshall County, West Virginia. In March 2017, Dominion Energy was voluntarily dismissed from the case; however, DETI and Dominion Energy Field Services, Inc. remain parties to the matter. In April 2017, the case was transferred to the Business Court Division of West Virginia. This case is pending. Dominion Energy and Dominion Energy Gas cannot currently estimate financial statement impacts, but there could be a material impact to their financial condition and/or cash flows.

~~Ash Pond and Landfill Closure Costs~~

In September 2014, Virginia Power received a notice from the Southern Environmental Law Center on behalf of the Potomac Riverkeeper and Sierra Club alleging CWA violations at Possum Point power station. The notice alleges unpermitted discharges to surface water and groundwater from Possum Point power station’s historical and active ash storage facilities. A similar notice from the Southern Environmental Law Center on behalf of the Sierra Club was subsequently received related to Chesapeake power station. In December 2014, Virginia Power offered to close all of its coal ash ponds and landfills at Possum Point power station, Chesapeake and Bremo power stations as settlement of the potential litigation. The Southern Environmental Law Center declined the offer as presented in January 2015 and, in March 2015, filed a lawsuit related to its claims of the alleged CWA violations at Chesapeake power station. In March 2017, the U.S. District Court for the Eastern District of Virginia ruled that impacted groundwater associated with the on-site coal ash storage units was migrating to adjacent surface water, which constituted an unpermitted point source discharge in violation of the CWA. The court, however, rejected Sierra Club’s claims that Virginia Power had violated specific conditions of its water discharge permit. Finding no harm to the environment, the court further declined to impose civil penalties or require excavation of the ash from the site as Sierra Club had sought. On remedy, the court ordered the parties to submit within 30 days a remedial plan (or separate plans) incorporating certain prescribed sediment, water and aquatic life monitoring. The court also ordered Virginia Power to reopen its solid waste permit application for closure of the coal ash storage units at Chesapeake power station. In April 2017, Virginia Power submitted its remedial plan to the court, which included a timetable for submitting a revised solid waste permit application to the VDEQ. The revised application will include a proposed remedial alternative to address groundwater impacts associated with coal ash storage at Chesapeake power station. Sierra Club submitted a separate remedial plan to the court. In July 2017, the court issued a final order requiring Virginia Power to perform additional specific sediment, water and aquatic life monitoring at and around the

Chesapeake power station for a period of at least two years. The court further directed Virginia Power to apply for a solid waste permit from VDEQ that includes corrective measures to address on-site groundwater impacts. In July 2017, Virginia Power appealed the court’s July 2017 final order to the U.S. Court of Appeals for the Fourth Circuit. In August 2017, the Sierra Club filed a cross appeal. This case is pending.

In April 2015, the EPA’s final rule regulating the management of CCRs stored in impoundments (ash ponds) and landfills was published in the Federal Register. The final rule regulates CCR landfills, existing ash ponds that still receive and manage CCRs, and inactive ash ponds that do not receive, but still store CCRs. Virginia Power currently operates inactive ash ponds, existing ash ponds, and CCR landfills subject to the final rule at eight different facilities. The enactment of the final rule in April 2015 created a legal obligation for Virginia Power to retrofit or close all of its inactive and existing ash ponds over a certain period of time, as well as perform required monitoring, corrective action, and post-closure care activities as necessary. In April 2016, the EPA announced a partial settlement with certain environmental and industry organizations that had challenged the final CCR rule in the U.S. Court of Appeals for the D.C. Circuit. As part of the settlement, certain exemptions included in the final rule for inactive ponds that closed by April 2018 will be removed, resulting in inactive ponds ultimately being subject to the same requirements as existing ponds. In June 2016, the court issued an order approving the settlement, which requires the EPA to modify provisions in the final CCR rule concerning inactive ponds. In August 2016, the EPA issued a final rule, effective October 2016, extending certain compliance deadlines in the final CCR rule for inactive ponds. Virginia Power does not believe these changes will substantially impact its closure plans for inactive ponds.

In December 2016, the U.S. Congress passed and the President signed legislation that creates a framework for EPA- approved state CCR permit programs. Under this legislation, an approved state CCR permit program functions in lieu of the self-implementing Federal CCR rule. The legislation allows states more flexibility in developing permit programs to implement the environmental criteria in the CCR rule. In August 2017, the EPA issued interim guidance outlining the framework for state CCR program approval. The EPA has enforcement authority until state programs are approved. The EPA and states with approved programs both will have authority to enforce CCR requirements under their respective rules and programs. In September 2017, the EPA agreed to reconsider portions of the CCR rule in response to two petitions for reconsideration. Dominion Energy cannot forecast potential incremental impacts or costs related to existing coal ash sites in connection with future implementation of the 2016 CCR legislation and reconsideration of the CCR rule.

In April 2017, the Governor of Virginia signed legislation into law that places a moratorium on the VDEQ issuing solid waste permits for closure of ash ponds at Virginia Power’s Bremo, Chesapeake, Chesterfield and Possum Point power stations until May 2018. The law also requires Virginia Power to conduct an assessment of closure alternatives for the ash ponds at these four stations, to include an evaluation of excavation for recycling or off-site disposal, surface and groundwater conditions and safety. The assessments are due by December 1, 2017. Virginia Power has initiated a third-party evaluation of closure alternatives consistent with the legislation and is unable to estimate the potential financial statement impacts. The actual AROs related to the CCR rule may vary substantiallydiffer from the estimates used ~~to record~~in preparing the ~~obligation.~~

~~Cove Point~~

Dominion Energy is constructing the Liquefaction Project at the Cove Point facility, which would enable the facility to liquefy domestically-produced natural gas and export it as LNG. In September 2014, FERC issued an order granting authorization for Cove Point to construct, modify and operate the Liquefaction Project. In October 2014, several parties filed a motion with FERC to stay the order and requested rehearing. In May 2015, FERC denied the requests for stay and rehearing.

Two parties have separately filed petitions for review of the FERC order in the U.S. Court of Appeals for the D.C. Circuit, which petitions were consolidated. Separately, one party requested a stay of the FERC order until the judicial proceedings are complete, which the court denied in June 2015. In July 2016, the court denied one party’s petition for review of the FERC order authorizing the Liquefaction Project. The court also issued a decision remanding the other party’s petition for review of the FERC order to FERC for further explanation of FERC’s decision that a previous transaction with an existing import shipper was not unduly discriminatory. In September 2017, FERC issued its order on remand from the U.S. Court of Appeals for the D.C. Circuit, and reaffirmed its ruling in its prior orders that Cove Point did not violate the prohibition against undue discrimination by agreeing to a capacity reduction and early contract termination with the existing import shipper.

In September 2013, the U.S. DOE granted Non-FTA Authorization approval for the export of up to 0.77 bcfe/day of natural gas to countries that do not have an FTA for trade in natural gas. In June 2016, a party filed a petition for review of this approval in the U.S. Court of Appeals for the D.C. Circuit. This case is pending.

In July 2017, Cove Point submitted an application for a temporary operating permit to the Maryland Department of the Environment, as required prior to the date of first production of LNG for commercial purposes of exporting LNG. In August 2017, Cove Point submitted an application to amend the CPCN issued by the Public Service Commission of Maryland in May 2014 to make necessary updates. These cases are pending.

~~FERC~~

FERC staff in the Office of Enforcement, Division of Investigations, is conducting a non-public investigation of Virginia Power's offers of combustion turbines generators into the PJM day-ahead markets from April 2010 through September 2014. FERC staff notified Virginia Power of its preliminary findings relating to Virginia Power's alleged violation of FERC's rules in connection with these activities. Virginia Power has provided its response to FERC staff's preliminary findings letter explaining why Virginia Power's conduct was lawful and refuting any allegation of wrongdoing. Virginia Power is cooperating fully with the investigation; however, it cannot currently predict whether or to what extent it may incur a material liability.

~~Greensville County~~

Virginia Power is constructing Greensville County and related transmission interconnection facilities. In August 2016, the Sierra Club filed an administrative appeal in the Circuit Court for the City of Richmond challenging certain provisions in Greensville County’s PSD air permit issued by the VDEQ in June 2016. In August 2017, the Circuit Court upheld the air permit, and no appeals were filed.

~~Nuclear Matters~~

In March 2011, a magnitude 9.0 earthquake and subsequent tsunami caused significant damage at the Fukushima Daiichi nuclear power station in northeast Japan. These events have resulted in significant nuclear safety reviews required by the NRC and industry groups such as the Institute of Nuclear Power Operations. Like other U.S. nuclear operators, Dominion Energy has been gathering supporting data and participating in industry initiatives focused on the ability to respond to and mitigate the consequences of design-basis and beyond-design-basis events at its stations.

In July 2011, an NRC task force provided initial recommendations based on its review of the Fukushima Daiichi accident and in October 2011 the NRC staff prioritized these recommendations into Tiers 1, 2 and 3, with the Tier 1 recommendations consisting of actions which the staff determined should be started without unnecessary delay. In December 2011, the NRC Commissioners approved the agency staff's prioritization and recommendations, and that same month an appropriations act directed the NRC to require reevaluation of external hazards (not limited to seismic and flooding hazards) as soon as possible.

Based on the prioritized recommendations, in March 2012, the NRC issued orders and information requests requiring specific reviews and actions to all operating reactors, construction permit holders and combined license holders based on the lessons learned from the Fukushima Daiichi event. The orders applicable to Dominion Energy requiring implementation of safety enhancements related to mitigation strategies to respond to extreme natural events resulting in the loss of power at plants, and enhancing spent fuel pool instrumentation have been implemented. The information requests issued by the NRC request each reactor to reevaluate the seismic and external flooding hazards at their site using present-day methods and information, conduct walkdowns of their facilities to ensure protection against the hazards in their current design basis, and to reevaluate their emergency communications systems and staffing levels. The walkdowns of each unit have been completed, audited by the NRC and found to be adequate. Reevaluation of the emergency communications systems and staffing levels was completed as part of the effort to comply with the orders. Reevaluation of the seismic and external flooding hazards is expected to continue through 2018. Dominion Energy and Virginia Power do not currently expect that compliance with the NRC's information requests will materially impact their financial position, results of operations or cash flows during the implementation period. The NRC staff is evaluating the implementation of the longer term Tier 2 and Tier 3 recommendations. Dominion Energy and Virginia Power do not expect material financial impacts related to compliance with Tier 2 and Tier 3 recommendations.

~~Guarantees, Surety Bonds and Letters of Credit~~

~~Dominion Energy~~

~~At September 30, 2017, Dominion Energy had issued $48 million of guarantees, primarily to support equity method investees. No significant amounts related to these guarantees have been recorded.~~

In October 2017, Dominion Energy entered into a guarantee agreement to support a portion of Atlantic Coast Pipeline’s obligation under a $3.3 billion revolving credit facility, also entered in October 2017, with a stated maturity date of October 2021. Dominion Energy’s maximum potential loss exposure under the terms of the guarantee is limited to 48% of the outstanding borrowings under the revolving credit facility, an equal percentage to Dominion Energy’s ownership in Atlantic Coast Pipeline. In October 2017, Dominion Energy recorded a liability of $30 million associated with this guarantee agreement. Through October 2017, Atlantic Coast Pipeline has borrowed $570 million against the revolving credit facility.

Dominion Energy also enters into guarantee arrangements on behalf of its consolidated subsidiaries, primarily to facilitate their commercial transactions with third parties. If any of these subsidiaries fail to perform or pay under the contracts and the counterparties seek performance or payment, Dominion Energy would be obligated to satisfy such obligation. To the extent that a liability subject to a guarantee has been incurred by one of Dominion Energy’s consolidated subsidiaries, that liability is included in theunaudited Consolidated Financial Statements. ~~Dominion Energy is not required~~Note 2 of Notes to recognize liabilities for guarantees issued on behalf of its subsidiaries unless it becomes probable that it will have to perform under the guarantees. Terms of the guarantees typically end once obligations have been paid. Dominion Energy currently believes it is unlikely that it would be required to perform or otherwise incur any losses associated with guarantees of its subsidiaries’ obligations.

~~At September 30, 2017, Dominion Energy had issued the following subsidiary guarantees:~~

Maximum
Exposure

(millions)

Commodity transactions⁽¹⁾

$
1,967

Nuclear obligations⁽²⁾

227

Cove Point⁽³⁾

1,900

Solar⁽⁴⁾

1,054

Other⁽⁵⁾

538

Total⁽⁶⁾

$
5,686

~~(1)~~

Guarantees related to commodity commitments of certain subsidiaries. These guarantees were provided to counterparties in order to facilitate physical and financial transaction-related commodities and services.

~~(2)~~

~~Guarantees related to certain DGI subsidiaries regarding all aspects of running a nuclear facility.~~

~~(3)~~

~~Guarantees related to Cove Point, in support of terminal services, transportation and construction.~~

~~(4)~~

Includes guarantees to facilitate the development of solar projects. Also includes guarantees entered into by DGI on behalf of certain subsidiaries to facilitate the acquisition and development of solar projects.

~~(5)~~

Guarantees related to other miscellaneous contractual obligations such as leases, environmental obligations, construction projects and insurance programs. Due to the uncertainty of workers’ compensation claims, the parental guarantee has no stated limit. Also included are guarantees related to certain DGI subsidiaries' obligations for equity capital contributions and energy generation associated with Fowler Ridge and NedPower. As of September 30, 2017, Dominion Energy's maximum remaining cumulative exposure under these equity funding agreements is $20 million through 2019 and its maximum annual future contributions could range from approximately $4 million to $19 million.

~~(6)~~

Excludes Dominion Energy's guarantee for the construction of a new corporate office property as discussed in Note 22 to the Consolidated Financial Statements in the Companies' Annual Report on Form 10-K for the year ended December 31, 2016.

Additionally, at September 30, 2017, Dominion Energy had purchased $141 million of surety bonds, including $63 million at Virginia Power and $24 million at Dominion Energy Gas, and authorized the issuance of letters of credit by financial institutions of $73 million to facilitate commercial transactions by its subsidiaries with third parties. Under the terms of surety bonds, the Companies are obligated to indemnify the respective surety bond company for any amounts paid.

~~Note 16. Credit Risk~~

~~The Companies' accounting policies for credit risk are discussed in Note 23 to the~~ Consolidated Financial Statements included in ~~the Companies'~~EGTS' Annual Report on Form 10-K for the year ended December 31, ~~2016. During~~2022 describes the ~~second quarter~~most significant accounting policies used in the preparation of ~~2017, Virginia Power recorded~~the unaudited Consolidated Financial Statements. There have been no significant changes in EGTS' accounting policies or its assumptions regarding significant accounting estimates during the three-month period ended March 31, 2023.

(2) Property, Plant and Equipment, Net

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


		As of
		March 31,		December 31,
	Depreciable Life	2023		2022

Interstate natural gas transmission and storage assets	28 - 50 years	$	6,842	$	6,724
Intangible plant	12 - 20 years	80		79
Plant in-service		6,922		6,803
Accumulated depreciation and amortization		(2,465)		(2,440)
		4,457		4,363










Construction work-in-progress		147		141
Property, plant and equipment, net		$	4,604	$	4,504

170

(3) Regulatory Matters

In September 2021, EGTS filed a ~~$16~~general rate case for its FERC-jurisdictional services, with proposed rates to be effective November 1, 2021. EGTS proposed an annual cost-of-service of approximately $1.1 billion, and requested increases in various rates, including general system storage rates by 85% and general system transmission rates by 60%. In October 2021, the FERC issued an order that accepted the November 1, 2021 effective date for certain changes in rates, while suspending the other changes for five months following the proposed effective date, until April 1, 2022, subject to refund. In September 2022, a settlement agreement was filed with the FERC, which provided for increased service rates and decreased depreciation rates. Under the terms of the settlement agreement, EGTS' rates result in an increase to annual firm transmission and storage services revenues of approximately $160 million ~~($10~~and a decrease in annual depreciation expense of approximately $30 million, ~~after-tax) charge~~compared to the rates in effect prior to April 1, 2022. EGTS' provision for rate refund for April 2022 through February 2023, including accrued interest, totaled $91 million. In November 2022, the FERC approved the settlement agreement and the rate refunds to customers were processed in late February 2023.

(4) Investments and Restricted Cash and Cash Equivalents

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


	As of
	March 31,		December 31,
	2023		2022
Investments:
Investment funds	$	17	$	14


Restricted cash and cash equivalents:
Customer deposits	29		29
Total restricted cash and cash equivalents	29		29

Total investments and restricted cash and cash equivalents	$	46	$	43

Reflected as:
Current assets	$	29	$	29
Noncurrent assets	17		14
Total investments and restricted cash and cash equivalents	$	46	$	43

Cash and Cash Equivalents and Restricted Cash and Cash Equivalents

Cash equivalents consist of funds invested in money market mutual funds, U.S. 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 consist of customer deposits as allowed under the FERC gas tariff. A reconciliation of cash and cash equivalents and restricted cash and cash equivalents as presented on 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,
	2023		2022

Cash and cash equivalents	$	46	$	16
Restricted cash and cash equivalents	29		29
Total cash and cash equivalents and restricted cash and cash equivalents	$	75	$	45

171

(5) Income Taxes

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


	Three-Month Periods
	Ended March 31,
	2023		2022

Federal statutory income tax rate	21	%	21	%
State income tax, net of federal income tax benefit	4		5













Effective income tax rate	25	%	26	%

(6) Employee Benefit Plans

EGTS is a participant in benefit plans sponsored by MidAmerican Energy Company ("MidAmerican Energy"), an affiliate. The MidAmerican Energy Company Retirement Plan includes a qualified pension plan that provides pension benefits for eligible employees. The MidAmerican Energy Company Welfare Benefit Plan provides certain postretirement health care and life insurance benefits for eligible retirees on behalf of EGTS. EGTS contributed $2 million and $3 million to the MidAmerican Energy Company Retirement Plan for the three-month periods ended March 31, 2023 and 2022, respectively, and $1 million to the MidAmerican Energy Company Welfare Benefit Plan for the three-month period ended March 31, 2022. Contributions related to ~~a proposed settlement~~these plans are reflected as net periodic benefit cost in operations and maintenance expense on the Consolidated Statements of Operations. Amounts attributable to EGTS were allocated from MidAmerican Energy in accordance with ~~a customer renting space on certain of Virginia Power’s electric distribution poles. This matter was settled during~~ the ~~third quarter of 2017.~~

~~At September 30, 2017, Dominion Energy's credit exposure~~intercompany administrative service agreement. Offsetting regulatory assets and liabilities have been recorded related to energy marketing and price risk management activities totaled $70 million. Of this amount, investment grade counterparties, including those internally rated, represented 49%. No single counterparty, whether investment grade or non-investment grade, exceeded $7 millionthe amounts not yet recognized as a component of exposure. At September 30, 2017, Virginia Power's exposure related to sales to wholesale customers totaled $23 million. Of this amount, investment grade counterparties, including those internally rated, represented 52%. No single counterparty, whether investment grade or non-investment grade, exceeded $6 millionnet periodic benefit costs that will be included in regulated rates. As of ~~exposure.~~

~~Credit-Related Contingent Provisions~~

The majority of Dominion Energy's derivative instruments contain credit-related contingent provisions. These provisions require Dominion Energy to provide collateral upon the occurrence of specific events, primarily a credit rating downgrade. If the credit-related contingent features underlying these instruments that are in a liability position and not fully collateralized with cash were fully triggered as of September 30, 2017March 31, 2023 and December 31, ~~2016, Dominion~~2022, EGTS' amount due to MidAmerican Energy associated with these plans and reflected in other long-term liabilities on the Consolidated Balance Sheets was $47 million.

(7) Fair Value Measurements

The carrying value of EGTS' cash, certain cash equivalents, receivables, payables, accrued liabilities and short-term borrowings approximates fair value because of the short-term maturity of these instruments. EGTS 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 EGTS has the ability to access at the measurement date.

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

172

The following table presents EGTS' 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		Total
As of March 31, 2023:
Assets:

Money market mutual funds	$	40	$	—	$	—	$	40
Equity securities:
Investment funds	17		—		—		17
	$	57	$	—	$	—	$	57







As of December 31, 2022:
Assets:
Commodity derivatives	$	—	$	1	$	—	$	1

Money market mutual funds	8		—		—		8
Equity securities:
Investment funds	14		—		—		14
	$	22	$	1	$	—	$	23

EGTS' investments in money market mutual funds and investment funds 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.

