Item 8. Financial Statements and Supplementary Data

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Item 8. Financial Statements and Supplementary Data


	Page Number

Dominion Energy, Inc.
Report of Independent Registered Public Accounting Firm		71
Consolidated Statements of Income for the years ended December 31, 2018, 2017 and 2016		72
Consolidated Statements of Comprehensive Income for the years ended December 31, 2018, 2017 and 2016		73
Consolidated Balance Sheets at December 31, 2018 and 2017		74
Consolidated Statements of Equity at December 31, 2018, 2017 and 2016 and for the years then ended		76
Consolidated Statements of Cash Flows for the years ended December 31, 2018, 2017 and 2016		77

Virginia Electric and Power Company
Report of Independent Registered Public Accounting Firm		79
Consolidated Statements of Income for the years ended December 31, 2018, 2017 and 2016		80
Consolidated Statements of Comprehensive Income for the years ended December 31, 2018, 2017 and 2016		81
Consolidated Balance Sheets at December 31, 2018 and 2017		82
Consolidated Statements of Common Shareholder’s Equity at December 31, 2018, 2017 and 2016 and for the years then ended		84
Consolidated Statements of Cash Flows for the years ended December 31, 2018, 2017 and 2016		85

Dominion Energy Gas Holdings, LLC
Report of Independent Registered Public Accounting Firm		87
Consolidated Statements of Income for the years ended December 31, 2018, 2017 and 2016		88
Consolidated Statements of Comprehensive Income for the years ended December 31, 2018, 2017 and 2016		89
Consolidated Balance Sheets at December 31, 2018 and 2017		90
Consolidated Statements of Equity at December 31, 2018, 2017 and 2016 and for the years then ended		92
Consolidated Statements of Cash Flows for the years ended December 31, 2018, 2017 and 2016		93

Combined Notes to Consolidated Financial Statements		95


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70

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and the Board of Directors of

Dominion Energy, Inc.

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Dominion Energy, Inc. and subsidiaries (“Dominion Energy”) at December 31, 2018 and 2017, the related consolidated statements of income, comprehensive income, equity, and cash flows, for each of the three years in the period ended December 31, 2018, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Dominion Energy at December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), Dominion Energy’s internal control over financial reporting at December 31, 2018, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2019, expressed an unqualified opinion on Dominion Energy’s internal control over financial reporting.

Basis for Opinion

These consolidated financial statements are the responsibility of Dominion Energy’s management. Our responsibility is to express an opinion on Dominion Energy’s consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to Dominion 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 audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Deloitte & Touche LLP

Richmond, Virginia

February 28, 2019

We have served as Dominion Energy’s auditor since 1988.


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Dominion Energy, Inc.

Consolidated Statements of Income


Year Ended December 31,	2018			2017			2016
(millions, except per share amounts)

Operating Revenue(1)	$	13,366		$	12,586		$	11,737
Operating Expenses
Electric fuel and other energy-related purchases		2,814			2,301			2,333
Purchased electric capacity		122			6			99
Purchased gas		645			701			459
Other operations and maintenance		3,458			3,200			3,279
Depreciation, depletion and amortization		2,000			1,905			1,559
Other taxes		703			668			596
Impairment of assets and related charges		403			15			4
Gains on sales of assets		(380	)		(147	)		(40	)
Total operating expenses		9,765			8,649			8,289
Income from operations		3,601			3,937			3,448
Other income(1)		1,021			358			429
Interest and related charges		1,493			1,205			1,010
Income from operations including noncontrolling interests before income tax expense (benefit)		3,129			3,090			2,867
Income tax expense (benefit)		580			(30	)		655
Net Income Including Noncontrolling Interests		2,549			3,120			2,212
Noncontrolling Interests		102			121			89
Net Income Attributable to Dominion Energy	$	2,447		$	2,999		$	2,123
Earnings Per Common Share
Net income attributable to Dominion Energy—Basic	$	3.74		$	4.72		$	3.44
Net income attributable to Dominion Energy—Diluted	$	3.74		$	4.72		$	3.44

(1)	See Note 9 for amounts attributable to related parties.

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


72

Dominion Energy, Inc.