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 purchase 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 EGTS transacts. When quoted prices for identical contracts are not available, EGTS uses forward price curves. Forward price curves represent EGTS' estimates of the prices at which a buyer or seller could contract today for delivery or settlement at future dates. EGTS 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 EGTS. Market price quotations are generally readily obtainable for the applicable term of EGTS' outstanding derivative contracts; therefore, EGTS' forward price curves reflect observable market quotes. Market price quotations for certain natural gas trading hubs are not as readily obtainable due to the length of the contracts. Given that limited market data exists for these contracts, as well as for those contracts that are not actively traded, EGTS 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, related volatility, counterparty creditworthiness and duration of contracts.

EGTS' long-term debt is carried at cost on the Consolidated Financial Statements. The fair value of EGTS' 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 following table presents the carrying value and estimated fair value of EGTS' long-term debt (in millions):


	As of March 31, 2023				As of December 31, 2022
	Carrying Value		Fair Value		Carrying Value		Fair Value

Long-term debt	$	1,582	$	1,393	$	1,582	$	1,337

173

(8) Commitments and Contingencies

Environmental Laws and Regulations

EGTS is subject to federal, state and local laws and regulations regarding air quality, climate change, emissions performance standards, water quality and other environmental matters that have ~~been required~~the potential to ~~post additional collateral~~impact its current and future operations. EGTS believes it is in material compliance with all applicable laws and regulations.

Legal Matters

EGTS is party to a variety of legal actions arising out of the normal course of business. Plaintiffs occasionally seek punitive or exemplary damages. EGTS does not believe that such normal and routine litigation will have a material impact on its ~~counterparties~~consolidated financial results.

(9) Revenue from Contracts with Customers

The following table summarizes EGTS' revenue from contracts with customers ("Customer Revenue") by regulated and other, with further disaggregation of regulated by line of business (in millions):


	Three-Month Periods
	Ended March 31,
	2023		2022
Customer Revenue:
Regulated:
Gas transmission	$	191	$	165
Gas storage	67		47

Other	2		—
Total regulated	260		212
Management service and other revenues	17		18
Total Customer Revenue	277		230
Other revenue(1)	1		(7)
Total operating revenue	$	278	$	223

Remaining Performance Obligations

The following table summarizes EGTS' 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, 2023 (in millions):


	Performance obligations expected to be satisfied
	Less than 12 months		More than 12 months		Total

EGTS	$	746	$	3,390	$	4,136

174

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 EGTS during the periods included herein. This discussion should be read in conjunction with EGTS' historical Consolidated Financial Statements and Notes to Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. EGTS' actual results in the future could differ significantly from the historical results.

Results of Operations for the First Quarter of 2023 and 2022

Overview

Net income for the first quarter of 2023 was $68 million, an increase of $13 million, or 24%, compared to 2022. Net income increased primarily due to higher margin from regulated gas transmission and storage operations of $32 million and a decrease due to lower depreciation rates due to the settlement in EGTS' general rate case, partially offset by higher operations and maintenance expenses, lower 2021 tax assessments finalized in 2022 and an increase in income tax expense primarily due to higher pre-tax income.

Quarter Ended March 31, 2023 Compared to Quarter Ended March 31, 2022

Operating revenue increased $55 million, or 25%, for the first quarter of 2023 compared to 2022, primarily due to an increase in regulated gas transmission and storage services revenues due to the settlement of EGTS' general rate case of $42 million, an increase in variable revenue related to park and loan activity of $10 million and derivative losses in 2022 of $7 million, partially offset by a net decrease in regulated gas transmission and storage services revenues due to volumes primarily from the expiration of the Appalachian Gateway Project contracts in August 2022 of $6 million.

Cost of (excess) gas was an expense of $20 million for the first quarter of 2023 compared to a credit of $3 million for the first quarter of 2022. The change is primarily from the unfavorable revaluation of the volumes retained prior to the effective date of the new fuel tracker, due to lower natural gas prices.

Operations and maintenance increased $15 million, or 18%, for the first quarter of 2023 compared to 2022, primarily due to higher corporate charges of $6 million and $3an increase in salaries, wages and benefits of $5 million.

Depreciation and amortization decreased $6 million, or 14%, for the first quarter of 2023 compared to 2022, primarily due to the settlement of deprecation rates in EGTS' general rate case of $8 million, partially offset by higher plant placed in-service of $2 million.

Property and other taxes increased $5 million, or 56%, for the first quarter of 2023 compared to 2022, primarily due to lower 2021 tax assessments that were finalized in 2022.

Income tax expense increased $4 million, or 21%, for the first quarter of 2023 compared to 2022, primarily due to higher pre-tax income. The effective tax rate was 25% for 2023 and 26% for 2022.

175

Liquidity and Capital Resources

As of March 31, 2023, EGTS' total net liquidity was as follows (in millions):


Cash and cash equivalents	$	46

Intercompany revolving credit agreement	400
Less:
Notes payable to affiliates	13

Net intercompany revolving credit agreement	387

Total net liquidity	$	433

Intercompany credit agreement:
Maturity date	2024

Operating Activities

Net cash flows from operating activities for the three-month periods ended March 31, 2023 and 2022 were $93 million and $128 million, respectively. The ~~collateral that would be required~~change is primarily due to ~~be posted includes~~the repayment of EGTS rate refunds to customers, partially offset by the impacts from the rate increase in effect April 1, 2022 for the EGTS general rate case and other changes in working capital.

The timing of ~~any offsetting asset positions and any amounts already posted for derivatives, non-derivative contracts and derivatives elected under~~EGTS' income tax cash flows from period to period can be significantly affected by the normal purchases and normal sales exception, per contractual terms. Dominion Energy had not posted any collateral at September 30, 2017 or December 31, 2016 related to derivatives with credit-related contingent provisions that are in a liability position and not fully collateralized with cash. The collateral posted includes any amounts paid related to non-derivative contracts and derivatives elected under the normal purchases and normal sales exception, per contractual terms. The aggregate fair value of all derivative instruments with credit-related contingent provisions that are in a liability position and not fully collateralized with cash at both September 30, 2017 and December 31, 2016 was $9 million, which does not include the impact of any offsetting asset positions. Credit-related contingent provisions for Virginia Power and Dominion Energy Gas were not material as of September 30, 2017 and December 31, 2016. See Note 9 for further information about derivative instruments.

~~Note 17. Related-Party Transactions~~

Virginia Power and Dominion Energy Gas engage in related-party transactions primarily with other Dominion Energy subsidiaries (affiliates). Virginia Power's and Dominion Energy Gas' receivable and payable balances with affiliates are settled based on contractual terms or on a monthly basis, depending on the nature of the underlying transactions. Virginia Power and Dominion Energy Gas are included in Dominion Energy's consolidatedestimated federal income tax ~~return~~payment methods elected and ~~where applicable, combined~~assumptions made for each payment date.

Investing Activities

Net cash flows from investing activities for the three-month periods ended March 31, 2023 and 2022 were $(40) million and $(56) million, respectively. The change is primarily due to a decrease in capital expenditures of $16 million.

Financing Activities

Net cash flows from financing activities for the three-month period ended March 31, 2023 were $(23) million and consisted of net repayment of notes payable to Eastern Energy Gas.

Net cash flows from financing activities for the three-month period ended March 31, 2022 were $(68) million and consisted of net repayment of notes payable to Eastern Energy Gas.

Future Uses of Cash

EGTS 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, intercompany revolving credit agreements, capital contributions and other sources. These sources are expected to provide funds required for current operations, capital expenditures, investments, debt retirements and other capital requirements. The availability and terms under which EGTS has access to external financing depends on a variety of factors, including regulatory approvals, EGTS' credit ratings, investors' judgment of risk and conditions in the overall capital markets, including the condition of the natural gas transmission and storage industry.

Capital Expenditures

Capital expenditure needs are reviewed regularly by management and may change significantly as a result of these reviews, which may consider, among other factors, new growth projects and the timing of growth projects; changes in environmental and other rules and regulations; impacts to customer rates; outcomes of regulatory proceedings; changes in income tax ~~returns~~laws; general business conditions; system reliability standards; the cost and efficiency of construction labor, equipment and materials; commodity prices; and the cost and availability of capital.

176

EGTS' historical and forecasted capital expenditures, each of which exclude amounts for ~~Dominion Energy~~non-cash equity AFUDC and other non-cash items, are ~~filed in various states. Dominion Energy's transactions with equity method investments are described in Note 10. A discussion of significant related-party transactions follows.~~

~~Virginia Power~~

~~Transactions with Affiliates~~

~~Virginia Power transacts with affiliates for certain quantities of~~as follows (in millions):


	Three-Month Periods				Annual
	Ended March 31,				Forecast
	2022		2023		2023

Natural gas transmission and storage	$	6	$	3	$	27
Other	47		34		225
Total	$	53	$	37	$	252

Natural gas transmission and storage includes primarily growth capital expenditures related to planned regulated projects. Other includes primarily pipeline integrity work, automation and controls upgrades, underground storage, corrosion control, unit exchanges, compressor modifications and projects related to Pipeline Hazardous Materials Safety Administration natural gas storage rules. The amounts also include EGTS' asset modernization program, which includes projects for vintage pipeline replacement, compression replacement, pipeline assessment and ~~other commodities~~underground storage integrity.

Material Cash Requirements

As of March 31, 2023, there have been no material changes in cash requirements from the ~~ordinary course~~information provided in Item 7 of business. Virginia Power also enters into certain commodity derivative contracts with affiliates. Virginia Power uses these contracts, which are principally comprised of commodity swaps, to manage commodity price risks associated with purchases of natural gas. At September 30, 2017, Virginia Power’s derivative assets and liabilities with affiliates were $13 million and $5 million, respectively. At December 31, 2016, Virginia Power’s derivative assets and liabilities with affiliates were $41 million and $8 million, respectively. See Note 9 for more information.

~~Virginia Power participates in certain Dominion Energy benefit plans described in Note 21 to the Consolidated Financial Statements in the Companies’~~EGTS' Annual Report on Form 10-K for the year ended December 31, ~~2016. At September 30, 2017~~2022.

Regulatory Matters

EGTS is subject to comprehensive regulation. Refer to "Regulatory Matters" in Berkshire Hathaway Energy's Part I, Item 2 of this Form 10-Q for discussion regarding EGTS' current regulatory matters.

Environmental Laws and ~~December 31, 2016, amounts due~~Regulations

EGTS is subject to ~~Dominion Energy associated with the Dominion Pension Plan~~federal, state and ~~included in other deferred credits~~local laws and regulations regarding air quality, climate change, emissions performance standards, water quality and other ~~liabilities in~~environmental matters that have the Consolidated Balance Sheets were $478 million and $396 million, respectively. At September 30, 2017 and December 31, 2016, Virginia Power's amounts due from Dominion Energy associated with the Dominion Retiree Health and Welfare plan and included in pension and other postretirement benefit assets in the Consolidated Balance Sheets were $182 million and $130 million, respectively.

~~DES and other affiliates provide accounting, legal, finance and certain administrative and technical services~~potential to ~~Virginia Power. In addition, Virginia Power provides certain services to affiliates, including charges for facilities and equipment usage.~~

The financial statements for all years presented include costs for certain general, administrative and corporate expenses assigned by DES to Virginia Power on the basis of direct and allocated methods in accordance with Virginia Power’s services agreements with DES. Where costs incurred cannot be determined by specific identification, the costs are allocated based on the proportional level of effort devoted by DES resources that is attributable to the entity, determined by reference to number of employees, salaries and wages and other similar measures for the relevant DES service. Management believes the assumptions and methodologies underlying the allocation of general corporate overhead expenses are reasonable.

~~Presented below are Virginia Power's significant transactions with DES and other affiliates:~~

Three Months Ended September 30,

Nine Months Ended September 30,

2017

2016

2017

2016

(millions)

Commodity purchases from affiliates

$
170

$
172

$
519

$
416

Services provided by affiliates⁽¹⁾

109

105

333

347

Services provided to affiliates

5

5

17

17

~~(1)~~

Includes capitalized expenditures of $33 million and $32 million for the three months ended September 30, 2017 and 2016, respectively, and $104 million and $109 million for the nine months ended September 30, 2017 and 2016, respectively.

Virginia Power has borrowed funds from Dominion Energy under short-term borrowing arrangements. There were $36 million and $262 million in short-term demand note borrowings from Dominion Energy as of September 30, 2017 and December 31, 2016, respectively. Virginia Power had no outstanding borrowings under the Dominion Energy money pool forimpact its nonregulated subsidiaries as of September 30, 2017 and December 31, 2016. Interest charges related to Virginia Power's borrowings from Dominion Energy were immaterial for the three and nine months ended September 30, 2017 and 2016.

~~There were no issuances of Virginia Power's common stock to Dominion Energy for the three and nine months ended September 30, 2017 and 2016.~~

~~Dominion Energy Gas~~

~~Transactions with Related Parties~~

Dominion Energy Gas transacts with affiliates for certain quantities of natural gas and other commodities at market prices in the ordinary course of business. Additionally, Dominion Energy Gas provides transportation and storage services to affiliates. Dominion Energy Gas also enters into certain other contracts with affiliates, which are presented separately from contracts involving commodities or services. As of September 30, 2017 and December 31, 2016, all of Dominion Energy Gas' commodity derivatives were with affiliates. See Notes 7 and 9 for more information.

Dominion Energy Gas participates in certain Dominion Energy benefit plans as described in Note 18. At September 30, 2017 and December 31, 2016, amounts due from Dominion Energy associated with the Dominion Pension Plan included in noncurrent pension and other postretirement benefit assets in the Consolidated Balance Sheets were $725 million and $697 million, respectively. At September 30, 2017 and December 31, 2016, Dominion Energy Gas' amounts due from Dominion Energy associated with the Dominion Retiree Health and Welfare plan included in noncurrent pension and other postretirement benefit assets in the Consolidated Balance Sheets were $6 million and $2 million, respectively.

The financial statements for all years presented include costs for certain general, administrative and corporate expenses assigned by DES to Dominion Energy Gas on the basis of direct and allocated methods in accordance with Dominion Energy Gas’ services agreements with DES. Where costs incurred cannot be determined by specific identification, the costs are allocated based on the proportional level of effort devoted by DES resources that is attributable to the entity, determined by reference to number of employees, salaries and wages and other similar measures for the relevant DES service. Management believes the assumptions and methodologies underlying the allocation of general corporate overhead expenses are reasonable. The costs of these services follow:

Three Months Ended September 30,

Nine Months Ended September 30,

2017

2016

2017

2016

(millions)

Purchases of natural gas and transportation and
storage services from affiliates

$
2

$
2

$
4

$
7

Sales of natural gas and transportation and
storage services to affiliates

15

16

51

51

Services provided by related parties⁽¹⁾

36

36

106

108

Services provided to related parties⁽²⁾

37

34

113

94

~~(1)~~

Includes capitalized expenditures of $13 million for both the three months ended September 30, 2017 and 2016, respectively, and $33 million and $37 million for the nine months ended September 30, 2017 and 2016, respectively.

~~(2)~~

~~Amounts primarily attributable to Atlantic Coast Pipeline, a related-party VIE.~~

~~The following table presents affiliated and related-party activity reflected in Dominion Energy Gas' Consolidated Balance Sheets:~~

September 30, 2017

December 31, 2016

(millions)

Other receivables⁽¹⁾

$
13

$
10

Imbalances receivable from affiliates

—

2

Imbalances payable to affiliates⁽²⁾

1

4

Affiliated notes receivable⁽³⁾

21

18

~~(1)~~

~~Represents amounts due from Atlantic Coast Pipeline, a related-party VIE.~~

~~(2)~~

~~Amounts are presented in other current liabilities in Dominion Energy Gas' Consolidated Balance Sheets.~~

~~(3)~~

~~Amounts are presented in other deferred charges and other assets in Dominion Energy Gas' Consolidated Balance Sheets.~~

Dominion Energy Gas' borrowings under the intercompany revolving credit agreement with Dominion Energy were $34 million and $118 million as of September 30, 2017 and December 31, 2016, respectively. Interest charges related to Dominion Energy Gas' total borrowings from Dominion Energy were immaterial for the three and nine months ended September 30, 2017 and 2016.

~~Note 18. Employee Benefit Plans~~

In the first quarter of 2016, the Companies announced an organizational design initiative that reduced their total workforces during 2016. The goal of the organizational design initiative was to streamline leadership structure and push decision making lower while also improving efficiency. During the nine months ended September 30, 2016, Dominion Energy recorded a $65 million ($40 million after-tax) charge, including $33 million ($20 million after-tax) at Virginia Power and $8 million ($5 million after-tax) at Dominion Energy Gas, primarily reflected in other operations and maintenance expense in their Consolidated Statements of Income due to severance pay and other costs related to the organizational design initiative. The terms of the severance under the organizational design initiative were consistent with the Companies’ existing severance plans.

~~Plan Amendment and Remeasurement~~

In the first quarter of 2017, Dominion Energy and Dominion Energy Gas remeasured an other postretirement benefit plan as a result of an amendment that changed post-65 retiree medical coverage for certain current and future ~~Local 69 retirees effective July 1, 2017. The remeasurement resulted in a decrease in Dominion Energy's~~operations. In addition to imposing continuing compliance obligations, these laws and Dominion Energy Gas' accumulated postretirement benefit obligation of $73 million and $61 million, respectively. As a result of regulatory accounting, the remeasurement will have an immaterial impact on net income for both Dominion Energy and Dominion Energy Gas. The discount rate used for the remeasurement was 4.30%. All other assumptions used were consistentregulations provide regulators with the ~~measurement as~~authority to levy substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. These laws and regulations are administered by various federal, state and local agencies. EGTS believes it is in material compliance with all applicable laws and regulations, although many are subject to interpretation that may ultimately be resolved by the courts. Environmental laws and regulations continue to evolve, and EGTS is unable to predict the impact of ~~December 31, 2016.~~

~~During~~ the nine months ended September 30, 2017, Dominion Energy recorded a $7 million ($4 million after-tax) charge, including $6 million ($4 million after-tax) at Dominion Energy Gas, as a result of additional payments associated with the new collective bargaining agreement, which is reflected in otherchanging laws and regulations on its operations and ~~maintenance expense~~financial results.

Refer to "Environmental Laws and Regulations" in ~~their Consolidated Statements~~Berkshire Hathaway Energy's Part I, Item 2 of ~~Income.~~

~~Dominion Energy~~

~~The components of Dominion Energy's provision~~this Form 10-Q for ~~net periodic benefit cost (credit) were as follows:~~

additional information regarding environmental laws and regulations.

Pension Benefits

Other Postretirement Benefits

2017

2016

2017

2016

(millions)

Three Months Ended September 30,

Service cost

$
35

$
30

$
7

$
7

Interest cost

86

79

15

16

Expected return on plan assets

(160
)

(141
)

(32
)

(28
)
Amortization of prior service credit

—

—

(13
)

(9
)
Amortization of net actuarial loss

40

29

3

2

Settlements

1

—

—

—

Net periodic benefit cost (credit)

$
2

$
(3
)

$
(20
)

$
(12
)
Nine Months Ended September 30,

Service cost

$
104

$
87

$
20

$
23

Interest cost

259

234

45

50

Expected return on plan assets

(480
)

(419
)

(95
)

(87
)
Amortization of prior service cost (credit)

1

1

(38
)

(23
)
Amortization of net actuarial loss

121

84

9

5

Settlements

2

—

—

—

Net periodic benefit cost (credit)

$
7

$
(13
)

$
(59
)

$
(32
)

~~Employer Contributions~~

~~During~~

Critical Accounting Estimates

Certain accounting measurements require management to make estimates and judgments concerning transactions that will be settled several years in the nine months ended September 30, 2017, Dominion Energy made no contributions to its defined benefit pension plans or other postretirement benefit plans, except for a $75 million contribution made in January 2017 to Dominion Energy Questar’s qualified pension plan to satisfy a regulatory condition to closing of the Dominion Energy Questar Combination. Dominion Energy expects to contribute approximately $12 million to its other postretirement benefit plans through VEBAs during the remainder of 2017.