Consolidated Statements of Comprehensive Income


Year Ended December 31,	2018			2017			2016
(millions)

Net Income Including Noncontrolling Interests	$	2,549		$	3,120		$	2,212
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities, net of $(10), $(3) and $(37) tax		30			8			55
Changes in unrealized net gains (losses) on investment securities, net of $5, $(121) and $(53) tax		(18	)		215			93
Changes in net unrecognized pension and other postretirement benefit costs, net of $75, $32 and $189 tax		(215	)		(69	)		(319	)
Amounts reclassified to net income:
Net derivative (gains) losses-hedging activities, net of $(35), $18 and $100 tax		102			(29	)		(159	)
Net realized (gains) losses on investment securities, net of $(2), $21 and $15 tax		5			(37	)		(28	)
Net pension and other postretirement benefit costs, net of $(21), $(32) and $(22) tax		78			50			34
Changes in other comprehensive gains (losses) from equity method investees, net of $(1), $(2) and $— tax		1			3			(1	)
Total other comprehensive income (loss)		(17	)		141			(325	)
Comprehensive income including noncontrolling interests		2,532			3,261			1,887
Comprehensive income attributable to noncontrolling interests		103			122			89
Comprehensive income attributable to Dominion Energy	$	2,429		$	3,139		$	1,798

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


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Dominion Energy, Inc.

Consolidated Balance Sheets


At December 31,	2018			2017
(millions)

ASSETS

Current Assets
Cash and cash equivalents	$	268		$	120
Customer receivables (less allowance for doubtful accounts of $14 and $17)		1,749			1,660
Other receivables (less allowance for doubtful accounts of $4 and $2)(1)		331			126
Inventories:
Materials and supplies		1,039			1,049
Fossil fuel		287			328
Gas stored		92			100
Prepayments		265			260
Regulatory assets		496			294
Other		634			397
Total current assets		5,161			4,334
Investments
Nuclear decommissioning trust funds		4,938			5,093
Investment in equity method affiliates		1,278			1,544
Other		344			327
Total investments		6,560			6,964
Property, Plant and Equipment
Property, plant and equipment		76,578			74,823
Accumulated depreciation, depletion and amortization		(22,018	)		(21,065	)
Total property, plant and equipment, net		54,560			53,758
Deferred Charges and Other Assets
Goodwill		6,410			6,405
Pension and other postretirement benefit assets		1,279			1,378
Intangible assets, net		670			685
Regulatory assets		2,676			2,480
Other		598			581
Total deferred charges and other assets		11,633			11,529
Total assets	$	77,914		$	76,585

(1)	See Note 9 for amounts attributable to related parties.


74


At December 31,	2018			2017
(millions)

LIABILITIES AND EQUITY

Current Liabilities
Securities due within one year	$	3,624		$	3,078
Credit facility borrowings		73			—
Short-term debt		334			3,298
Accounts payable		914			875
Accrued interest, payroll and taxes		836			848
Other		1,866			1,537
Total current liabilities		7,647			9,636
Long-Term Debt
Long-term debt		26,328			25,588
Junior subordinated notes		3,430			3,981
Remarketable subordinated notes		1,386			1,379
Total long-term debt		31,144			30,948
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		5,116			4,523
Regulatory liabilities		6,840			6,916
Asset retirement obligations		2,250			2,169
Pension and other postretirement benefit liability		2,328			2,160
Other(1)		541			863
Total deferred credits and other liabilities		17,075			16,631
Total liabilities		55,866			57,215
Commitments and Contingencies (see Note 22)
Equity
Common stock – no par(2)		12,588			9,865
Retained earnings		9,219			7,936
Accumulated other comprehensive loss		(1,700	)		(659	)
Total common shareholders’ equity		20,107			17,142
Noncontrolling interests		1,941			2,228
Total equity		22,048			19,370
Total liabilities and equity	$	77,914		$	76,585

(1)	See Note 9 for amounts attributable to related parties.

(2)	1 billion shares authorized; 681 million shares and 645 million shares outstanding at December 31, 2018 and 2017, respectively.

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


				75

Dominion Energy, Inc.

Consolidated Statements of Equity


	Common Stock					Dominion Energy Shareholders
	Shares		Amount			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Common 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							2,123						2,123			89			2,212
Contributions from SunEdison to Four Brothers and Three Cedars													—			189			189
Sale of interest in merchant solar projects				22									22			117			139
Sale of Dominion Energy Midstream common units—net of offering costs													—			482			482
Sale of Dominion Energy Midstream convertible preferred units—net of offering costs													—			490			490
Purchase of Dominion Energy Midstream common units				(3	)								(3	)		(14	)		(17	)
Issuance of common stock		32		2,152									2,152						2,152
Stock awards (net of change in unearned compensation)				14									14						14
Present value of stock purchase contract payments related to RSNs(1)				(191	)								(191	)					(191	)
Tax effect of Dominion Energy Questar Pipeline contribution to Dominion Energy Midstream				(116	)								(116	)					(116	)
Dividends ($2.80 per common share) and distributions							(1,727	)					(1,727	)		(62	)		(1,789	)
Other comprehensive loss, net of tax										(325	)		(325	)					(325	)
Other				(8	)								(8	)		6			(2	)
December 31, 2016		628	$	8,550		$	6,854		$	(799	)	$	14,605		$	2,235		$	16,840
Net income including noncontrolling interests							2,999						2,999			121			3,120
Contributions from NRG to Four Brothers and Three Cedars													—			9			9
Issuance of common stock		17		1,302									1,302						1,302
Sale of Dominion Energy Midstream common units—net of offering costs													—			18			18
Stock awards (net of change in unearned compensation)				22									22						22
Dividends ($3.035 per common share) and distributions							(1,931	)					(1,931	)		(156	)		(2,087	)
Other comprehensive income, net of tax										140			140			1			141
Other				(9	)		14						5						5
December 31, 2017		645	$	9,865		$	7,936		$	(659	)	$	17,142		$	2,228		$	19,370
Cumulative-effect of changes in accounting principles				(127	)		1,029			(1,023	)		(121	)		127			6
Net income including noncontrolling interests							2,447						2,447			102			2,549
Issuance of common stock		36		2,461									2,461						2,461
Sale of Dominion Energy Midstream common units—net of offering costs													—			4			4
Remeasurement of noncontrolling interest in Dominion Energy Midstream				375									375			(375	)		—
Stock awards (net of change in unearned compensation)				22									22						22
Dividends ($3.34 per common share) and distributions							(2,185	)					(2,185	)		(146	)		(2,331	)
Other comprehensive income (loss), net of tax										(18	)		(18	)		1			(17	)
Other				(8	)		(8	)					(16	)					(16	)
December 31, 2018		681	$	12,588		$	9,219		$	(1,700	)	$	20,107		$	1,941		$	22,048

(1)	See Note 17 for further information.

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


76

Dominion Energy, Inc.

Consolidated Statements of Cash Flows


Year Ended December 31,	2018			2017			2016
(millions)

Operating Activities
Net income including noncontrolling interests	$	2,549		$	3,120		$	2,212
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities:
Depreciation, depletion and amortization (including nuclear fuel)		2,280			2,202			1,849
Deferred income taxes and investment tax credits		517			(3	)		725
Current income tax for Dominion Energy Questar Pipeline contribution to Dominion Energy Midstream		—			—			(212	)
Proceeds from assignment of tower rental portfolio		—			91			—
Contribution to pension plan		—			(75	)		—
Gains on sales of assets and equity method investments		(1,006	)		(148	)		(50	)
Provision for rate credits to electric utility customers		77			—			—
Charges associated with equity method investments		—			158			—
Charges associated with future ash pond and landfill closure costs		81			—			197
Impairment of assets and related charges		395			15			4
Net (gains) losses on nuclear decommissioning trusts funds and other investments		102			(117	)		(96	)
Other adjustments		19			33			8
Changes in:
Accounts receivable		(110	)		(103	)		(286	)
Inventories		(29	)		15			1
Deferred fuel and purchased gas costs, net		(247	)		(71	)		54
Prepayments		(51	)		(62	)		21
Accounts payable		67			(89	)		97
Accrued interest, payroll and taxes		(12	)		64			203
Margin deposit assets and liabilities		—			(10	)		(66	)
Net realized and unrealized changes related to derivative activities		181			44			(335	)
Asset retirement obligations		(35	)		(94	)		(61	)
Pension and other postretirement benefits		(114	)		(177	)		(152	)
Other operating assets and liabilities		109			(291	)		38
Net cash provided by operating activities		4,773			4,502			4,151
Investing Activities
Plant construction and other property additions (including nuclear fuel)		(4,254	)		(5,504	)		(6,085	)
Acquisition of Dominion Energy Questar, net of cash acquired		—			—			(4,381	)
Acquisition of solar development projects		(151	)		(405	)		(40	)
Proceeds from sales of securities		1,804			1,831			1,422
Purchases of securities		(1,894	)		(1,940	)		(1,504	)
Proceeds from the sale of certain retail energy marketing assets		54			68			—
Proceeds from sales of assets and equity method investments		2,379			—			—
Proceeds from assignment of shale development rights		109			70			10
Contributions to equity method affiliates		(428	)		(370	)		(198	)
Distributions from equity method affiliates		36			275			2
Other		(13	)		33			83
Net cash used in investing activities		(2,358	)		(5,942	)		(10,691	)
Financing Activities
Issuance (repayment) of short-term debt, net		(2,964	)		143			(654	)
Issuance of short-term notes		1,450			—			1,200
Repayment and repurchase of short-term notes		(1,450	)		(250	)		(1,800	)
Issuance and remarketing of long-term debt		6,362			3,880			7,722
Repayment and repurchase of long-term debt (including redemption premiums)		(5,682	)		(1,572	)		(1,610	)
Credit facility borrowings		73			—			—
Net proceeds from issuance of Dominion Energy Midstream common units		4			18			482
Net proceeds from issuance of Dominion Energy Midstream preferred units		—			—			490
Proceeds from sale of interest in merchant solar projects		—			—			117
Contributions from NRG and SunEdison to Four Brothers and Three Cedars		—			9			189
Issuance of common stock		2,461			1,302			2,152
Common dividend payments		(2,185	)		(1,931	)		(1,727	)
Other		(278	)		(296	)		(331	)
Net cash provided by (used in) financing activities		(2,209	)		1,303			6,230
Increase (decrease) in cash, restricted cash and equivalents		206			(137	)		(310	)
Cash, restricted cash and equivalents at beginning of year		185			322			632
Cash, restricted cash and equivalents at end of year	$	391		$	185		$	322
Supplemental Cash Flow Information
Cash paid during the year for:
Interest and related charges, excluding capitalized amounts	$	1,362		$	1,083		$	905
Income taxes		89			9			145
Significant noncash investing and financing activities:(1)(2)
Accrued capital expenditures		307			343			427
Receivables from sales of assets and equity method investments		159			—			—
Guarantee provided by equity method affiliate		—			30			—