~~Dominion Energy Gas~~

~~Dominion Energy Gas participates in certain Dominion Energy benefit plans as described in Note 21 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, impairment of long-lived assets and income taxes. For additional discussion of EGTS' critical accounting estimates, see Item 7 of EGTS' Annual Report on Form 10-K for the year ended December 31, ~~2016. See Note 17 for more information.~~

~~The components of Dominion Energy Gas' provision for net periodic benefit credit for employees represented by collective bargaining units were as follows:~~

Pension Benefits

Other Postretirement Benefits

2017

2016

2017

2016

(millions)

Three Months Ended September 30,

Service cost

$
3

$
3

$
1

$
1

Interest cost

7

7

3

3

Expected return on plan assets

(34
)

(33
)

(7
)

(5
)
Amortization of prior service credit

—

—

(1
)

—

Amortization of net actuarial loss

4

3

1

—

Net periodic benefit credit

$
(20
)

$
(20
)

$
(3
)

$
(1
)
Nine Months Ended September 30,

Service cost

$
11

$
10

$
3

$
4

Interest cost

22

22

9

10

Expected return on plan assets

(105
)

(100
)

(19
)

(17
)
Amortization of prior service credit

—

—

(2
)

—

Amortization of net actuarial loss

12

10

2

1

Net periodic benefit credit

$
(60
)

$
(58
)

$
(7
)

$
(2
)

~~Employer Contributions~~

~~During the nine months ended September 30, 2017, Dominion Energy Gas made~~2022. There have been no contributions to its defined benefit pension plans or other postretirement benefit plans. Dominion Energy Gas expects to contribute approximately $12 million to its other postretirement benefit plans through VEBAs, for both employees represented by collective bargaining units and employees not represented by collective bargaining units, during the remainder of 2017.

~~Note 19. Operating Segments~~

The Companies are organized primarily on the basis of products and services sold in the U.S. In connection with its corporate rebranding, the Companies changed the names of their principal operating segments to Power Delivery, Power Generation and Gas Infrastructure from Dominion Virginia Power, Dominion Generation and Dominion Energy, respectively. A description of the operations included in the Companies’ primary operating segments is as follows:

~~Primary Operating Segment~~	~~Description of Operations~~	~~Dominion Energy~~	~~Virginia Power~~	~~Dominion Energy Gas~~
~~Power Delivery~~	~~Regulated electric distribution~~	X	X
	~~Regulated electric transmission~~	X	X
~~Power Generation~~	~~Regulated electric fleet~~	X	X
	~~Merchant electric fleet~~	X
~~Gas Infrastructure~~	~~Gas transmission and storage~~	X		X
	~~Gas distribution and storage~~	X		X
	~~Gas gathering and processing~~	X		X
	~~LNG import and storage~~	X
	~~Nonregulated retail energy marketing~~	X

~~In addition 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) and the net impact of operations that are discontinued or sold. In addition, Corporate and Other includes specific items attributable to Dominion Energy's operating segments that are not included in profit measures evaluated by executive management in assessing the segments' performance or in allocating resources.

In the nine months ended September 30, 2017, Dominion Energy reported after-tax net expenses of $17 million for specific items in the Corporate and Other segment, with $1 million of net expenses attributable to its operating segments. In the nine months ended September 30, 2016, Dominion Energy reported after-tax net expenses of $63 million for specific items in the Corporate and Other segment, with $22 million of these net expenses attributable to its operating segments.

~~The net expense for specific items attributable to Dominion Energy's operating segments in 2016 primarily related to the impact of the following item:~~

~~A $59 million ($36 million after-tax) charge related to an organizational design initiative, attributable to:~~

~~Power Delivery ($5 million after-tax);~~

~~Gas Infrastructure ($12 million after-tax); and~~

~~Power Generation ($19 million after-tax).~~

~~A $29 million ($18 million after-tax) net gain on investments held in nuclear decommissioning trust funds, attributable to Dominion Generation~~

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

Power
Delivery

Power
Generation

Gas
Infrastructure

Corporate
and Other

Adjustments/
Eliminations

Consolidated
Total

(millions)

Three Months Ended September 30, 2017

Total revenue from external customers

$
580

$
1,931

$
459

$
3

$
206

$
3,179

Intersegment revenue

4

3

204

150

(361
)

—

Total operating revenue

584

1,934

663

153

(155
)

3,179

Net income (loss) attributable to Dominion Energy

138

369

187

(29
)

—

665

Three Months Ended September 30, 2016

Total revenue from external customers

$
614

$
1,947

$
359

$
2

$
210

$
3,132

Intersegment revenue

6

2

205

144

(357
)

—

Total operating revenue

620

1,949

564

146

(147
)

3,132

Net income (loss) attributable to Dominion Energy

139

650

135

(234
)

—

690

Nine Months Ended September 30, 2017

Total revenue from external customers

$
1,664

$
5,091

$
1,949

$
12

$
660

$
9,376

Intersegment revenue

16

8

645

451

(1,120
)

—

Total operating revenue

1,680

5,099

2,594

463

(460
)

9,376

Net income (loss) attributable to Dominion Energy

390

870

613

(186
)

—

1,687

Nine Months Ended September 30, 2016

Total revenue from external customers

$
1,682

$
5,204

$
1,235

$
8

$
522

$
8,651

Intersegment revenue

17

7

507

469

(1,000
)

—

Total operating revenue

1,699

5,211

1,742

477

(478
)

8,651

Net income (loss) attributable to Dominion Energy

363

1,066

483

(246
)

—

1,666

~~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 segments that are not included in profit measures evaluated by executive management in assessing the segments' performance or in allocating resources.

In the nine months ended September 30, 2017, Virginia Power reported after-tax net expenses of $7 million for specific items in the Corporate and Other segment, all of which was attributable to its operating segments. In the nine months ended September 30, 2016, Virginia Power reported an after-tax net expense of $18 million for specific items in the Corporate and Other segment, all of which was attributable to its operating segments.

~~The net expense for specific items attributable to Virginia Power's operating segments in 2017 primarily related to the impact of the following item which was attributable to Power Delivery:~~

~~A $16 million ($10 million after-tax) charge~~ ~~arising from a customer settlement.~~

~~The net expense for specific items attributable to Virginia Power’s operating segments in 2016 primarily related to the impact of the following item:~~

~~A $33 million ($20 million after-tax) charge related to an organizational design initiative, attributable to:~~

~~Power Delivery ($5 million after-tax); and~~

~~Power Generation ($15 million after-tax).~~

~~The following table presents segment information pertaining to Virginia Power’s operations:~~

Power
Delivery

Power
Generation

Corporate
and Other

Consolidated
Total

(millions)

Three Months Ended September 30, 2017

Operating revenue

$
580

$
1,574

$
—

$
2,154

Net income

137

314

8

459

Three Months Ended September 30, 2016

Operating revenue

$
617

$
1,594

$
—

$
2,211

Net income

140

359

4

503

Nine Months Ended September 30, 2017

Operating revenue

$
1,670

$
4,062

$
—

$
5,732

Net income

387

735

11

1,133

Nine Months Ended September 30, 2016

Operating revenue

$
1,686

$
4,191

$
—

$
5,877

Net income (loss)

362

699

(15
)

1,046

~~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 the nine months ended September 30, 2017, Dominion Energy Gas reported after-tax net expenses of $9 million for specific items in the Corporate and Other segment, all of which was attributable to its operating segment. In the nine months ended September 30, 2016, Dominion Energy Gas reported an after-tax net benefit of $5 million for specific items in the Corporate and Other segment, with after-tax net expense of $7 million attributable to its operating segment.

~~The net expense for specific items in 2017 was due to a $15 million ($9 million after-tax)~~ ~~charge to write-off the balance of a regulatory asset no longer considered probable of recovery.~~

~~The net expense for specific items in 2016 primarily related to an $8 million ($5 million after-tax) charge related to an organizational design initiative.~~

~~The following table presents segment information pertaining to Dominion Energy Gas' operations:~~

Gas
Infrastructure

Corporate and
Other

Consolidated
Total

(millions)

Three Months Ended September 30, 2017

Operating revenue

$
401

$
—

$
401

Net income (loss)

121

(4
)

117

Three Months Ended September 30, 2016

Operating revenue

$
382

$
—

$
382

Net income

77

6

83

Nine Months Ended September 30, 2017

Operating revenue

$
1,313

$
—

$
1,313

Net income (loss)

318

(16
)

302

Nine Months Ended September 30, 2016

Operating revenue

$
1,181

$
—

$
1,181

Net income (loss)

288

(2
)

286

~~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's 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 and~~significant changes in ~~water temperatures~~EGTS' assumptions regarding critical accounting estimates since December 31, 2022.

177

Item 3.Quantitative and ~~availability that can cause outages~~Qualitative Disclosures About Market Risk

For quantitative and ~~property damage to facilities;~~

~~Federal, state and local legislative and regulatory developments, including changes in federal and state tax laws and regulations;~~

~~Changes to federal, state and local environmental laws and regulations, including those related to climate change,~~qualitative disclosures about market risk affecting the ~~tightening~~Registrants, see Item 7A 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;~~

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;

•	~~Unplanned outages at facilities in which the Companies have an ownership interest;~~

Fluctuations in energy-related commodity prices and the effect these could have on Dominion Energy’s and Dominion Energy Gas' earnings and the Companies' liquidity position and the underlying value of their assets;

~~Counterparty credit and performance risk;~~

~~Global capital market conditions, including the availability of credit and the ability to obtain financing on reasonable terms;~~

~~Risks associated with Virginia Power’s membership and participation in PJM, including risks related to obligations created by the default of other participants;~~

~~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 interest rates or foreign currency exchange rates;~~

~~Changes in rating agency requirements or credit ratings and their effect on availability and cost of capital;~~

~~Changes in financial or regulatory accounting principles or policies imposed by governing bodies;~~

~~Employee workforce factors including collective bargaining agreements and labor negotiations with union employees;~~

~~Risks of operating businesses in regulated industries that are subject to changing regulatory structures;~~

Impacts of acquisitions, including the Dominion Energy Questar Combination, divestitures, transfers of assets to joint ventures or Dominion Energy Midstream, including the contribution of Dominion Energy Questar Pipeline to Dominion Energy Midstream, and retirements of assets based on asset portfolio reviews;

~~Receipt of approvals for, and timing of, closing dates for acquisitions and divestitures;~~

~~The timing and execution of Dominion Energy Midstream's growth strategy;~~

Changes in rules for regional transmission organizations and independent system operators in which Dominion Energy and Virginia Power participate, including changes in rate designs, changes in FERC's interpretation of market rules and new and evolving capacity models;

~~Political and economic conditions, including inflation and deflation;~~

~~Domestic terrorism and other threats to the Companies' physical and intangible assets, as well as threats to cybersecurity;~~

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 and processing 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;

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 Virginia Power's service territory in connection with FERC Order 1000;~~

~~Changes in technology, particularly with respect to new, developing or alternative sources of generation and smart grid technologies;~~

Changes to regulated electric rates collected by Virginia Power and regulated gas distribution, transportation and storage rates, including LNG storage, collected by Dominion Energy and Dominion Energy Gas;

~~Changes in operating, maintenance and construction costs;~~

~~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;~~

•	~~Adverse outcomes in litigation matters or regulatory proceedings; and~~

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.

~~Additionally, other risks that could cause actual results to differ from predicted results are set forth in Item 1A. Risk Factors in the Companies'~~each Registrant's Annual Report on Form 10-K for the year ended December 31, ~~2016.~~

~~The Companies' forward-looking statements are based~~2022. Each Registrant's exposure to market risk and its management of such risk has not changed materially since December 31, 2022. Refer to Note 7 of the Notes to Consolidated Financial Statements of PacifiCorp, Note 7 of the Notes to Consolidated Financial Statements of Nevada Power and Note 6 of the Notes to Consolidated Financial Statements of Sierra Pacific in Part I, Item 1 of this Form 10-Q for disclosure of the respective Registrant's derivative positions as of March 31, 2023.

Item 4.Controls and Procedures

At the end of the period covered by this Quarterly Report on ~~beliefs~~Form 10-Q, each of Berkshire Hathaway Energy Company, PacifiCorp, MidAmerican Funding, LLC, MidAmerican Energy Company, Nevada Power Company, Sierra Pacific Power Company, Eastern Energy Gas Holdings, LLC and ~~assumptions using~~Eastern Gas Transmission and Storage, Inc. carried out separate evaluations, under the supervision and with the participation of each such entity's management, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, of the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended). Based upon these evaluations, management of each such entity, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, in each case, concluded that the disclosure controls and procedures for such entity were effective to ensure that information ~~available at~~required to be disclosed by such entity in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the ~~statements~~United States Securities and Exchange Commission's rules and forms, and is accumulated and communicated to its management, including its Chief Executive Officer (principal executive officer) and its Chief Financial Officer (principal financial officer), or persons performing similar functions, in each case, as appropriate to allow timely decisions regarding required disclosure by it. Each such entity hereby states that there has been no change in its internal control over financial reporting during the quarter ended March 31, 2023 that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.

178

PART II

Item 1.Legal Proceedings

Berkshire Hathaway Energy and PacifiCorp

Multiple lawsuits, complaints and demands alleging similar claims totaling approximately $8.0 billion have been filed in Oregon and California related to the 2020 Wildfires. Multiple complaints have also been filed in California for the 2022 McKinney fire. Generally, the complaints filed in California do not specify damages sought. Investigations into the causes and origins of those wildfires are ~~made.~~ongoing. For more information regarding certain legal proceedings affecting Berkshire Hathaway Energy, refer to Note 9 of the Notes to Consolidated Financial Statements of Berkshire Hathaway Energy in Part I, Item 1 of this Form 10-Q, and PacifiCorp, refer to Note 9 of the Notes to Consolidated Financial Statements of PacifiCorp in Part I, Item 1 of this Form 10-Q.

On September 30, 2020, a putative class action complaint against PacifiCorp was filed, captioned Jeanyne James et al. v. PacifiCorp et al., Case No. 20CV33885, Circuit Court, Multnomah County, Oregon. The ~~Companies caution~~complaint was filed by Oregon residents and businesses who seek to represent a class of all Oregon citizens and entities whose real or personal property was harmed beginning on September 7, 2020, by wildfires in Oregon allegedly caused by PacifiCorp. On November 3, 2021, the ~~reader~~plaintiffs filed an amended complaint to limit the class to include Oregon citizens allegedly impacted by the Echo Mountain Complex, South Obenchain, Two Four Two and Santiam Canyon fires, as well as to add claims for noneconomic damages. The amended complaint alleges that PacifiCorp's assets contributed to the Oregon wildfires occurring on or after September 7, 2020 and that PacifiCorp acted with gross negligence, among other things. The amended complaint seeks the following damages for the plaintiffs and the putative class: (i) noneconomic damages, including mental suffering, emotional distress, inconvenience and interference with normal and usual activities, in excess of $1 billion; (ii) damages for real and personal property and other economic losses of not less than $600 million; (iii) double the amount of property and economic damages; (iv) treble damages for specific costs associated with loss of timber, trees and shrubbery; (v) double the damages for the costs of litigation and reforestation; (vi) prejudgment interest; and (vii) reasonable attorney fees, investigation costs and expert witness fees. The plaintiffs demand a trial by jury and have reserved their right to further amend the complaint to allege claims for punitive damages. In May 2022, the Multnomah Circuit Court granted issue class certification and consolidated this case with others as described below. PacifiCorp requested an immediate appeal of the issue class certification before the Oregon Court of Appeals. In January 2023, the Oregon Court of Appeals denied PacifiCorp's request for appeal. In February 2023, the plaintiffs filed a motion to amend the complaint to add punitive damages in an unspecified amount. On March 23, 2023, the plaintiffs filed an amended complaint seeking punitive damages with permission of the Circuit Court. Plaintiffs seek punitive damages at a five times multiplier to the amount of compensatory damages awarded. On April 24, 2023, the jury trial began in Multnomah County Circuit Court.

On August 20, 2021, a complaint against PacifiCorp was filed, captioned Shylo Salter et al. v. PacifiCorp, Case No. 21CV33595, Multnomah County, Oregon, in which two complaints, Case No. 21CV09339 and Case No. 21CV09520, previously filed in Circuit Court, Marion County, Oregon, were combined. The plaintiffs voluntarily dismissed the previously filed complaints in Marion County, Oregon. The refiled complaint was filed by Oregon residents and businesses who allege that they were injured by the Beachie Creek fire, which the plaintiffs allege began on or around September 7, 2020, but which government reports indicate began on or around August 16, 2020. The complaint alleges that PacifiCorp's assets contributed to the Beachie Creek fire and that PacifiCorp acted with gross negligence, among other things. The complaint seeks the following damages: (i) damages related to real and personal property in an amount determined by the jury to be fair and reasonable, estimated not to ~~place undue reliance~~exceed $75 million; (ii) other economic losses in an amount determined by the jury to be fair and reasonable, but not to exceed $75 million; (iii) noneconomic damages in the amount determined by the jury to be fair and reasonable, but not to exceed $500 million; (iv) double the damages for economic and property damages under specified Oregon statutes; (v) alternatively, treble the damages under specified Oregon statutes; (vi) attorneys' fees and other costs; and (vii) pre- and post-judgment interest. The plaintiffs demand a trial by jury and have reserved their right to amend the complaint with an intent to add a claim for punitive damages. In May 2022, this case was consolidated with others as described below.

179

On March 17, 2022, a complaint against PacifiCorp was filed, captioned Roseburg Resources Co et al. v. PacifiCorp, Case No. 22CV09346, Circuit Court, Douglas County, Oregon. The complaint was filed by nine businesses and public pension plans that own and/or operate timberlands or possess property in Douglas County who allege damages, losses and injuries associated with their timberlands as a result of the French Creek, Archie Creek, Susan Creek and Smith Springs Road fires in Douglas County in September 2020. The complaint alleges (i) PacifiCorp's conduct constituted not only common law negligence but also gross negligence and that such conduct contributed to or caused the ignition and spread of the aforementioned fires; (ii) PacifiCorp violated certain Oregon rules and regulations; and (iii) as an alternative to negligence, inverse condemnation. The complaint seeks the following damages as amended: (i) economic and property damages in excess of $195 million under a determination of negligence or inverse condemnation; (ii) doubling of those economic damages to in excess of $390 million under a determination of gross negligence pursuant to Oregon statutes; (iii) all costs of the lawsuit; (iv) prejudgment interest of $43 million and post-judgment interest as allowed by law; and (v) attorneys' fees of $105 million and other costs.

In May 2022, the Multnomah County Circuit Court granted plaintiffs' motion to consolidate Shylo Salter et al. v. PacifiCorp, Case No. 21CV33595 (described above) and Amy Allen, et al. v. PacifiCorp, Case No. 20CV37430 ("Allen") into Jeanyne James et al. v. PacifiCorp et al., Case No. 20CV33885 (described above). Plaintiffs' motion to bifurcate issues for trial between class-wide liability and individual damages was also granted. The Allen case was filed by five individuals as amended in September 2021 claiming in excess of $32 million in economic and noneconomic damages, as well as claims for statutory doubling or trebling of damages, attorneys' fees and other costs and pre- and post-judgment interest.

On August 26, 2022, a putative class action complaint seeking declaratory and equitable relief against PacifiCorp was filed, captioned Margaret Dietrich et al. v. PacifiCorp, Case No. 22CV29187, Circuit Court, Multnomah County, Oregon. The complaint was filed by two Oregon residents individually and on ~~their forward-looking statements because the assumptions, beliefs, expectations~~behalf of a class initially defined to include residents of, business owners in, real or personal property owners in 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~~

Asother individuals physically present in specified Oregon counties as of September ~~30, 2017, there~~7, 2020 who experienced any harm, damage or loss as a result of the Santiam, Beachie Creek, Lionshead, Echo Mountain Complex, Two Four Two or South Obenchain fires in September 2020. The complaint was amended on September 6, 2022, to seek damages of over $900 million that were originally demanded on August 4, 2022, pursuant to Oregon Rule of Civil Procedure 32 H. The amended complaint alleges: (i) negligence due to alleged failure to comply with certain Oregon statutes and administrative rules; (ii) gross negligence due to alleged conscious indifference to or reckless disregard for the probable consequences of defendant's actions or inactions; (iii) private nuisance; (iv) public nuisance; (v) trespass; (vi) inverse condemnation; (vii) accounting/injunction; (viii) negligent infliction of emotional distress. The amended complaint seeks the following: (i) an order certifying the matter as a class action; (ii) economic damages not less than $400 million; (iii) double the amount of economic and property damages to the extent applicable under Oregon statute; (iv) reasonable costs of reforestation activities; (v) doubling and trebling of certain other damages to the extent applicable under certain Oregon statutes; (vi) noneconomic damages not less than $500 million; (vii) prejudgment interest; (viii) an order requiring an accounting with respect to the amount of damages; (ix) an order enjoining PacifiCorp from leaving power lines energized in areas of Oregon experiencing extremely critical fire conditions; (x) an award of reasonable attorney fees, costs, investigation costs, disbursements and expert witness fees; and (xi) other relief the court finds appropriate. The plaintiffs and proposed class demand a trial by jury. On December 19, 2022, the Dietrich case was consolidated into Jeanyne James et al. v. PacifiCorp et al., Case No. 20CV33885 (described above) and is currently stayed.

On September 1, 2022, a complaint against PacifiCorp was filed, captioned Martin Klinger et al. v. PacifiCorp, Case No. 22CV29674, Multnomah County, Oregon ("Klinger"). The complaint was filed by Oregon residents or Oregon property owners who allege damages resulting from the September 2020 Echo Mountain Complex fires. The allegations made and damages sought are described below.

On September 1, 2022, a complaint against PacifiCorp was filed, captioned Jeremiah E. Bowen et al. v. PacifiCorp, Case No. 22CV29681, Multnomah County, Oregon ("Bowen"). The complaint was filed by Oregon residents, occupants and real and personal property owners who allege injuries and damages resulting from the September 2020 Echo Mountain Complex fires. The allegations made and damages sought are described below.

On September 1, 2022, a complaint against PacifiCorp was filed, captioned James Weathers et al. v. PacifiCorp, Case No. 22CV29683, Multnomah County, Oregon ("Weathers"). The complaint was filed by Oregon residents, occupants and real and personal property owners who allege injuries and damages resulting from the September 2020 Echo Mountain Complex fires. The allegations made and damages sought are described below.

On September 6, 2022, a complaint against PacifiCorp was filed, captioned Blair Barnholdt et al. v. PacifiCorp, Case No. 22CV30097, Multnomah County, Oregon ("Barnholdt"). The complaint was filed by Oregon residents or Oregon property owners who allege damages resulting from the September 2020 Echo Mountain Complex fires. The allegations made and damages sought are described below.

180

On September 7, 2022, a complaint against PacifiCorp was filed, captioned Estate of Nancy Darlene Hunter, et al. v. PacifiCorp, Case No. 22CV30214, Multnomah County, Oregon ("Hunter"). The complaint was filed by Oregon residents, occupants and real and personal property owners who allege injuries and damages resulting from the September 2020 Echo Mountain Complex fires. The allegations made and damages sought are described below.

On September 7, 2022, a complaint against PacifiCorp was filed, captioned Willard K. Pratt et al. v. PacifiCorp, Case No. 22CV30217, Multnomah County, Oregon ("Pratt"). The complaint was filed by Oregon residents, occupants and real and personal property owners who allege injuries and damages resulting from the September 2020 Echo Mountain Complex fires. The allegations made and damages sought are described below.

On September 7, 2022, a complaint against PacifiCorp was filed, captioned April Thompson et al. v. PacifiCorp, Case No. 22CV30451, Multnomah County, Oregon ("Thompson"). The complaint was filed by Oregon residents, occupants and real and personal property owners who allege injuries and damages resulting from the September 2020 Echo Mountain Complex fires. The allegations made and damages sought are described below.

The Klinger, Bowen, Weathers, Barnholdt, Hunter, Pratt and Thompson cases are in the process of being consolidated with Sparkset al. v. PacifiCorp, Case No. 21CV48022 ("Sparks")and Russieet al. v. PacifiCorp, Case No. 22CV15840 ("Russie") into Ashley Andersen et al. v. PacifiCorp, Case No. 21CV36567 ("Andersen"). The Klinger, Bowen, Weathers, Barnholdt, Pratt and Thompson complaints each allege: (i) negligence due in part to alleged failure to comply with certain Oregon statutes and administrative rules, including those issued by the OPUC; (ii) gross negligence alleged in the form of willful, wanton and reckless disregard of known risks to the public; (iii) trespass; (iv) nuisance; and (v) inverse condemnation. The Klinger, Bowen, Weathers, Barnholdt, Pratt and Thompson complaints each seek the following damages: (i) economic and property related damages of $83 million; (ii) doubling of those economic and property related damages to $167 million to the extent eligible for doubling of damages under the specified Oregon statute; (iii) non-economic damages to the plaintiffs' persons in an amount not less than $83 million for physical injury, mental suffering, emotional distress and other damages; (iv) loss of wages, loss of earnings capacity, evacuation expenses, displacement expenses and similar damages; (v) attorneys' fees and other costs; and (vii) pre-judgment interest. The plaintiffs for each Klinger, Bowen, Weathers, Barnholdt, Pratt and Thompson request a trial by jury and have reserved their right to amend the complaint to add a claim for punitive damages. The Hunter complaint seeks $50 million in damages and alleges claims for: (i) negligence, (ii) trespass, (iii), nuisance, (iv) inverse condemnation, and (v) wrongful death. The Andersen case was filed by 50 individuals as amended in August 2022 seeking $250 million in economic and noneconomic damages, as well as claims for statutory doubling or trebling of damages, attorneys' fees and other costs and pre-judgment interest. The Sparks case was filed by 17 individuals in December 2021 claiming $125 million in economic and noneconomic damages, as well as claims for statutory doubling or trebling of damages, attorneys' fees and other costs and pre- judgment interest. The Russie case was filed by 45 individuals as amended in September 2022 seeking $250 million in economic and noneconomic damages, as well as claims for statutory doubling or trebling of damages, attorneys' fees and other costs and pre-judgment interest.

On September 1, 2022, a complaint against PacifiCorp was filed, captioned Aaron Macy-Wyngarden et al. v. PacifiCorp, Case No. 22CV29684, Multnomah County, Oregon ("Macy-Wyngarden"). The complaint was filed by Oregon residents or Oregon property owners who allege injuries and damages resulting from the September 2020 Beachie Creek, Santiam Canyon, Lionshead and Riverside fires. The allegations made and damages sought are described below.

On September 22, 2022, a complaint against PacifiCorp was filed, captioned Zachary Bogle et al. v. PacifiCorp, Case No. 22CV29717, Multnomah County, Oregon ("Bogle"). The complaint was filed by Oregon residents who allege injuries and damages resulting from the September 2020 Beachie Creek, Santiam Canyon, Lionshead and Riverside fires. The allegations made and damages sought are described below.

The Macy-Wyngarden and Bogle complaints each allege: (i) negligence due in part to alleged failure to comply with certain Oregon statutes and administrative rules, including those issued by the OPUC; (ii) gross negligence alleged in the form of willful, wanton and reckless disregard of known risks to the public; (iii) trespass; (iv) nuisance; and (v) inverse condemnation. The Macy-Wyngarden and Bogle complaints each seek the following damages: (i) economic and property related damages of $83 million; (ii) doubling of those economic and property related damages to $167 million to the extent eligible for doubling of damages under the specified Oregon statute; (iii) non-economic damages to the plaintiffs' persons in an amount not less than $83 million for physical injury, mental suffering, emotional distress and other damages; (iv) loss of wages, loss of earnings capacity, evacuation expenses, displacement expenses and similar damages; (v) attorneys' fees and other costs; and (vii) pre-judgment interest. The plaintiffs for each Macy-Wyngarden and Bogle request a trial by jury and have reserved their right to amend the complaint to add a claim for punitive damages.

181

On September 2, 2022, a complaint against PacifiCorp was filed, captioned Logan et al. v. PacifiCorp, Case No. 22CV29859, Multnomah County, Oregon ("Logan"). The Logan complaint was filed by Oregon residents or Oregon property owners who allege injuries and damages resulting from the September 2020 Echo Mountain Complex fires. The Logan case is in the process of being consolidated with Cady et al. v. PacifiCorp, Case No. 22CV13946 ("Cady") into Jeanyne James et al. v. PacifiCorp et al., Case No. 20CV33885 (described above). The Logan and Cady complaints each allege: (i) negligence; (ii) trespass; (iii) nuisance, and (iv) inverse condemnation. The Logan case was filed by five individuals claiming $10 million in economic and noneconomic damages, as well as claims for statutory doubling or trebling of damages, attorneys' fees and other costs and pre- and post-judgment interest. The Cady case was filed by 21 individuals as amended in April 2022 claiming $10 million in economic and noneconomic damages, as well as claims for statutory doubling or trebling of damages, attorneys' fees and other costs and pre-judgment interest.

On October 14, 2022, the Multnomah County Circuit Court consolidated 21st Century Centennial Insurance Company, et al. v. PacifiCorp, Case No. 22CV26326 ("21st Century") and Allstate Vehicle and Property Insurance Company, et al. v. PacifiCorp, Case No. 22CV29976 into Jeanyne James et al. v. PacifiCorp et al., Case No. 20CV33885 (described above). The 21st Century and Allstate complaints were each filed by subrogated insurance carriers alleging claims of (i) negligence, (ii) gross negligence, and (iii) inverse condemnation resulting from the September 2020 Santiam Canyon, Echo Mountain Complex, 242, and South Obenchain fires. The 21st Century case was filed in August 2022 by 177 insurance carriers seeking $20 million in damages. The Allstate case was filed in September 2022 by 11 insurance carriers seeking $40 million in damages.

On October 17, 2022, the Multnomah County Circuit Court consolidated Michael Bell, et al. v. PacifiCorp, Case No. 22CV30450 ("Bell") into Jeanyne James et al. v. PacifiCorp et al., Case No. 20CV33885 (described above). The Bell case was filed in Oregon Circuit Court in Multnomah County, Oregon on September 7, 2022, by 59 plaintiffs seeking $35 million in damages for claims of (i) negligence, (ii) trespass, (iii) nuisance, and (iv) inverse condemnation.

On October 19, 2022, the Multnomah County Circuit Court consolidated Freres Timber, Inc. v. PacifiCorp, Case No. 22CV29694 ("Freres") into Jeanyne James et al. v. PacifiCorp et al., Case No. 20CV33885 (described above). The Freres case was filed in Oregon Circuit Court in Multnomah County, Oregon on September 1, 2022, by one plaintiff and seeks $40 million for claims of (i) negligence, (ii) gross negligence, and (iii) inverse condemnation.

On November 1, 2022, three complaints were filed against PacifiCorp, captioned Moore et al. v. PacifiCorp, No. 22CV37302; Blodgett et al. v. PacifiCorp, No. 22CV37306; and Ellis et al. v. PacifiCorp, No. 22CV37304. Three additional cases were filed December 5, 2022, captioned Tague et al. v. PacifiCorp, No. 22CV41242; Long, et al. v. PacifiCorp, No. 22CV41283; and Moyers et al. v. PacifiCorp, No. 22CV41293. On January 6, 2023, an additional complaint was filed against PacifiCorp captioned Meyer et al. v. PacifiCorp, No. 23CV00748. On January 17, 2023, seven additional cases were filed, captioned Foster et al. v. PacifiCorp, No. 23CV02142; Hall et al. v. PacifiCorp, No. 23CV02184; Joneset al. v. PacifiCorp, No. 23CV02110; Price et al. v. PacifiCorp, No. 23CV02175; Minottet al. v. PacifiCorp, No. 23CV02203; Webbet al. v. PacifiCorp, No. 23CV02202; and Keithet al. v. PacifiCorp, No. 23CV02200. On January 24, 2023, three additional cases were filed captioned Kiddet al. v. PacifiCorp, No. 23CV03318; Parkeret al. v. PacifiCorp, No. 23CV03317; and Diazet al. v. PacifiCorp, No. 23CV03313. These complaints were filed in Circuit Courts, Douglas County and Multnomah County, Oregon with substantially similar allegations as those of the Roseburg Resources Co case with the exception that certain of the complaints do not allege inverse condemnation. On February 9, 2023, in an oral ruling, the Circuit Court ordered these seventeen cases consolidated for trial as to certain specified issues, along with the above mentioned Roseburg Resources Co case; the precise scope of the trial will be determined in a later order. Collectively, these eighteen cases seek in excess of $1,300 million in damages, inclusive of the $573 million Roseburg Resources Co case. On February 14, 2023, the Circuit Court ordered that all plaintiffs' claims for inverse condemnation be dismissed; a written order is forthcoming.

On December 6, 2022, CW Specialty Lumber, Inc., et al. v. PacifiCorp, Case No. 22CV41640 ("CW Specialty") was filed in Oregon Circuit Court in Multnomah County, Oregon by two plaintiffs seeking $28.6 million in damages for claims of (i) negligence, (ii) gross negligence, (iii) trespass, and (iv) inverse condemnation. The CW Specialty case is in the process of being consolidated into Jeanyne James et al. v. PacifiCorp et al., Case No. 20CV33885 (described above).

Item 1A.Risk Factors

There has been no ~~significant changes with regard~~material change to ~~the critical accounting policies and estimates~~each Registrant's risk factors from those disclosed in ~~MD&A in the Companies'~~Item 1A of each Registrant's Annual Report on Form 10-K for the year ended December 31, ~~2016. The policies disclosed included the accounting for regulated operations, AROs, income taxes, derivative contracts~~2022.

Item 2.Unregistered Sales of Equity Securities and Use of Proceeds

Not applicable.

182

Item 3.Defaults Upon Senior Securities

Not applicable.

Item 4.Mine Safety Disclosures

Information regarding Berkshire Hathaway Energy's and PacifiCorp's mine safety violations and other ~~instruments at fair value, goodwill~~legal matters disclosed in accordance with Section 1503(a) of the Dodd-Frank Wall Street Reform and ~~long-lived asset impairment testing and employee benefit plans.~~

~~Dominion Energy~~

~~Results of Operations~~

~~Presented below~~Consumer Protection Act is included in Exhibit 95 to this Form 10-Q.

Item 5.Other Information

Not applicable.

Item 6.Exhibits

The following is a ~~summary~~list of ~~Dominion Energy’s consolidated results:~~

2017

2016

$ Change

(millions, except EPS)

Third Quarter

Net income attributable to Dominion Energy

$
665

$
690

$
(25
)
Diluted EPS

1.03

1.10

(0.07
)
Year-To-Date

Net income attributable to Dominion Energy

$
1,687

$
1,666

$
21

Diluted EPS

2.66

2.71

(0.05
)

~~Overview~~

~~Third Quarter 2017 vs. 2016~~

Net income attributable to Dominion Energy decreased 4%, primarily due to lower anticipated renewable energy investment tax credits, milder weather during 2017 in Dominion Energy’s electric utility service territory and a decrease in Cove Point import contracts. These decreases were partially offset by the Dominion Energy Questar Combination and an increase in gains from agreements to convey shale development rights underneath several natural gas storage fields.

~~Year-To-Date 2017 vs. 2016~~

~~Net income attributable to Dominion Energy increased 1%, primarily due to the Dominion Energy Questar Combination, an electric utility capacity benefit and the absence~~exhibits filed as part of 2016 organizational design initiative costs. These increases were substantially offset by lower anticipated renewable energy investment tax credits, an increase in interest expense, milder weather in Dominion Energy’s electric utility service territory and a decrease in Cove Point import contracts.

this Quarterly Report.

~~Analysis of Consolidated Operations~~

~~Presented below are selected amounts related to Dominion Energy’s results of operations:~~

Third Quarter

Year-To-Date

2017

2016

$ Change

2017

2016

$ Change

(millions)

Operating revenue

$
3,179

$
3,132

$
47

$
9,376

$
8,651

$
725

Electric fuel and other energy-related purchases

638

606

32

1,711

1,791

(80
)
Purchased (excess) electric capacity

21

(6
)

27

(8
)

107

(115
)
Purchased gas

24

77

(53
)

441

252

189

Net revenue

2,496

2,455

41

7,232

6,501

731

Other operations and maintenance

649

765

(116
)

2,166

2,133

33

Depreciation, depletion and amortization

485

400

85

1,421

1,112

309

Other taxes

162

145

17

519

448

71

Other income

73

63

10

249

189

60

Interest and related charges

305

250

55

905

715

190

Income tax expense

272

230

42

683

561

122

Noncontrolling interests

31

38

(7
)

100

55

45

~~An analysis of Dominion Energy’s results of operations follows:~~

~~Third Quarter 2017 vs. 2016~~

~~Net revenue~~ ~~increased 2%, primarily reflecting:~~

~~A $161 million increase from the operations acquired in the Dominion Energy Questar Combination being included for all of 2017;~~

183

~~A $29 million increase due to additional generation output from merchant solar generating projects; and~~

~~A $16 million increase from regulated natural gas transmission growth projects placed into service; partially offset by~~

~~A $76 million decrease in sales to electric utility retail customers from a decrease in cooling degree days;~~

~~A $41 million decrease from Cove Point import contracts;~~

A $24 million increase in electric capacity related expenses due to the annual PJM capacity performance market effective June 2017 ($68 million), partially offset by a benefit related to non-utility generators ($44 million); and

~~A $20 million decrease due to unfavorable pricing at merchant generation facilities.~~

~~Other operations and maintenance~~ ~~decreased 15%, primarily reflecting:~~

~~A $56 million increase in gains from agreements to convey shale development rights underneath several natural gas storage fields;~~

~~A $30 million decrease in certain electric transmission-related expenditures. These expenses are primarily recovered through state and FERC rates and do not impact net income;~~

~~A $26 million decrease in transaction and transition costs related to the Dominion Energy Questar Combination; and~~

~~A $21 million decrease due to the absence of costs related to 2016 labor contract renegotiations as well as costs resulting from a union workforce temporary work stoppage; partially offset by~~

~~A $45 million increase from the operations acquired in the Dominion Energy Questar Combination being included for all of 2017.~~

~~Depreciation, depletion and amortization~~ increased 21%, primarily due to the operations acquired in the Dominion Energy Questar Combination being included for all of 2017 ($47 million) and various growth projects being placed into service ($40 million).

~~Interest and related charges~~ ~~increased 22%, primarily due to higher long-term debt interest expense resulting from debt issuances in the fourth quarter of 2016 and the first nine months of 2017($41 million) and debt acquired in the Dominion Energy Questar Combination ($11 million).~~

~~Income tax expense~~ ~~increased 18%, primarily due to an increased effective tax rate, principally due to lower anticipated renewable energy investment tax credits.~~

~~Noncontrolling interests~~ decreased 18% primarily due to a decrease in earnings attributable to merchant solar partners ($22 million), partially offset by an increase in Dominion Energy Midstream earnings attributable to public unit holders ($15 million).

~~Year-To-Date 2017 vs. 2016~~

~~Net revenue~~ ~~increased 11%, primarily reflecting:~~

~~A $663 million increase from the operations acquired in the Dominion Energy Questar Combination being included for all of 2017;~~

A $119 million electric capacity benefit due to the annual PJM capacity performance market effective June 2016 ($123 million) and a benefit related to non-utility generators ($86 million), partially offset by the annual PJM capacity performance market effective June 2017 ($90 million);

~~A $74 million increase due to additional generation output from merchant solar generating projects;~~

~~A $57 million increase in sales to electric utility retail customers due to the effect of changes in customer usage and other factors;~~

~~A $49 million increase from regulated natural gas transmission growth projects placed into service; and~~

~~A $36 million increase from rate adjustment clauses associated with electric utility operations; partially offset by~~

~~A $109 million decrease due to unfavorable pricing at merchant generation facilities;~~

~~A $104 million decrease from Cove Point import contracts; and~~

A decrease in sales to electric utility retail customers from a reduction in heating degree days during the heating season of 2017 ($52 million) and a decrease in cooling degree days during the cooling season of 2017 ($53 million).