(1)	See Note 9 for noncash activities related to equity method investments.

(2)	See Note 19 for noncash activities related to the remeasurement of Dominion Energy’s noncontrolling interest in Dominion Energy Midstream.

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


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78

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Virginia Electric and Power Company

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Virginia Electric and Power Company (a wholly-owned subsidiary of Dominion Energy, Inc.) and subsidiaries (“Virginia Power”) at December 31, 2018 and 2017, the related consolidated statements of income, comprehensive income, common shareholder’s equity, and cash flows, for each of the three years in the period ended December 31, 2018, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Virginia Power at December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These consolidated financial statements are the responsibility of Virginia Power’s management. Our responsibility is to express an opinion on Virginia Power’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Virginia 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.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Virginia Power is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Virginia Power’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Deloitte & Touche LLP

Richmond, Virginia

February 28, 2019

We have served as Virginia Power’s auditor since 1988.


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Virginia Electric and Power Company

Consolidated Statements of Income


Year Ended December 31,	2018		2017		2016
(millions)

Operating Revenue(1)	$	7,619	$	7,556	$	7,588
Operating Expenses
Electric fuel and other energy-related purchases(1)		2,318		1,909		1,973
Purchased electric capacity		122		6		99
Other operations and maintenance:
Affiliated suppliers		305		309		310
Other		1,371		1,169		1,547
Depreciation and amortization		1,132		1,141		1,025
Other taxes		300		290		284
Total operating expenses		5,548		4,824		5,238
Income from operations		2,071		2,732		2,350
Other income		22		76		56
Interest and related charges(1)		511		494		461
Income from operations before income tax expense		1,582		2,314		1,945
Income tax expense		300		774		727
Net Income	$	1,282	$	1,540	$	1,218

(1)	See Note 24 for amounts attributable to affiliates.