~~Other operations and maintenance~~ ~~increased 2%, primarily reflecting:~~

~~A $162 million increase from the operations acquired in the Dominion Energy Questar Combination being included for all of 2017; and~~

~~A $35 million increase in salaries, wages and benefits; partially offset by~~

~~An $88 million decrease in certain electric transmission-related expenditures. These expenses are primarily recovered through state and FERC rates and do not impact net income; and~~

~~The absence of organizational design initiative costs ($64 million).~~

~~Depreciation, depletion and amortization~~ increased 28%, primarily due to the operations acquired in the Dominion Energy Questar Combination being included for all of 2017 ($162 million) and various growth projects being placed into service ($120 million).

~~Other taxes~~ increased 16%, primarily due to the operations acquired in the Dominion Energy Questar Combination being included for all of 2017 ($35 million) and increased property taxes related to growth projects placed into service ($31 million).

~~Other income~~ ~~increased 32%, primarily reflecting:~~

~~A $26 million increase in earnings from equity method investments;~~

~~A $19 million increase in AFUDC associated with rate-regulated projects;~~

~~An $11 million increase in interest income associated with the settlement of state income tax refund claims; and~~

~~An $11 million increase in net realized gains (including investment income) on nuclear decommissioning trust funds.~~

~~Interest and related charges~~ increased 27%, primarily due to higher long-term debt interest expense resulting from debt issuances in 2016 and the first nine months of 2017 ($148 million) and debt acquired in the Dominion Energy Questar Combination ($39 million).

~~Income tax expense~~ ~~increased 22%, primarily due to higher pre-tax income and an increased effective tax rate, principally due to lower anticipated renewable energy investment tax credits.~~

~~Noncontrolling interests~~ ~~increased 82%, primarily due to an increase in Dominion Energy Midstream earnings attributable to public unitholders.~~

~~Segment Results of Operations~~

Segment results include the impact of intersegment revenues and expenses, which may result in intersegment profit and loss. In connection with its corporate rebranding in May 2017, Dominion Energy changed the names of its principal operating segments to Power Delivery, Power Generation and Gas Infrastructure from Dominion Virginia Power, Dominion Generation and Dominion Energy, respectively. Presented below is a summary of contributions by Dominion Energy’s operating segments to net income attributable to Dominion Energy:

Net Income attributable to
Dominion Energy

Diluted EPS

2017

2016

$ Change

2017

2016

$ Change

(millions, except EPS)

Third Quarter

Power Delivery

$
138

$
139

$
(1
)

$
0.21

$
0.22

$
(0.01
)
Power Generation

369

650

(281
)

0.57

1.04

(0.47
)
Gas Infrastructure

187

135

52

0.29

0.21

0.08

Primary operating segments

694

924

(230
)

1.07

1.47

(0.40
)
Corporate and Other

(29
)

(234
)

205

(0.04
)

(0.37
)

0.33

Consolidated

$
665

$
690

$
(25
)

$
1.03

$
1.10

$
(0.07
)
Year-To-Date

Power Delivery

$
390

$
363

$
27

$
0.62

$
0.59

$
0.03

Power Generation

870

1,066

(196
)

1.37

1.74

(0.37
)
Gas Infrastructure

613

483

130

0.97

0.78

0.19

Primary operating segments

1,873

1,912

(39
)

2.96

3.11

(0.15
)
Corporate and Other

(186
)

(246
)

60

(0.30
)

(0.40
)

0.10

Consolidated

$
1,687

$
1,666

$
21

$
2.66

$
2.71

$
(0.05
)

~~Power Delivery~~

~~Presented below are selected operating statistics related to Power Delivery’s operations:~~

Third Quarter

Year-To-Date

2017

2016

% Change

2017

2016

% Change

Electricity delivered (million MWh)

23.0

24.1

(5
)%

63.2

64.2

(2
)%
Degree days (electric distribution service area):

Cooling

1,124

1,326

(15
)

1,698

1,755

(3
)
Heating

2

—

100

1,825

2,247

(19
)
Average electric distribution customer accounts
(thousands)⁽¹⁾

2,576

2,552

1

2,570

2,546

1

~~(1)~~	~~Period average.~~
Exhibit No.			Description

~~Presented below, on an after-tax basis, are the key factors impacting Power Delivery’s net income contribution:~~

Third Quarter
2017 vs. 2016
Increase (Decrease)

Year-To-Date
2017 vs. 2016
Increase (Decrease)

Amount

EPS

Amount

EPS

(millions, except EPS)

Regulated electric sales:

Weather

$
(13
)

$
(0.02
)

$
(19
)

$
(0.03
)
Other

1

—

12

0.02

FERC transmission equity return

5

0.01

14

0.02

Storm damage and service restoration

3

—

17

0.03

Other

3

—

3

—

Share dilution

—

—

—

(0.01
)
Change in net income contribution

$
(1
)

$
(0.01
)

$
27

$
0.03

~~Power Generation~~

~~Presented below are selected operating statistics related to Power Generation’s operations:~~

Third Quarter

Year-To-Date

2017

2016

% Change

2017

2016

% Change

Electricity supplied (million MWh):

Utility

23.1

24.8

(7
)%

64.7

67.1

(4
)%
Merchant

7.9

7.9

—

22.7

21.2

7

Degree days (electric utility service area):

Cooling

1,124

1,326

(15
)

1,698

1,755

(3
)
Heating

2

—

100

1,825

2,247

(19
)

~~Presented below, on an after-tax basis, are the key factors impacting Power Generation’s net income contribution:~~

Third Quarter
2017 vs. 2016
Increase (Decrease)

Year-To-Date
2017 vs. 2016
Increase (Decrease)

Amount

EPS

Amount

EPS

(millions, except EPS)

Regulated electric sales:

Weather

$
(33
)

$
(0.05
)

$
(45
)

$
(0.07
)
Other

6

0.01

27

0.04

Electric capacity

(16
)

(0.03
)

70

0.11

Renewable energy investment tax credits⁽¹⁾

(242
)

(0.39
)

(187
)

(0.31
)
Merchant generation margin

6

0.01

(9
)

(0.02
)
Noncontrolling interests⁽²⁾

14

0.02

1

—

Depreciation and amortization

(12
)

(0.02
)

(38
)

(0.06
)
Other

(4
)

(0.01
)

(15
)

(0.02
)
Share dilution

—

(0.01
)

—

(0.04
)
Change in net income contribution

$
(281
)

$
(0.47
)

$
(196
)

$
(0.37
)
BERKSHIRE HATHAWAY ENERGY

~~(1)~~

~~Tax credit is reflected in Power Generation segment once project is placed into service.~~

~~(2)~~

~~Represents noncontrolling interests related to merchant solar partnerships.~~

~~Gas Infrastructure~~

~~Presented below are selected operating statistics related to Gas Infrastructure’s operations:~~

Third Quarter

Year-To-Date

2017

2016

% Change

2017

2016

% Change

Gas distribution throughput (bcf)⁽¹⁾:

Sales

10

2

400
%

85

18

372
%
Transportation

143

106

35

469

364

29

Heating degree days (gas distribution service area):

Eastern region

66

22

200

2,940

3,435

(14
)
Western region⁽¹⁾

131

39

236

3,024

39

7,654

Average gas distribution customer accounts
(thousands)⁽¹⁾⁽²⁾:

Sales

1,234

472

161

1,234

329

275

Transportation

1,082

1,069

1

1,089

1,072

2

Average retail energy marketing customer accounts
(thousands)⁽²⁾

1,463

1,377

6

1,447

1,368

6

~~(1)~~

~~Includes Dominion Energy Questar effective September 2016.~~

~~(2)~~

~~Period average.~~

~~Presented below, on an after-tax basis, are the key factors impacting Gas Infrastructure’s net income contribution:~~

Third Quarter
2017 vs. 2016
Increase (Decrease)

Year-To-Date
2017 vs. 2016
Increase (Decrease)

Amount

EPS

Amount

EPS

(millions, except EPS)

Dominion Energy Questar Combination

$
34

$
0.05

$
184

$
0.30

Assignment of Marcellus acreage

33

0.05

7

0.01

Cove Point import contracts

(27
)

(0.04
)

(63
)

(0.10
)
Noncontrolling interests⁽¹⁾

(9
)

(0.01
)

(28
)

(0.04
)
Transportation and storage growth projects

7

0.01

23

0.04

Other

14

0.02

7

0.01

Share dilution

—

—

—

(0.03
)
Change in net income contribution

$
52

$
0.08

$
130

$
0.19

~~(1)~~

~~Represents the portion of earnings attributable to Dominion Energy Midstream's public unitholders.~~

~~Corporate and Other~~

~~Presented below are the Corporate and Other segment’s after-tax results:~~

Third Quarter

Year-To-Date

2017

2016

$ Change

2017

2016

$ Change

(millions, except EPS)

Specific items attributable to operating segments

$
—

$
4

$
(4
)

$
(1
)

$
(22
)

$
21

Specific items attributable to corporate operations

(7
)

(30
)

23

(16
)

(41
)

25

Total specific items

(7
)

(26
)

19

(17
)

(63
)

46

Other corporate operations:

Renewable energy investment tax credits

52

(143
)

195

79

(11
)

90

Interest expense, net

(85
)

(63
)

(22
)

(258
)

(191
)

(67
)
Other

11

(2
)

13

10

19

(9
)
Total other corporate operations

(22
)

(208
)

186

(169
)

(183
)

14

Total net expense

$
(29
)

$
(234
)

$
205

$
(186
)

$
(246
)

$
60

EPS impact

$
(0.04
)

$
(0.37
)

$
0.33

$
(0.30
)

$
(0.40
)

$
0.10

~~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 those segments' performance or in allocating resources. See Note 19 to the Consolidated Financial Statements in this report for discussion of these items in more detail. Corporate 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:~~

Third Quarter

Year-To-Date

2017

2016

$ Change

2017

2016

$ Change

(millions)

Net income

$
459

$
503

$
(44
)

$
1,133

$
1,046

$
87

~~Overview~~

~~Third Quarter 2017 vs. 2016~~

Net income decreased 9%, primarily due to milder weather during 2017 and the annual PJM capacity performance market effective June 2017, partially offset by a benefit related to non-utility generators.

~~Year-To-Date 2017 vs. 2016~~

Net income increased 8%, primarily due to the PJM capacity performance market, a benefit related to non-utility generators, an increase in customer usage and other factors and the absence of organizational design initiative costs, partially offset by milder weather during 2017.

~~Analysis of Consolidated Operations~~

~~Presented below are selected amounts related to Virginia Power’s results of operations:~~

Third Quarter

Year-To-Date

2017

2016

$ Change

2017

2016

$ Change

(millions)

Operating revenue

$
2,154

$
2,211

$
(57
)

$
5,732

$
5,877

$
(145
)
Electric fuel and other energy-related purchases

549

516

33

1,414

1,527

(113
)
Purchased (excess) electric capacity

21

(6
)

27

(8
)

107

(115
)
Net revenue

1,584

1,701

(117
)

4,326

4,243

83

Other operations and maintenance

373

443

(70
)

1,126

1,279

(153
)
Depreciation and amortization

288

270

18

854

765

89

Other taxes

76

74

2

233

218

15

Other income

13

13

—

57

47

10

Interest and related charges

128

118

10

373

345

28

Income tax expense

273

306

(33
)

664

637

27

~~An analysis of Virginia Power’s results of operations follows:~~

~~Third Quarter 2017 vs. 2016~~

~~Net revenue~~ ~~decreased 7%, primarily reflecting:~~

~~A $76 million decrease in sales to retail customers from a decrease in cooling degree days; and~~

~~Other operations and maintenance~~ ~~decreased 16%, primarily reflecting:~~

~~A $30 million decrease in certain electric transmission-related expenditures. These expenses are primarily recovered through state and FERC rates and do not impact net income;~~

~~An $11 million decrease due to the absence of 2016 union workforce contract renegotiations; and~~

~~A $9 million decrease in outside services due to the absence of certain utility projects.~~

~~Income tax expense~~ ~~decreased 11%, primarily due to lower pre-tax income.~~

~~Year-To-Date 2017 vs. 2016~~

~~Net revenue~~ ~~increased 2%, primarily reflecting:~~

~~An increase in sales to retail customers due to the effect of changes in customer usage and other factors ($57 million); and~~

~~An increase from rate adjustment clauses ($36 million); partially offset by~~

A decrease in sales to retail customers from a reduction in heating degree days during the heating season of 2017 ($52 million) and a decrease in cooling degree days during the cooling season of 2017 ($53 million).

~~Other operations and maintenance~~ ~~decreased 12%, primarily reflecting:~~

~~An $88 million decrease in certain electric transmission-related expenditures. These expenses are primarily recovered through state and FERC rates and do not impact net income;~~

~~The absence of organizational design initiative costs ($32 million); and~~

~~A $28 million decrease in storm damage and service restoration costs.~~

~~Depreciation and amortization~~ ~~increased 12%, primarily due to various growth projects being placed into service ($48 million) and revised depreciation rates ($32 million).~~

~~Other income~~ ~~increased 21%, primarily reflecting:~~

~~An $11 million increase in interest income associated with the settlement of state income tax refund claims; and~~

~~A $10 million increase from the assignment of Virginia Power’s electric transmission tower rental portfolio; partially offset by~~

~~A $16 million charge associated with a customer settlement.~~

~~Dominion Energy Gas~~

~~Results of Operations~~

~~Presented below is a summary of Dominion Energy Gas' consolidated results:~~

Third Quarter

Year-To-Date

2017

2016

$ Change

2017

2016

$ Change

(millions)

Net income

$
117

$
83

$
34

$
302

$
286

$
16

~~Overview~~

~~Third Quarter 2017 vs. 2016~~

~~Net income increased 41%, primarily due to gains from agreements to convey shale development rights underneath several natural gas storage fields.~~

~~Year-To-Date 2017 vs. 2016~~

~~Net income increased 6%, primarily due to gas transportation and storage activities from growth projects placed into service.~~

~~Analysis of Consolidated Operations~~

~~Presented below are selected amounts related to Dominion Energy Gas' results of operations:~~

Third Quarter

Year-To-Date

2017

2016

$ Change

2017

2016

$ Change

(millions)

Operating revenue

$
401

$
382

$
19

$
1,313

$
1,181

$
132

Purchased gas

19

21

(2
)

100

71

29

Other energy-related purchases

4

4

—

11

8

3

Net revenue

378

357

21

1,202

1,102

100

Other operations and maintenance

73

133

(60
)

377

331

46

Depreciation and amortization

57

55

2

167

150

17

Other taxes

42

36

6

139

127

12

Earnings from equity method investee

4

5

(1
)

15

14

1

Other income

6

2

4

16

8

8

Interest and related charges

25

23

2

72

68

4

Income tax expense

74

34

40

176

162

14

~~An analysis of Dominion Energy Gas' results of operations follows:~~

~~Third Quarter 2017 vs. 2016~~

~~Net revenue~~ ~~increased 6%, primarily reflecting:~~

~~A $13 million increase from regulated natural gas transmission growth projects placed into service;~~

~~A $6 million increase in PIR program revenues; and~~

~~A $6 million increase in services performed for Atlantic Coast Pipeline.~~

~~Other operations and maintenance~~ ~~decreased 45%, primarily reflecting:~~

~~The increase in gains from agreements to convey shale development rights underneath several natural gas storage fields ($56 million); and~~

~~The absence of a union workforce temporary work stoppage ($8 million); partially offset by~~

~~A $5 million increase in services performed for Atlantic Coast Pipeline. These expenses are billed to Atlantic Coast Pipeline and do not significantly impact net income.~~

~~Other taxes~~ ~~increased 17% primarily due to an increase in property taxes related to growth projects placed into service.~~

~~Income tax expense~~ ~~increased by $40 million due to higher pre-tax income ($28 million) and the absence of a 2016 settlement with a tax authority ($12 million).~~

~~Year-To-Date 2017 vs. 2016~~

~~Net revenue~~ ~~increased 9%, primarily reflecting:~~

~~A $38 million increase from regulated natural gas transmission growth projects placed into service;~~

~~A $22 million increase in services performed for Atlantic Coast Pipeline;~~

~~An $18 million increase in PIR program revenues; and~~

~~A $17 million increase in rate recovery for low income assistance programs associated with regulated natural gas distribution operations.~~

~~Other operations and maintenance~~ ~~increased 14%, primarily reflecting:~~

~~A $21 million increase in services performed for Atlantic Coast Pipeline. These expenses are billed to Atlantic Coast Pipeline and do not significantly impact net income;~~

A $17 million increase in bad debt expense at regulated natural gas distribution operations primarily related to low income assistance programs. These bad debt expenses are recovered through rates and do not impact net income;

~~A $15 million increase due to a charge to write-off the balance of a regulatory asset no longer considered probable of recovery; and~~

~~An $11 million increase in salaries, wages and benefits and general and administrative expenses; partially offset by~~

~~A $16 million increase in gains from agreements to convey shale development rights underneath several natural gas storage fields;~~

~~The absence of organizational design initiative costs ($10 million); and~~

~~The absence of a union workforce temporary work stoppage ($8 million).~~

~~Other income~~ increased by $8 million primarily due to an increase in AFUDC associated with rate-regulated projects ($12 million), partially offset by the absence of a gain on the 2016 sale of a portion of Dominion Energy Gas’ interest in Iroquois ($5 million).

~~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 September 30, 2017, Dominion Energy had $2.4 billion of unused capacity under its credit facilities. See Note 14 to the Consolidated Financial Statements for more information.~~

~~A summary of Dominion Energy’s cash flows is presented below:~~

2017

2016

(millions)

Cash and cash equivalents at January 1

$
261

$
607

Cash flows provided by (used in):

Operating activities

3,664

3,386

Investing activities

(4,873
)

(9,029
)
Financing activities

1,175

5,287

Net decrease in cash and cash equivalents

(34
)

(356
)
Cash and cash equivalents at September 30

$
227

$
251

~~Operating Cash Flows~~

Net cash provided by Dominion Energy’s operating activities increased $278 million, primarily due to the operations acquired in the Dominion Energy Questar Combination being included for all of 2017, an electric utility capacity benefit, derivative activities and proceeds from the assignment of the electric transmission tower rental portfolio, partially offset by lower deferred fuel cost recoveries in the Virginia jurisdiction, milder weather in Dominion Energy’s electric utility service territory, higher interest expense, lower revenue from Cove Point’s import contracts and Dominion Energy’s contribution to Dominion Energy Questar’s pension plan.

~~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.~~

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 Item 1A. Risk Factors in the Companies' Annual Report on Form 10-K for the year ended December 31, 2016.

~~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 September 30, 2017 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⁾

$
26

$
—

$
26

Non-investment grade⁽²⁾

3

—

3

No external ratings:

Internally rated—investment grade⁽³⁾

8

—

8

Internally rated—non-investment grade⁽⁴⁾

33

—

33

Total

$
70

$
—

$
70

~~(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 32% of the total net credit exposure.

~~(2)~~

~~The five largest counterparty exposures, combined, for this category represented approximately 4% of the total net credit exposure.~~

~~(3)~~

~~The five largest counterparty exposures, combined, for this category represented approximately 11% of the total net credit exposure.~~

~~(4)~~

~~The five largest counterparty exposures, combined, for this category represented approximately 18% of the total net credit exposure.~~

~~Investing Cash Flows~~

Net cash used in Dominion Energy’s investing activities decreased $4.2 billion, primarily due to the absence of the acquisition of Dominion Energy Questar and decreases in plant construction and other property additions, partially offset by an increase in acquisitions of solar development projects and increased investment 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, 2016, 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.

Net cash provided by Dominion Energy's financing activities decreased $4.1 billion, primarily due to the absence of debt and common stock issuances utilized to finance the Dominion Energy Questar Combination.

~~See Notes 3 and 14 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, 2016, 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 September 30, 2017, 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, 2016, there is a discussion on the various covenants present in the enabling agreements underlying Dominion Energy's debt. As of September 30, 2017, there have been no material changes to debt covenants, nor any events of default under Dominion Energy's debt covenants. Pursuant to a waiver received in April 2016 and in connection with the closing of the Dominion Energy Questar Combination, the 65% maximum debt to total capital ratio in Dominion Energy’s credit agreements was, with respect to Dominion Energy only, temporarily increased to 70% through the fiscal quarter ended June 30, 2017. Effective July 2017, the maximum debt to total capital ratio in Dominion Energy’s credit agreements was reset to 65%.

~~Future Cash Payments for Contractual Obligations and Planned Capital Expenditures~~

As of September 30, 2017, 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, 2016.

~~Use of Off-Balance Sheet Arrangements~~

As of September 30, 2017, there have been no material changes in the off-balance sheet arrangements disclosed in MD&A in the Companies' Annual Report on Form 10-K for the year ended December 31, 2016.

~~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, 2016 and~~ ~~Future Issues and Other Matters~~ ~~in MD&A in the Companies’ Quarterly Reports on Form 10-Q for the quarters ended March 31, 2017 and June 30, 2017.~~

~~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 22 to the Consolidated Financial Statements in the Companies' Annual Report on Form 10-K for the year ended December 31, 2016, and Note 15 to the Consolidated Financial Statements in the Companies’ Quarterly Reports on Form 10-Q for the quarters ended March 31, 2017 and June 30, 2017, and in this report for additional information on various environmental matters.

~~Air~~

In August 2015, the EPA issued final carbon standards for existing fossil fuel power plants. Known as the Clean Power Plan, the rule uses a set of measures for reducing emissions from existing sources that includes efficiency improvements at coal plants, displacing coal-fired generation with increased utilization of natural gas combined cycle units and expanding renewable resources. The new rule requires states to impose standards of performance limits for existing fossil fuel-fired electric generating units or equivalent statewide intensity-based or mass-based CO₂ binding goals or limits. States are required to submit final plans identifying how they will comply with the rule by September 2018. The EPA also issued a proposed federal implementation plan and model trading rule that states can adopt or that would be put in place if, in response to the final guidelines, a state either does not submit a state plan or its plan is not approved by the EPA. The

final rule has been challenged in the U.S. Court of Appeals for the D.C. Circuit. In February 2016, the U.S. Supreme Court issued a stay of the Clean Power Plan until the disposition of the petitions challenging the rule now before the Court of Appeals, and, if such petitions are filed in the future, before the U.S. Supreme Court. In June 2016, the Governor of Virginia signed an executive order directing the Virginia Natural Resources Secretary to convene a workgroup charged with recommending concrete steps to reduce carbon pollution from power plants which could include reductions at levels similar to the Clean Power Plan as an option. In March 2017, the President issued an Executive Order directing the EPA to undertake a review of the Clean Power Plan that could result in significant revisions to, or rescinding of, the rule. In April 2017, the U.S. Court of Appeals for the D.C. Circuit issued an order suspending the cases challenging the Clean Power Plan for 60 days to allow the EPA time to determine whether to revise or rescind the rule. Also ~~in April 2017, the~~ EPA issued a notice withdrawing the proposed federal implementation plan and model trading rules. In June 2017, the Governor of Virginia issued a directive for development of state carbon regulations with a December 2017 deadline for submittal of draft rules to the Virginia State Air Pollution Control Board for approval to notice for public comment. In October 2017, the EPA issued a proposed rule to repeal the Clean Power Plan on the basis that the rule promulgated in 2015 exceeds the EPA’s authority under the CAA. The proposal does not include a replacement rule. The proposal also does not impact the EPA’s regulation of GHG emissions from stationary sources under the CAA permitting programs or the GHG performance standards for new sources, which remain in place. Given these developments and associated federal and state regulatory and legal uncertainties, Dominion Energy cannot predict the potential financial statement impacts but believes the potential expenditures to comply could be material.

~~State Actions~~

~~In August 2017, the Ozone Transport Commission released a draft model rule for control of NO~~_x emissions from natural gas pipeline compressor fuel-fire prime movers. States within the ozone transport region, including states in which Dominion Energy has natural gas operations, are expected to develop reasonably achievable control technology rules for existing sources based on the Ozone Transport Commission model rule. States outside of the Ozone Transport Commission may also consider the model rules in setting new reasonably achievable control technology standards. Several states in which Dominion Energy operates, including Pennsylvania, New York and Maryland, are moving ahead with state-specific climate change regulations, including methane. Dominion Energy cannot currently estimate the potential financial statements impacts on results of operations, financial condition and/or cash flows related to these matters.

~~Significant Power Delivery Project~~

In September 2017, Virginia Power filed an application with the Virginia Commission for a CPCN to rebuild and operate in Augusta County, Virginia approximately 18 miles of the existing 500 kV transmission line between the Dooms substation and the Valley substation, along with associated substation work, for a total estimated cost of approximately $65 million. This case is pending.

~~Significant Gas Infrastructure Projects~~

~~Eastern Market Access~~

In November 2016, Cove Point filed an application to request FERC authorization to construct the approximately $150 million Eastern Market Access Project. Construction on the project is expected to begin in the first quarter of 2018, and the project facilities are expected to be placed into service in late 2018.

~~Atlantic Coast Pipeline~~

In October 2017, Atlantic Coast Pipeline received the FERC order authorizing the construction and operation of an approximately 600-mile natural gas pipeline running from West Virginia through Virginia to North Carolina. The project remains subject to other pending federal and state approvals.

~~Other Matters~~

While management currently has no plans which may affect the carrying value of Millstone, based on potential future economic and other factors, including, but not limited to, market power prices, results of capacity auctions, legislative and regulatory solutions to ensure nuclear plants are fairly compensated for their carbon-free emissions, and the impact of final rules from the EPA and the efforts of states to implement those final rules; there is risk that Millstone may be evaluated for an early retirement date. Should management make any decision on a potential early retirement date, the precise date and the resulting financial statement impacts, which could be material to Dominion Energy, may be affected by a number of factors, including any potential regulatory or legislative solutions, results of any transmission system reliability study assessments, and decommissioning requirements, among other factors.

~~Legal Matters~~

~~See Notes 13 and 22 to the Consolidated Financial Statements and~~ ~~Item 3. Legal Proceedings~~ in the Companies' Annual Report on Form 10-K for the year ended December 31, 2016, Notes 12 and 15 to the Consolidated Financial Statements in the Companies’ Quarterly Reports on Form 10-Q for the quarters ended March 31, 2017 and June 30, 2017, and ~~Item 1. Legal Proceedings~~ ~~in this report for additional information on various legal matters.~~

~~Regulatory Matters~~

See Note 13 to the Consolidated Financial Statements in the Companies' Annual Report on Form 10-K for the year ended December 31, 2016, Note 12 to the Consolidated Financial Statements in the Companies’ Quarterly Reports on Form 10-Q for the quarters ended March 31, 2017 and June 30, 2017, and in this report for additional information on various regulatory matters.

~~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's and Virginia Power's electric operations and Dominion Energy's 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 and Dominion Energy Gas holds commodity-based financial derivative instruments held for non-trading purposes associated with purchases and sales of natural gas and other energy-related products.

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 $28 million and $27 million of Dominion Energy's commodity-based derivative instruments as of September 30, 2017 and December 31, 2016, respectively.

A hypothetical 10% decrease in commodity prices would have resulted in a decrease in the fair value of $48 million and $62 million of Virginia Power's commodity-based derivative instruments as of September 30, 2017 and December 31, 2016, respectively.

A hypothetical 10% increase in commodity prices would have resulted in a decrease in fair value of $4 million of Dominion Energy Gas' commodity-based derivative instruments as of both September 30, 2017 and December 31, 2016.

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 and interest rate swaps designated under fair value hedging and outstanding for the Companies, a hypothetical 10% increase in market interest rates would not have resulted in a material change in earnings at September 30, 2017 or December 31, 2016.

The Companies also use interest rate derivatives, including forward-starting swaps, as cash flow hedges of forecasted interest payments. As of September 30, 2017, Dominion Energy and Virginia Power had $3.5 billion and $1.5 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 $55 million and $42 million, respectively, in the fair value of Dominion Energy's and Virginia Power's interest rate derivatives at September 30, 2017. As of December 31, 2016, Dominion Energy and Virginia Power had $2.9 billion and $1.7 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 $58 million and $45 million, respectively, in the fair value of Dominion Energy's and Virginia Power's interest rate derivatives at December 31, 2016.

Dominion Energy Gas holds foreign currency swaps for the purpose of hedging the foreign currency exchange risk associated with Euro denominated debt. As of September 30, 2017 and December 31, 2016, Dominion Energy and Dominion Energy Gas had $280 million (€250 million) in aggregate notional amounts of these foreign currency swaps outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a $3 million and $5 million decrease in the fair value of Dominion Energy Gas' foreign currency swaps at September 30, 2017 and December 31, 2016, respectively.

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's and Virginia Power's Consolidated Balance Sheets at fair value.

Dominion Energy recognized net realized gains (including investment income) on nuclear decommissioning and rabbi trust investments of $137 million and $113 million for the nine months ended September 30, 2017 and 2016, respectively, and $144 million for the year ended December 31, 2016. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. Dominion Energy recorded in AOCI and regulatory liabilities, a net increase in unrealized gains on these investments of $271 million and $146 million for the nine months ended September 30, 2017 and 2016, respectively, and $183 million for the year ended December 31, 2016.

Virginia Power recognized net realized gains (including investment income) on nuclear decommissioning trust investments of $59 million and $51 million for the nine months ended September 30, 2017 and 2016, respectively, and $67 million for the year ended December 31, 2016. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. Virginia Power recorded in AOCI and regulatory liabilities, a net increase in unrealized gains on these investments of $127 million and $77 million for the nine months ended September 30, 2017 and 2016, respectively, and $93 million for the year ended December 31, 2016.

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’s, Virginia Power’s, 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’s, Virginia Power’s, 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 in Dominion Energy’s, Virginia Power’s, or Dominion Energy Gas' internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, the Companies’ 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.

~~See the following for discussions on various environmental and other regulatory proceedings to which the Companies are a party, which information is incorporated herein by reference:~~

~~Notes 13 and 22 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, 2016.~~

~~Notes 12 and 15 to the Consolidated Financial Statements in the Companies’ Quarterly Reports on Form 10-Q for the quarter ended March 31, 2017.~~

~~Notes 12 and 15 to the Consolidated Financial Statements in the Companies’ Quarterly Reports on Form 10-Q for the quarter ended June 30, 2017.~~

~~Notes 12 and 15 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, 2016, 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, 2016. 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~~ ~~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⁾
7/1/17-7/31/17

—

$
—

—

19,629,059 shares/
$1.18 billion
8/1/17-8/31/17

217

77.30

—

19,629,059 shares/
$1.18 billion
9/1/17-9/30/17

5,932

79.50

—

19,629,059 shares/
$1.18 billion
Total

6,149

$
79.42

—

19,629,059 shares/
$1.18 billion

~~(1)~~

~~In August and September 2017, 217 shares and 5,932 shares, respectively, were tendered by employees to satisfy tax withholding obligations on vested restricted stock.~~

~~(2)~~

~~Represents the weighted-average price paid per share.~~

~~(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.

~~ITEM 6. EXHIBITS~~

~~Exhibit~~

~~Number~~

~~Description~~

~~Dominion Energy~~

~~Virginia Power~~

~~Dominion Energy Gas~~

10.1

First Amending Agreement to the Credit Agreement, dated April 27, 2021, among AltaLink Investments, L.P., as borrower, AltaLink Investment Management Ltd., as general partner, Royal Bank of Canada, as administrative agent, and Lenders.

~~3.1.a~~

~~Dominion Energy, Inc. Articles of Incorporation as amended and restated, effective May 10, 2017 (Exhibit 3.1, Form 8-K filed May 10, 2017, File No.1-8489).~~

10.2

Second Amending Agreement to the Credit Agreement, dated April 27, 2022, among AltaLink Investments, L.P., as borrower, AltaLink Investment Management Ltd., as general partner, Royal Bank of Canada, as administrative agent, and Lenders.

~~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).~~

10.3

Third Amending Agreement to the Credit Agreement, dated April 27, 2023, among AltaLink Investments, L.P., as borrower, AltaLink Investment Management Ltd., as general partner, Royal Bank of Canada, as administrative agent, and Lenders.

~~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).~~

15.1

Awareness Letter of Independent Registered Public Accounting Firm.

~~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).~~

31.1

~~3.2.a~~

~~Dominion Energy, Inc. Amended and Restated Bylaws, effective May 10, 2017 (Exhibit 3.2, Form 8-K filed May 10, 2017, File No. 1-8489).~~

~~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).~~

~~3.2.c~~

~~Operating Agreement of Dominion Energy Gas Holdings, LLC, amended and restated as of May 12, 2017 (Exhibit 3.2, Form 8-K filed May 16, 2017, File No. 001-37591).~~

~~4.1~~

Dominion Energy, Inc., Virginia Electric and Power Company and Dominion Energy Gas Holdings, LLC agree to furnish to the 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.

~~4.2~~

Form of Senior Indenture, dated June 1, 1998, between Virginia Electric and Power Company and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)), as Trustee (Exhibit 4(iii), Form S-3 Registration Statement filed February 27, 1998, File No. 333-47119); ~~Form of Nineteenth Supplemental and Amending Indenture, dated November 1, 2008 (Exhibit 4.2, Form 8-K filed November 5, 2008, File No. 1-2255)~~; ~~Twenty-Fifth Supplemental Indenture, dated as of March 1, 2013 (Exhibit 4.3, Form 8-K filed March 14, 2013, File No. 1-2255)~~.

~~4.3~~

Senior Indenture, dated as of September 1, 2017, between Virginia Electric and Power Company and U.S. Bank National Association, as Trustee (Exhibit 4.1, Form 8-K filed September 13, 2017, File No.000-55337); ~~First Supplemental Indenture, dated as of September 1, 2017 (Exhibit 4.2, Form 8-K filed September 13, 2017, File No.000-55337).~~

~~12.1~~

~~Ratio of earnings to fixed charges for Dominion Energy, Inc. (filed herewith).~~

~~12.2~~

~~Ratio of earnings to fixed charges for Virginia Electric and Power Company (filed herewith).~~

~~12.3~~

~~Ratio of earnings to fixed charges for Dominion Energy Gas Holdings, LLC (filed herewith).~~

~~31.a~~

~~Certification by Chief~~Principal Executive Officer ~~of Dominion Energy, Inc. pursuant~~Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of ~~2002 (filed herewith).~~2002.

~~31.b~~

31.2

~~Certification by Chief~~Principal Financial Officer ~~of Dominion Energy, Inc. pursuant~~Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of ~~2002 (filed herewith).~~2002.

~~31.c~~

32.1

~~Certification by Chief~~Principal Executive Officer Certification Pursuant to Section 906 of ~~Virginia Electric and Power Company pursuant~~the Sarbanes-Oxley Act of 2002.

32.2

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

PACIFICORP

15.2

Awareness Letter of Independent Registered Public Accounting Firm.

31.3

Principal Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of ~~2002 (filed herewith).~~2002.

~~31.d~~

31.4

~~Certification by Chief~~Principal Financial Officer ~~of Virginia Electric and Power Company pursuant~~Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of ~~2002 (filed herewith).~~2002.

32.3

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

32.4

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

BERKSHIRE HATHAWAY ENERGY AND PACIFICORP

~~Exhibit~~

~~Number~~

~~Description~~

~~Dominion Energy~~

~~Virginia Power~~

~~Dominion Energy Gas~~

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

MIDAMERICAN ENERGY

~~31.e~~

15.3

Awareness Letter of Independent Registered Public Accounting Firm.

31.5

~~Certification by Chief~~Principal Executive Officer ~~of Dominion Energy Gas Holdings, LLC pursuant~~Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of ~~2002 (filed herewith).~~2002.

~~31.f~~

31.6

~~Certification by Chief~~Principal Financial Officer ~~of Dominion Energy Gas Holdings, LLC pursuant~~Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of ~~2002 (filed herewith).~~2002.

~~32.a~~

32.5

~~Certification to the Securities and Exchange Commission by Chief~~Principal Executive Officer ~~and Chief Financial Officer of Dominion Energy, Inc. as required by~~Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of ~~2002 (furnished herewith).~~2002.

~~32.b~~

32.6

~~Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief~~Principal Financial Officer ~~of Virginia Electric and Power Company as required by~~Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of ~~2002 (furnished herewith).~~2002.

184

				X
Exhibit No.			Description

MIDAMERICAN FUNDING

~~32.c~~

31.7

~~Certification to the Securities and Exchange Commission by Chief~~Principal Executive Officer ~~and Chief~~Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.8

Principal Financial Officer Certification Pursuant to Section 302 of ~~Dominion Energy Gas Holdings, LLC as required by~~the Sarbanes-Oxley Act of 2002.

32.7

Principal Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of ~~2002 (furnished herewith).~~2002.

32.8

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

NEVADA POWER

~~Condensed consolidated earnings statements (filed herewith).~~

15.4

Awareness Letter of Independent Registered Public Accounting Firm.

~~101~~

31.9

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

31.10

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

32.9

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

32.10

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

SIERRA PACIFIC


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

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

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

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

EASTERN ENERGY GAS


10.4			Amended and Restated $400,000,000 Inter-Company Credit Agreement, dated as of March 1 , 2023, by and between BHE GT&S, LLC and Eastern Energy Gas Holdings, LLC.

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

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

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

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

185


Exhibit No.			Description

EASTERN GAS TRANSMISSION AND STORAGE


10.5			Amended and Restated $400,000,000 Inter-Company Credit Agreement, dated as of March 1, 2023, by and between Eastern Energy Gas Holdings, LLC and Eastern Gas Transmission and Storage, Inc.

10.6			Amended and Restated $400,000,000 Inter-Company Credit Agreement, dated as of March 1, 2023, by and between Eastern Gas Transmission and Storage, Inc. and Eastern Energy Gas Holdings, LLC.

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

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

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

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

ALL REGISTRANTS


101	The following financial ~~statements~~information from ~~Dominion Energy, Inc.’s~~each respective Registrant's Quarterly Report on Form 10-Q for the quarter ended ~~September 30, 2017, filed on November 1, 2017,~~March 31, 2023, is formatted in ~~XBRL:~~iXBRL (Inline eXtensible Business Reporting Language) and included herein: (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of ~~Income, (ii) Consolidated Balance Sheets,~~Operations, (iii) ~~Consolidated Statements of Equity, (iv)~~the 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 Consolidated Financial ~~Statements. The following financial statements from Virginia Electric~~Statements, tagged in summary and ~~Power Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2017, filed on November 1, 2017,~~detail.

104	Cover Page Interactive Data File formatted in ~~XBRL: (i) Consolidated Statements of Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows,~~iXBRL (Inline eXtensible Business Reporting Language) and (iv) 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 September 30, 2017, filed on November 1, 2017, formattedcontained in XBRL: (i) Consolidated Statements of Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Comprehensive Income, (iv) Consolidated Statements of Cash Flows, and (v) the Notes to Consolidated Financial Statements.	X	X	X Exhibit 101.

186

~~SIGNATURE~~

SIGNATURES

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: May 5, 2023			~~DOMINION ENERGY, INC.~~ ~~Registrant~~ /s/ Calvin D. Haack
			Calvin D. Haack
~~November 1, 2017~~			~~/s/ Michele L. Cardiff~~ Senior Vice President and Chief Financial Officer
			~~Michele~~(principal financial and accounting officer)

			PACIFICORP

Date: May 5, 2023			/s/ Nikki L. ~~Cardiff~~ Kobliha
			Nikki L. Kobliha
			Vice President, ~~Controller~~Chief Financial Officer and ~~Chief Accounting Officer~~ Treasurer
			(principal financial and accounting officer)
			~~VIRGINIA ELECTRIC AND~~
			MIDAMERICAN FUNDING, LLC
			MIDAMERICAN ENERGY COMPANY

Date: May 5, 2023			/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 ~~Registrant~~

~~November 1, 2017~~ Date: May 5, 2023			/s/ ~~Michele L. Cardiff~~ Michael J. Behrens
			~~Michele L. Cardiff~~ Michael J. Behrens
			Vice President ~~Controller~~ and Chief ~~Accounting~~Financial Officer
			(principal financial and accounting officer)
			~~DOMINION~~
			SIERRA PACIFIC POWER COMPANY

Date: May 5, 2023			/s/ Michael J. Behrens
			Michael J. Behrens
			Vice President and Chief Financial Officer
			(principal financial and accounting officer)

			EASTERN ENERGY GAS HOLDINGS, LLC ~~Registrant~~

~~November 1, 2017~~ Date: May 5, 2023			/s/ ~~Michele L. Cardiff~~ Scott C. Miller
			~~Michele L. Cardiff~~ Scott C. Miller
			Vice President, ~~Controller~~Chief Financial Officer and Treasurer
			(principal financial and accounting officer)

			EASTERN GAS TRANSMISSION AND STORAGE, INC.

Date: May 5, 2023			/s/ Scott C. Miller
			Scott C. Miller
			Vice President, Chief ~~Accounting~~Financial Officer and Treasurer
			(principal financial and accounting officer)

~~101~~

187

~~Large accelerated filer~~	☐		~~Accelerated filer~~	☐
~~Non-accelerated filer~~	☒	~~(Do not check if a smaller reporting company)~~	~~Smaller reporting company~~	☐
			~~Emerging growth company~~	☐

~~Large accelerated filer~~	☐		~~Accelerated filer~~	☐
~~Non-accelerated filer~~	☒	~~(Do not check if a smaller reporting company)~~	~~Smaller reporting company~~	☐
			~~Emerging growth company~~	☐

~~Abbreviation or Acronym~~	~~Definition~~
~~2013 Equity Units~~			~~Dominion Energy's 2013 Series A Equity Units~~Berkshire Hathaway Energy Company and ~~2013 Series B Equity Units issued in June 2013~~ Related Entities
~~2014 Equity Units~~ BHE		~~Dominion Energy's 2014 Series A Equity Units issued in July 2014~~ Berkshire Hathaway Energy Company
~~2016 Equity Units~~ Berkshire Hathaway		~~Dominion Energy's 2016 Series A Equity Units issued in August 2016~~ Berkshire Hathaway Inc.
~~AFUDC~~ Berkshire Hathaway Energy or the Company		~~Allowance for funds used during construction~~ Berkshire Hathaway Energy Company and its subsidiaries
~~AOCI~~ PacifiCorp		~~Accumulated other comprehensive income (loss)~~ PacifiCorp and its subsidiaries
~~ARO~~ MidAmerican Funding		~~Asset retirement obligation~~ MidAmerican Funding, LLC and its subsidiaries
~~Atlantic Coast Pipeline~~ MidAmerican Energy		~~Atlantic Coast Pipeline, LLC, a limited liability company owned by Dominion~~MidAmerican Energy ~~Duke and Southern~~ Company ~~Gas~~
~~BACT~~ NV Energy		~~Best available control technology~~
~~bcf~~	~~Billion cubic feet~~
~~bcfe~~	~~Billion cubic feet equivalent~~
~~Brunswick County~~	~~A 1,376 MW combined cycle, natural gas-fired power station in Brunswick County, Virginia~~
~~CAA~~	~~Clean Air Act~~
~~CAISO~~	~~California Independent System Operator~~
~~CCR~~	~~Coal combustion residual~~
~~CEO~~	~~Chief Executive Officer~~
~~CERCLA~~	~~Comprehensive Environmental Response, Compensation and Liability Act of 1980, also known as Superfund~~
~~CFO~~	~~Chief Financial Officer~~
CO₂	~~Carbon dioxide~~
~~Companies~~	~~Dominion Energy, Virginia Power and Dominion Energy Gas, collectively~~
~~Cooling degree days~~	~~Units measuring the extent to which the average daily temperature is greater than 65 degrees Fahrenheit, calculated as the difference between 65 degrees and the average temperature for that day~~
~~Cove Point~~	~~Dominion Energy Cove Point LNG, LP (formerly known as Dominion Cove Point LNG, LP)~~
~~CPCN~~	~~Certificate of Public Convenience and Necessity~~
~~CWA~~	~~Clean Water Act~~
~~DECG~~	~~Dominion Energy Carolina Gas Transmission, LLC (formerly known as Dominion Carolina Gas Transmission, LLC)~~
~~DES~~	~~Dominion Energy Services, Inc. (formerly known as Dominion Resources Services, Inc.)~~
~~DETI~~	~~Dominion Energy Transmission, Inc. (formerly known as Dominion Transmission, Inc.)~~
~~DGI~~	~~Dominion Generation, Inc. (formerly known as Dominion Energy, Inc.)~~
~~DOE~~	~~Department of Energy~~
~~Dominion Energy~~	The legal entity, Dominion Energy, Inc. (formerly known as Dominion Resources, Inc.), one or more of its consolidated subsidiaries (other than Virginia Power and Dominion Energy Gas) or operating segments, or the entirety of DominionNV Energy, Inc. and its ~~consolidated~~ subsidiaries

~~Abbreviation or Acronym~~	~~Definition~~
~~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 (formerly known as Dominion 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 Energy Midstream~~ EGTS		The legal entity, Dominion Energy Midstream Partners, LP (formerly known as Dominion Midstream Partners, LP), one or more of its consolidated subsidiaries, Cove Point Holdings, Iroquois GP Holding Company, LLC, DECGEastern Gas Transmission and ~~Dominion Energy Questar Pipeline (beginning December 1, 2016) or operating segment, or the entirety of Dominion Energy Midstream Partners, LP~~Storage, Inc. and its ~~consolidated~~ subsidiaries
~~Dominion~~Registrants		Berkshire Hathaway Energy ~~Questar~~ 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, Eastern Energy Gas Holdings, LLC and its subsidiaries and Eastern Gas Transmission and Storage, Inc. and its subsidiaries
Northern Powergrid		~~The legal entity, Dominion Energy Questar~~Northern Powergrid Holdings Company and its subsidiaries
BHE Pipeline Group		BHE GT&S, LLC, Northern Natural Gas Company and Kern River Gas Transmission Company
BHE GT&S		BHE GT&S, LLC and its subsidiaries
Northern Natural Gas		Northern Natural Gas Company
Kern River		Kern River Gas Transmission Company
BHE Transmission		BHE Canada Holdings Corporation ~~(formerly known as Dominion Questar Corporation), one or more of its consolidated subsidiaries or operating segment, or the entirety of Dominion Energy Questar~~and BHE U.S. Transmission, LLC
BHE Canada		BHE Canada Holdings Corporation and its ~~consolidated~~ subsidiaries
~~Dominion Energy Questar Combination~~ AltaLink		~~Dominion Energy's acquisition of Dominion Energy Questar completed on September 16, 2016 pursuant to the terms of the agreement and plan of merger entered on January 31, 2016~~ AltaLink, L.P.
~~Dominion Energy Questar Pipeline~~ BHE U.S. Transmission		~~Dominion Energy Questar Pipeline, LLC (formerly known as Questar Pipeline, LLC), one or more of its consolidated subsidiaries, or the entirety of Dominion Energy Questar Pipeline,~~BHE U.S. Transmission, LLC and its ~~consolidated~~ subsidiaries
~~DSM~~ BHE Renewables		~~Demand-side management~~ BHE Renewables, LLC and its subsidiaries
~~Dth~~ HomeServices		~~Dekatherm~~ HomeServices of America, Inc. and its subsidiaries
~~Duke~~ Utilities		~~The legal entity, Duke Energy Corporation, one or more of its consolidated subsidiaries or operating segments, or the entirety of Duke Energy Corporation~~PacifiCorp and its ~~consolidated~~ subsidiaries, MidAmerican Energy Company, Nevada Power Company and its subsidiaries and Sierra Pacific Power Company and its subsidiaries
~~East Ohio~~		~~The East Ohio Gas Company~~
~~Eastern Market Access Project~~		Project to provide 294,000 Dths per day of firm transportation service to help meet demand for natural gas for Washington Gas Light Company, a local gas utility serving customers in D.C., Virginia and Maryland, and Mattawoman Energy, LLC for its new electric generation facility to be built in Maryland
~~EPA~~



Certain Industry Terms

2020 Wildfires		Wildfires in Oregon and Northern California that occurred September of 2020


AFUDC		Allowance for Funds Used During Construction
AUC		Alberta Utilities Commission
BART		Best Available Retrofit Technology



CPUC		California Public Utilities Commission
CSAPR		Cross-State Air Pollution Rule
D.C. Circuit		United States Court of Appeals for the District of Columbia Circuit

Dth		Decatherm


EPA		United States Environmental Protection Agency
~~EPS~~ FERC		~~Earnings per share~~
~~FERC~~	Federal Energy Regulatory Commission
~~Four Brothers~~ FIP		~~Four Brothers Solar, LLC, a limited liability company owned by Dominion Energy and Four Brothers Holdings, LLC, a wholly-owned subsidiary of NRG effective November 2016~~ Federal Implementation Plan
~~Fowler Ridge~~		~~A wind-turbine facility joint venture between Dominion Energy and BP Wind Energy North America Inc. in Benton County, Indiana~~
~~FTA~~ GAAP		~~Free Trade Agreement~~ Accounting principles generally accepted in the United States of America
~~FTRs~~		~~Financial transmission rights~~
~~GAAP~~		~~U.S. generally accepted accounting principles~~
~~Gal~~ GTA		~~Gallon~~ General Tariff Application
~~Gas Infrastructure~~ GWh		~~Gas Infrastructure Group operating segment~~ Gigawatt Hour
~~GHG~~		~~Greenhouse gas~~
~~Granite Mountain~~		~~Granite Mountain Holdings, LLC, a limited liability company owned by Dominion Energy and Granite Mountain Renewables, LLC, a wholly-owned subsidiary of NRG effective November 2016~~
~~Greensville County~~ IRP		~~An approximately 1,588 MW combined cycle, natural gas-fired power station under construction in Greensville County, Virginia~~ Integrated Resource Plan
~~Heating degree days~~ IUB		~~Units measuring the extent to which the average daily temperature is less than 65 degrees Fahrenheit, calculated as the difference between 65 degrees and the average temperature for that day~~ Iowa Utilities Board
~~Hope~~ kV		~~Hope Gas, Inc.~~


Registrant			Securities registered pursuant to Section 12(b) of the Act:
BERKSHIRE HATHAWAY ENERGY COMPANY			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
EASTERN GAS TRANSMISSION AND STORAGE, INC.			None


Registrant			Name of exchange on which registered:
BERKSHIRE HATHAWAY ENERGY COMPANY			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
EASTERN GAS TRANSMISSION AND STORAGE, INC.			None

		~~Page~~ ~~Number~~
			~~Glossary of Terms~~	3

	~~PART I. Financial Information~~

Item 1.	Financial Statements			7 1
Item 2.			~~Management’s~~Management's Discussion and Analysis of Financial Condition and Results of Operations		80 2
Item 3.			Quantitative and Qualitative Disclosures About Market Risk		96 178
Item 4.			Controls and Procedures		97 178



	~~PART II. Other Information~~

Item 1.	Legal Proceedings		98 179
Item 1A.		Risk Factors		98 182
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds		98 182
Item 3.		Defaults Upon Senior Securities		183
Item 4.		Mine Safety Disclosures		183
Item 5.		Other Information		183
Item 6.		Exhibits		99 183
Signatures				187

~~Abbreviation or Acronym~~	~~Definition~~ Kilovolt
~~Iron Springs~~		~~Iron Springs Holdings, LLC, a limited liability company owned by Dominion Energy and Iron Springs Renewables, LLC, a wholly-owned subsidiary of NRG effective November 2016~~
~~Iroquois~~ LNG		~~Iroquois~~Liquefied Natural Gas ~~Transmission System, L.P.~~
~~ISO-NE~~ MATS		~~Independent System Operator New England~~
kV	~~Kilovolt~~
~~Liquefaction Project~~	~~A natural gas export/liquefaction facility currently under construction by Cove Point~~
~~LNG~~	~~Liquefied natural gas~~
~~Local 69~~	~~Local 69, Utility Workers Union of America, United Gas Workers~~
~~MATS~~	~~Utility~~ Mercury and Air Toxics ~~Standard Rule~~ Standards
~~MD&A~~ MW		~~Management’s Discussion and Analysis of Financial Condition and Results of Operations~~ Megawatt
~~MGD~~ MWh		~~Million gallons a day~~ Megawatt Hour
~~Millstone~~ NAAQS		~~Millstone nuclear power station~~ National Ambient Air Quality Standards
~~MISO~~ NOx		~~Midcontinent Independent System Operator, Inc.~~ Nitrogen Oxides
MW		~~Megawatt~~
~~MWh~~ Ofgem		~~Megawatt hour~~ Office of Gas and Electric Markets
~~NAV~~ OPUC		~~Net asset value~~ Oregon Public Utility Commission
~~NedPower~~ PTC		~~A wind-turbine facility joint venture between Dominion Energy and Shell Wind Energy, Inc. in Grant County, West Virginia~~ Production Tax Credit
~~NGL~~ PUCN		~~Natural gas liquid~~
NO_x	~~Nitrogen oxide~~
~~NRC~~	~~Nuclear Regulatory Commission~~
~~NRG~~	The legal entity, NRG Energy, Inc., one or more of its consolidated subsidiaries (including, effective November 2016, Four Brothers Holdings, LLC, Granite Mountain Renewables, LLC and Iron Springs Renewables, LLC) or operating segments, or the entirety of NRG Energy, Inc. and its consolidated subsidiaries
~~NSPS~~	~~New Source Performance Standards~~
~~Ohio Commission~~	Public Utilities Commission of ~~Ohio~~ Nevada
~~Order 1000~~		~~Order issued by FERC adopting requirements for electric transmission planning, cost allocation and development~~
~~PIPP~~		~~Percentage of Income Payment Plan deployed by East Ohio~~
~~PIR~~ RFP		~~Pipeline Infrastructure Replacement program deployed by East Ohio~~ Request for Proposals
~~PJM~~ RPS		~~PJM Interconnection, L.L.C.~~ Renewable Portfolio Standards
~~Power Delivery~~		~~Power Delivery Group operating segment~~
~~Power Generation~~ SCR		~~Power Generation Group operating segment~~ Selective Catalytic Reduction
~~ppb~~ SEC		~~Parts-per-billion~~
~~PREP~~	~~Pipeline Replacement and Expansion Program, a program of replacing, upgrading and expanding natural gas utility infrastructure deployed by Hope~~
~~PSD~~	~~Prevention of Significant Deterioration~~
~~Questar Gas~~	~~Questar Gas Company~~
~~Rider BW~~	~~A rate adjustment clause associated with the recovery of costs related to Brunswick County~~
~~Rider U~~	~~A rate adjustment clause associated with the recovery of costs of new underground distribution facilities~~

~~Abbreviation or Acronym~~	~~Definition~~
~~Rider US-2~~	~~A rate adjustment clause associated with the recovery of costs related to Woodland, Scott Solar and Whitehouse~~
~~Riders C1A and C2A~~	~~Rate adjustment clauses associated with the recovery of costs related to certain DSM programs approved in DSM cases~~
~~ROE~~	~~Return on equity~~
~~RSN~~	~~Remarketable subordinated note~~
~~SBL Holdco~~	~~SBL Holdco, LLC, a wholly-owned subsidiary of DGI~~
~~Scott Solar~~	~~A 17 MW utility-scale solar power station in Powhatan County, Virginia~~
~~SEC~~	United States Securities and Exchange Commission
~~Standard & Poor’s~~ SIP		~~Standard & Poor’s Ratings Services, a division of McGraw Hill Financial, Inc.~~ State Implementation Plan
~~SunEdison~~ SO2		~~The legal entity, SunEdison, Inc., one or more~~Sulfur Dioxide

UPSC		Utah Public Service Commission

WUTC		Washington Utilities and Transportation Commission


Berkshire Hathaway Energy Company and its subsidiaries
Report of Independent Registered Public Accounting Firm			4
Consolidated Balance Sheets			5
Consolidated Statements of Operations			7
Consolidated Statements of Comprehensive Income (Loss)			8
Consolidated Statements of Changes in Equity			9
Consolidated Statements of Cash Flows			10
Notes to Consolidated Financial Statements			11
PacifiCorp and its ~~consolidated~~ subsidiaries ~~(including, through November 2016, Four Brothers Holdings, LLC, Granite Mountain Renewables,~~
Report of Independent Registered Public Accounting Firm			47
Consolidated Balance Sheets			48
Consolidated Statements of Operations			50
Consolidated Statements of Changes in Shareholders' Equity			51
Consolidated Statements of Cash Flows			52
Notes to Consolidated Financial Statements			53
MidAmerican Energy Company
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 ~~Iron Springs Renewables, LLC) or operating segments, or the entirety of SunEdison, Inc. and~~ its ~~consolidated~~ subsidiaries
~~Terra Nova Renewable Partners~~ Report of Independent Registered Public Accounting Firm			~~A partnership comprised primarily of institutional investors advised by J.P. Morgan Asset Management-Global Real Assets~~ 85
~~Three Cedars~~ Consolidated Balance Sheets			~~Granite Mountain and Iron Springs, collectively~~ 86
~~UEX Rider~~ Consolidated Statements of Operations			~~Uncollectible Expense Rider deployed by East Ohio~~ 88
~~VDEQ~~ Consolidated Statements of Changes in Member's Equity			~~Virginia Department of Environmental Quality~~ 89
~~VEBA~~ Consolidated Statements of Cash Flows			~~Voluntary Employees' Beneficiary Association~~ 90
~~VIE~~ Notes to Consolidated Financial Statements			~~Variable interest entity~~ 91
~~Virginia Commission~~		~~Virginia State Corporation Commission~~
~~Virginia Power~~	~~The legal entity, Virginia Electric and Power Company, one or more of its consolidated subsidiaries or operating segments, or the entirety of Virginia Electric and~~Nevada Power Company and its ~~consolidated~~ subsidiaries
~~VOC~~ Report of Independent Registered Public Accounting Firm			~~Volatile organic compounds~~ 104
~~Whitehouse~~ Consolidated Balance Sheets			~~A 20 MW utility-scale solar power station in Louisa County, Virginia~~ 105
~~Woodland~~ Consolidated Statements of Operations			~~A 19 MW utility-scale solar power station~~ 106
Consolidated Statements of Changes in ~~Isle~~Shareholder's Equity			107
Consolidated Statements of ~~Wight County, Virginia~~ Cash Flows			108
Notes to Consolidated Financial Statements			109
Sierra Pacific Power Company and its subsidiaries
Report of Independent Registered Public Accounting Firm			124
Consolidated Balance Sheets			125
Consolidated Statements of Operations			126
Consolidated Statements of Changes in Shareholder's Equity			127
Consolidated Statements of Cash Flows			128
Notes to Consolidated Financial Statements			129
Eastern Energy Gas Holdings, LLC and its subsidiaries
Report of Independent Registered Public Accounting Firm			145
Consolidated Balance Sheets			146
Consolidated Statements of Operations			148
Consolidated Statements of Comprehensive Income			149
Consolidated Statements of Changes in Equity			150
Consolidated Statements of Cash Flows			151
Notes to Consolidated Financial Statements			152
Eastern Gas Transmission and Storage, Inc. and its subsidiaries
Report of Independent Registered Public Accounting Firm			163
Consolidated Balance Sheets			164
Consolidated Statements of Operations			166
Consolidated Statements of Comprehensive Income			167
Consolidated Statements of Changes in Shareholder's Equity			168
Consolidated Statements of Cash Flows			169
Notes to Consolidated Financial Statements			170


Berkshire Hathaway Energy Company and its subsidiaries						28
PacifiCorp and its subsidiaries						63
MidAmerican Funding, LLC and its subsidiaries and MidAmerican Energy Company						95
Nevada Power Company and its subsidiaries						117
Sierra Pacific Power Company and its subsidiaries						137
Eastern Energy Gas Holdings, LLC and its subsidiaries						159
Eastern Gas Transmission and Storage, Inc. and its subsidiaries						175

	Three Months Ended September 30,					Nine Months Ended September 30,
	2017		2016			2017			2016
(millions, except per share amounts)
Operating Revenue	$	3,179	$	3,132		$	9,376		$	8,651
Operating Expenses
Electric fuel and other energy-related purchases		638		606			1,711			1,791
Purchased (excess) electric capacity		21		(6	)		(8	)		107
Purchased gas		24		77			441			252
Other operations and maintenance		649		765			2,166			2,133
Depreciation, depletion and amortization		485		400			1,421			1,112
Other taxes		162		145			519			448
Total operating expenses		1,979		1,987			6,250			5,843
Income from operations		1,200		1,145			3,126			2,808
Other income		73		63			249			189
Interest and related charges		305		250			905			715
Income from operations including noncontrolling interests before income tax expense		968		958			2,470			2,282
Income tax expense		272		230			683			561
Net Income Including Noncontrolling Interests		696		728			1,787			1,721
Noncontrolling Interests		31		38			100			55
Net Income Attributable to Dominion Energy	$	665	$	690		$	1,687		$	1,666
Earnings Per Common Share
Net income attributable to Dominion Energy - Basic	$	1.03	$	1.10		$	2.66		$	2.72
Net income attributable to Dominion Energy - Diluted		1.03		1.10			2.66			2.71
Dividends Declared Per Common Share	$	0.7700	$	0.7000		$	2.2800		$	2.1000

	September 30, 2017			December 31, 2016⁽¹⁾
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	227		$	261
Customer receivables (less allowance for doubtful accounts of $16 and $18)		1,292			1,523
Other receivables (less allowance for doubtful accounts of $3 and $2)		212			183
Inventories		1,527			1,524
Regulatory assets		311			244
Other		425			513
Total current assets		3,994			4,248
Investments
Nuclear decommissioning trust funds		4,881			4,484
Investment in equity method affiliates		1,895			1,561
Other		320			298
Total investments		7,096			6,343
Property, Plant and Equipment
Property, plant and equipment		73,610			69,556
Accumulated depreciation, depletion and amortization		(20,799	)		(19,592	)
Total property, plant and equipment, net		52,811			49,964
Deferred Charges and Other Assets
Goodwill		6,405			6,399
Regulatory assets		2,503			2,473
Other		2,582			2,183
Total deferred charges and other assets		11,490			11,055
Total assets	$	75,391		$	71,610

	Common Stock					Dominion Energy Shareholders						Total Common
	Shares		Amount			Retained Earnings			AOCI			Shareholders' Equity			Noncontrolling Interests			Total Equity
(millions)
December 31, 2015		596	$	6,680		$	6,458		$	(474	)	$	12,664		$	938		$	13,602
Net income including noncontrolling interests							1,666						1,666			55			1,721
Contributions from SunEdison to Four Brothers and Three Cedars													—			178			178
Sale of interest in merchant solar projects				22									22			117			139
Purchase of Dominion Energy Midstream common units				(3	)								(3	)		(14	)		(17	)
Issuance of common stock		31		2,079									2,079						2,079
Stock awards (net of change in unearned compensation)				10									10						10
Present value of stock purchase contract payments related to RSNs				(191	)								(191	)					(191	)
Dividends and distributions							(1,287	)					(1,287	)		(39	)		(1,326	)
Other comprehensive income, net of tax										3			3						3
Other				(5	)								(5	)		(1	)		(6	)
September 30, 2016		627	$	8,592		$	6,837		$	(471	)	$	14,958		$	1,234		$	16,192

December 31, 2016		628	$	8,550		$	6,854		$	(799	)	$	14,605		$	2,235		$	16,840
Net income including noncontrolling interests							1,687						1,687			100			1,787
Contributions from NRG to Four Brothers and Three Cedars													—			9			9
Issuance of common stock		16		1,232									1,232						1,232
Stock awards (net of change in unearned compensation)				17									17						17
Dividends and distributions							(1,435	)					(1,435	)		(123	)		(1,558	)
Other comprehensive income, net of tax										171			171						171
Other				(10	)		13		.				3		1				4
September 30, 2017		644	$	9,789		$	7,119		$	(628	)	$	16,280		$	2,222		$	18,502

	Three Months Ended September 30, 2016⁽¹⁾		Nine Months Ended September 30, 2016⁽¹⁾
(millions, except EPS)
Operating Revenue	$	3,261	$	9,410
Net income attributable to Dominion Energy		732		1,835
Earnings Per Common Share – Basic	$	1.17	$	2.99
Earnings Per Common Share – Diluted	$	1.17	$	2.99

	Dominion Energy						Virginia Power						Dominion Energy Gas
Nine Months Ended September 30,	2017			2016			2017			2016			2017			2016
U.S. statutory rate		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%
Increases (reductions) resulting from:
State taxes, net of federal benefit		2.9			3.7			3.7			3.9			2.7			0.8
Investment tax credits		(5.7	)		(10.4	)		(0.8	)		—			—			—
Production tax credits		(0.7	)		(0.8	)		(0.5	)		(0.5	)		—			—
State legislative change		—			(0.8	)		—			—			—			—
AFUDC - equity		(1.3	)		(0.7	)		(0.6	)		(0.6	)		(0.8	)		(0.1	)
Other, net		(2.6	)		(1.4	)		0.2			0.1			(0.1	)		0.5
Effective tax rate		27.6	%		24.6	%		37.0	%		37.9	%		36.8	%		36.2	%

	Deferred Gains and Losses on Derivatives-Hedging Activities			Unrealized Gains and Losses on Investment Securities			Unrecognized Pension and Other Postretirement Benefit Costs			Other Comprehensive Income (Loss) From Equity Method Investee			Total
(millions)
Three Months Ended September 30, 2017
Beginning balance	$	(250	)	$	630		$	(1,058	)	$	(4	)	$	(682	)
Other comprehensive income before reclassifications: gains		11			48			—			—			59
Amounts reclassified from AOCI⁽¹⁾: (gains) losses		(15	)		(4	)		14			—			(5	)
Net current-period other comprehensive income (loss)		(4	)		44			14			—			54
Ending balance	$	(254	)	$	674		$	(1,044	)	$	(4	)	$	(628	)
Three Months Ended September 30, 2016
Beginning balance	$	(241	)	$	535		$	(781	)	$	(6	)	$	(493	)
Other comprehensive income before reclassifications: gains		14			31			15			—			60
Amounts reclassified from AOCI⁽¹⁾: (gains) losses		(34	)		(13	)		9			—			(38	)
Net current-period other comprehensive income (loss)		(20	)		18			24			—			22
Ending balance	$	(261	)	$	553		$	(757	)	$	(6	)	$	(471	)
Nine Months Ended September 30, 2017
Beginning balance	$	(280	)	$	569		$	(1,082	)	$	(6	)	$	(799	)
Other comprehensive income before reclassifications: gains		82			141			—			2			225
Amounts reclassified from AOCI⁽¹⁾: (gains) losses		(56	)		(36	)		38			—			(54	)
Net current-period other comprehensive income		26			105			38			2			171
Ending balance	$	(254	)	$	674		$	(1,044	)	$	(4	)	$	(628	)
Nine Months Ended September 30, 2016
Beginning balance	$	(176	)	$	504		$	(797	)	$	(5	)	$	(474	)
Other comprehensive income before reclassifications: gains (losses)		56			72			15			(1	)		142
Amounts reclassified from AOCI⁽¹⁾: (gains) losses		(141	)		(23	)		25			—			(139	)
Net current-period other comprehensive income (loss)		(85	)		49			40			(1	)		3
Ending balance	$	(261	)	$	553		$	(757	)	$	(6	)	$	(471	)

Details About AOCI Components	Amounts Reclassified From AOCI			Affected Line Item in the Consolidated Statements of Income
(millions)
Three Months Ended September 30, 2017
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(32	)	Operating revenue
		1		Electric fuel and other energy-related purchases
Interest rate contracts		16		Interest and related charges
Foreign currency contracts		(10	)	Other income
		(25	)
Tax		10		Income tax expense
	$	(15	)
Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities	$	(10	)	Other income
Impairment		4		Other income
		(6	)
Tax		2		Income tax expense
	$	(4	)
Unrecognized pension and other postretirement benefit costs:
Prior service (credit) costs	$	(5	)	Other operations and maintenance
Actuarial (gains) losses		26		Other operations and maintenance
		21
Tax		(7	)	Income tax expense
	$	14
Three Months Ended September 30, 2016
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(64	)	Operating revenue
		1		Purchased gas
		1		Electric fuel and other energy-related purchases
Interest rate contracts		10		Interest and related charges
Foreign currency contracts		(3	)	Other income
		(55	)
Tax		21		Income tax expense
	$	(34	)
Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities	$	(25	)	Other income
Impairment		5		Other income
		(20	)
Tax		7		Income tax expense
	$	(13	)
Unrecognized pension and other postretirement benefit costs:
Prior service (credit) costs	$	(4	)	Other operations and maintenance
Actuarial (gains) losses		17		Other operations and maintenance
		13
Tax		(4	)	Income tax expense
	$	9
Nine Months Ended September 30, 2017
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts	$	(114	)	Operating revenue
		(1	)	Electric fuel and other energy-related purchases
Interest rate contracts		39		Interest and related charges

	Fair Value (millions)		Valuation Techniques	Unobservable Input		Range	Weighted Average⁽¹⁾
Assets
Physical and financial forwards and futures:
Natural gas⁽²⁾	$	91	Discounted cash flow	Market price (per Dth)	⁽³⁾	(2) - 7		—
FTRs		19	Discounted cash flow	Market price (per MWh)	⁽³⁾	(3) - 7		1
Physical options:
Natural gas		2	Option model	Market price (per Dth)	⁽³⁾	2 - 7		4
				Price volatility	⁽⁴⁾	24% - 46%		32	%
Electricity		42	Option model	Market price (per MWh)	⁽³⁾	21 - 50		34
				Price volatility	⁽⁴⁾	0% - 78%		28	%
Total assets	$	154
Liabilities
Financial forwards:
FTRs	$	1	Discounted cash flow	Market price (per MWh)	⁽³⁾	(5) - 7		1
Total liabilities	$	1

	Operating Revenue		Electric Fuel and Other Energy - Related Purchases			Total
(millions)
Three Months Ended September 30, 2017
Total gains (losses) included in earnings	$	1	$	(12	)	$	(11	)
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		1		—			1
Three Months Ended September 30, 2016
Total gains (losses) included in earnings	$	—	$	(7	)	$	(7	)
Nine Months Ended September 30, 2017
Total gains (losses) included in earnings	$	1	$	(37	)	$	(36	)
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		1		—			1
Nine Months Ended September 30, 2016
Total gains (losses) included in earnings	$	—	$	(23	)	$	(23	)

	September 30, 2017				December 31, 2016
	Carrying Amount		Estimated Fair Value⁽¹⁾		Carrying Amount		Estimated Fair Value⁽¹⁾
(millions)
Dominion Energy
Long-term debt, including securities due within one year⁽²⁾	$	28,317	$	30,639	$	26,587	$	28,273
Junior subordinated notes⁽³⁾		3,980		4,128		2,980		2,893
Remarketable subordinated notes⁽³⁾		1,377		1,421		2,373		2,418
Virginia Power
Long-term debt, including securities due within one year⁽³⁾	$	11,346	$	12,686	$	10,530	$	11,584
Dominion Energy Gas
Long-term debt⁽⁴⁾	$	3,564	$	3,705	$	3,528	$	3,603

	September 30, 2017						December 31, 2016
	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Assets Presented in the Consolidated Balance Sheet		Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Assets Presented in the Consolidated Balance Sheet
(millions)
Commodity contracts:
Over-the-counter	$	186	$	—	$	186	$	211	$	—	$	211
Exchange		24		—		24		44		—		44
Interest rate contracts:
Over-the-counter		11		—		11		17		—		17
Foreign currency contracts:
Over-the-counter		25		—		25		—		—		—
Total derivatives, subject to a master netting or similar arrangement		246		—		246		272		—		272
Total derivatives, not subject to a master netting or similar arrangement		3		—		3		7		—		7
Total	$	249	$	—	$	249	$	279	$	—	$	279

			September 30, 2017									December 31, 2016
			Gross Amounts Not Offset in the Consolidated Balance Sheet									Gross Amounts Not Offset in the Consolidated Balance Sheet
	Net Amounts of Assets Presented in the Consolidated Balance Sheet			Financial Instruments		Cash Collateral Received		Net Amounts		Net Amounts of Assets Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Received		Net Amounts
(millions)
Commodity contracts:
Over-the-counter	$	186		$	8	$	—	$	178	$	211	$	14	$	—	$	197
Exchange		24			21		—		3		44		44		—		—
Interest rate contracts:
Over-the-counter		11			6		—		5		17		9		—		8
Foreign currency contracts:
Over-the-counter		25			4		—		21		—		—		—		—
Total	$	246		$	39	$	—	$	207	$	272	$	67	$	—	$	205

	September 30, 2017						December 31, 2016
	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet
(millions)
Commodity contracts:
Over-the-counter	$	19	$	—	$	19	$	23	$	—	$	23
Exchange		21		—		21		71		—		71
Interest rate contracts:
Over-the-counter		72		—		72		53		—		53
Foreign currency contracts:
Over-the-counter		4		—		4		6		—		6
Total derivatives, subject to a master netting or similar arrangement		116		—		116		153		—		153
Total derivatives, not subject to a master netting or similar arrangement		2		—		2		2		—		2
Total	$	118	$	—	$	118	$	155	$	—	$	155

	Current		Noncurrent
Natural Gas (bcf):
Fixed price⁽¹⁾		62		17
Basis		165		612
Electricity (MWh):
Fixed price		6,749,288		902,069
FTRs		72,126,361		—
Liquids (Gal)⁽²⁾		36,940,288		—
Interest rate⁽³⁾	$	1,100,000,000	$	5,049,890,127
Foreign currency⁽³⁾⁽⁴⁾	$	—	$	280,000,000

	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax			Maximum Term
(millions)
Commodities:
Gas	$	(1	)	$	(1	)	37 months
Electricity		7			7		15 months
Other		(4	)		(4	)	6 months
Interest rate		(260	)		(11	)	387 months
Foreign currency		4			(2	)	105 months
Total	$	(254	)	$	(11	)

	Fair Value – Derivatives under Hedge Accounting		Fair Value – Derivatives not under Hedge Accounting		Total Fair Value
(millions)
September 30, 2017
ASSETS
Current Assets
Commodity	$	19	$	83	$	102
Interest rate		9		—		9
Total current derivative assets⁽¹⁾		28		83		111
Noncurrent Assets
Commodity		1		110		111
Interest rate		2		—		2
Foreign currency		25		—		25
Total noncurrent derivative assets⁽²⁾		28		110		138
Total derivative assets	$	56	$	193	$	249
LIABILITIES
Current Liabilities
Commodity	$	15	$	25	$	40
Interest rate		21		—		21
Foreign currency		4		—		4
Total current derivative liabilities⁽³⁾		40		25		65
Noncurrent Liabilities
Commodity		—		2		2
Interest rate		51		—		51
Total noncurrent derivative liabilities⁽⁴⁾		51		2		53
Total derivative liabilities	$	91	$	27	$	118
December 31, 2016
ASSETS
Current Assets
Commodity	$	29	$	101	$	130
Interest rate		10		—		10
Total current derivative assets⁽¹⁾		39		101		140
Noncurrent Assets
Commodity		—		132		132
Interest rate		7		—		7
Total noncurrent derivative assets⁽²⁾		7		132		139
Total derivative assets	$	46	$	233	$	279
LIABILITIES
Current Liabilities
Commodity	$	51	$	41	$	92
Interest rate		33		—		33
Foreign currency		3		—		3
Total current derivative liabilities⁽³⁾		87		41		128
Noncurrent Liabilities
Commodity		1		3		4
Interest rate		20		—		20
Foreign currency		3		—		3
Total noncurrent derivative liabilities⁽⁴⁾		24		3		27
Total derivative liabilities	$	111	$	44	$	155

Derivatives in Cash Flow Hedging Relationships	Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)⁽¹⁾			Amount of Gain (Loss) Reclassified From AOCI to Income			Increase (Decrease) in Derivatives Subject to Regulatory Treatment⁽²⁾
(millions)
Three Months Ended September 30, 2017
Derivative type and location of gains (losses):
Commodity:
Operating revenue				$	32
Electric fuel and other energy-related purchases					(1	)
Total commodity	$	8		$	31		$	—
Interest rate⁽³⁾		(4	)		(16	)		(26	)
Foreign currency⁽⁴⁾		12			10			—
Total	$	16		$	25		$	(26	)
Three Months Ended September 30, 2016
Derivative type and location of gains (losses):
Commodity:
Operating revenue				$	64
Purchased gas					(1	)
Electric fuel and other energy-related purchases					(1	)
Total commodity	$	7		$	62		$	—
Interest rate⁽³⁾		3			(10	)		(16	)
Foreign currency⁽⁴⁾		12			3			—
Total	$	22		$	55		$	(16	)
Nine Months Ended September 30, 2017
Derivative type and location of gains (losses):
Commodity:
Operating revenue				$	114
Electric fuel and other energy-related purchases					1
Total commodity	$	139		$	115		$	—
Interest rate⁽³⁾		(18	)		(39	)		(60	)
Foreign currency⁽⁴⁾		10			15			—
Total	$	131		$	91		$	(60	)
Nine Months Ended September 30, 2016
Derivative type and location of gains (losses):
Commodity:
Operating revenue				$	266
Purchased gas					(9	)
Electric fuel and other energy-related purchases					(8	)
Total commodity	$	193		$	249		$	—
Interest rate⁽³⁾		(107	)		(21	)		(258	)
Foreign currency⁽⁴⁾		4			1			—
Total	$	90		$	229		$	(258	)

	September 30, 2017						December 31, 2016
	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Assets Presented in the Consolidated Balance Sheet		Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Assets Presented in the Consolidated Balance Sheet
(millions)
Commodity contracts:
Over-the-counter	$	156	$	—	$	156	$	147	$	—	$	147
Interest rate contracts:
Over-the-counter		—		—		—		6		—		6
Total derivatives, subject to a master netting or similar arrangement		156		—		156		153		—		153
Total derivatives, not subject to a master netting or similar arrangement		12		—		12		41		—		41
Total	$	168	$	—	$	168	$	194	$	—	$	194

	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax			Maximum Term
(millions)
Interest rate	$	(12	)	$	(1	)	387 months
Total	$	(12	)	$	(1	)

Derivatives in Cash Flow Hedging Relationships	Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)⁽¹⁾			Amount of Gain (Loss) Reclassified From AOCI to Income			Increase (Decrease) in Derivatives Subject to Regulatory Treatment⁽²⁾
(millions)
Three Months Ended September 30, 2017
Derivative type and location of gains (losses):
Interest rate⁽³⁾	$	(3	)	$	—		$	(26	)
Total	$	(3	)	$	—		$	(26	)
Three Months Ended September 30, 2016
Derivative type and location of gains (losses):
Interest rate⁽³⁾	$	(2	)	$	—		$	(16	)
Total	$	(2	)	$	—		$	(16	)
Nine Months Ended September 30, 2017
Derivative type and location of gains (losses):
Interest rate⁽³⁾	$	(8	)	$	(1	)	$	(60	)
Total	$	(8	)	$	(1	)	$	(60	)
Nine Months Ended September 30, 2016
Derivative type and location of gains (losses):
Interest rate⁽³⁾	$	(26	)	$	(1	)	$	(258	)
Total	$	(26	)	$	(1	)	$	(258	)

	September 30, 2017						December 31, 2016
	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet		Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Consolidated Balance Sheet		Net Amounts of Liabilities Presented in the Consolidated Balance Sheet
(millions)
Commodity contracts:
Over-the-counter	$	6	$	—	$	6	$	5	$	—	$	5
Foreign currency contracts:
Over-the-counter		4		—		4		6		—		6
Total derivatives, subject to a master netting or similar arrangement		10		—		10		11		—		11
Total	$	10	$	—	$	10	$	11	$	—	$	11

	Fair Value-Derivatives Under Hedge Accounting		Fair Value-Derivatives Not Under Hedge Accounting		Total Fair Value
(millions)
September 30, 2017
ASSETS
Current Assets
Commodity	$	—	$	1	$	1
Total current derivative assets⁽¹⁾		—		1		1
Noncurrent Assets
Foreign currency		25		—		25
Total noncurrent derivative assets⁽²⁾		25		—		25
Total derivative assets	$	25	$	1	$	26
LIABILITIES
Current Liabilities
Commodity	$	6	$	—	$	6
Foreign currency		4		—		4
Total current derivative liabilities⁽³⁾		10		—		10
Total derivative liabilities	$	10	$	—	$	10
December 31, 2016
LIABILITIES
Current Liabilities
Commodity	$	4	$	—	$	4
Foreign currency		3		—		3
Total current derivative liabilities⁽³⁾		7		—		7
Noncurrent Liabilities
Commodity		1		—		1
Foreign currency		3		—		3
Total noncurrent derivative liabilities⁽⁴⁾		4		—		4
Total derivative liabilities	$	11	$	—	$	11