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


80

Virginia Electric and Power Company

Consolidated Statements of Comprehensive Income


Year Ended December 31,	2018		2017			2016
(millions)

Net Income	$	1,282	$	1,540		$	1,218
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities, net of $(1), $3 and $1 tax		1		(5	)		(2	)
Changes in unrealized net gains (losses) on nuclear decommissioning trust funds, net of $—, $(16) and $(7) tax		—		24			11
Amounts reclassified to net income:
Net derivative (gains) losses-hedging activities, net of $—, $— and $— tax		1		1			1
Net realized (gains) losses on nuclear decommissioning trust funds, net of $—, $3 and $2 tax		—		(4	)		(4	)
Other comprehensive income		2		16			6
Comprehensive income	$	1,284	$	1,556		$	1,224

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


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Virginia Electric and Power Company

Consolidated Balance Sheets


At December 31,	2018			2017
(millions)

ASSETS

Current Assets
Cash and cash equivalents	$	29		$	14
Customer receivables (less allowance for doubtful accounts of $9 and $10)		999			951
Other receivables (less allowance for doubtful accounts of $3 and $1)		76			64
Affiliated receivables		101			3
Inventories (average cost method):
Materials and supplies		550			531
Fossil fuel		287			319
Prepayments		28			27
Regulatory assets		424			205
Other(1)		77			110
Total current assets		2,571			2,224

Investments
Nuclear decommissioning trust funds		2,369			2,399
Other		3			3
Total investments		2,372			2,402

Property, Plant and Equipment
Property, plant and equipment		44,524			42,329
Accumulated depreciation and amortization		(14,003	)		(13,277	)
Total property, plant and equipment, net		30,521			29,052

Deferred Charges and Other Assets
Pension and other postretirement benefit assets(1)		254			199
Intangible assets		250			233
Regulatory assets		737			810
Other(1)		175			219
Total deferred charges and other assets		1,416			1,461
Total assets	$	36,880		$	35,139

(1)	See Note 24 for amounts attributable to affiliates.


82


At December 31,	2018			2017
(millions)

LIABILITIES AND COMMON SHAREHOLDER’S EQUITY

Current Liabilities
Securities due within one year	$	350		$	850
Short-term debt		314			542
Accounts payable		339			361
Payables to affiliates		209			125
Affiliated current borrowings		224			33
Accrued interest, payroll and taxes		248			256
Asset retirement obligations		245			216
Regulatory liabilities		299			127
Other(1)		587			410
Total current liabilities		2,815			2,920
Long-Term Debt		11,321			10,496
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		3,017			2,728
Asset retirement obligations		1,200			1,149
Regulatory liabilities		4,647			4,760
Pension and other postretirement benefit liability(1)		632			505
Other		201			357
Total deferred credits and other liabilities		9,697			9,499
Total liabilities		23,833			22,915
Commitments and Contingencies (see Note 22)
Common Shareholder’s Equity
Common stock – no par(2)		5,738			5,738
Other paid-in capital		1,113			1,113
Retained earnings		6,208			5,311
Accumulated other comprehensive income (loss)		(12	)		62
Total common shareholder’s equity		13,047			12,224
Total liabilities and shareholder’s equity	$	36,880		$	35,139

(1)	See Note 24 for amounts attributable to affiliates.

(2)	500,000 shares authorized; 274,723 shares outstanding at December 31, 2018 and 2017.

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


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Virginia Electric and Power Company

Consolidated Statements of Common Shareholder’s Equity


		Common Stock					Other Paid-In Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
	Shares			Amount
(millions, except for shares)		(thousands)

December 31, 2015			275		$	5,738	$	1,113	$	3,750		$	40		$	10,641
Net income										1,218						1,218
Other comprehensive income, net of tax													6			6
December 31, 2016			275			5,738		1,113		4,968			46			11,865
Net income										1,540						1,540
Dividends										(1,199	)					(1,199	)
Other comprehensive income, net of tax													16			16
Other										2						2
December 31, 2017			275			5,738		1,113		5,311			62			12,224
Cumulative-effect of changes in accounting principles										79			(76	)		3
Net income										1,282						1,282
Dividends										(464	)					(464	)
Other comprehensive income, net of tax													2			2
December 31, 2018			275		$	5,738	$	1,113	$	6,208		$	(12	)	$	13,047

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


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Virginia Electric and Power Company

Consolidated Statements of Cash Flows


Year Ended December 31,	2018			2017			2016
(millions)

Operating Activities
Net income	$	1,282		$	1,540		$	1,218
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization (including nuclear fuel)		1,309			1,333			1,210
Deferred income taxes and investment tax credits		224			269			469
Proceeds from assignment of rental portfolio		—			91			—
Charges associated with future ash pond and landfill closure costs		81			—			197
Provision for rate credits to customers		77			—			—
Other adjustments		(21	)		(36	)		(16	)
Changes in:
Accounts receivable		(60	)		(27	)		(65	)
Affiliated receivables and payables		(14	)		125			220
Inventories		13			3			20
Prepayments		(1	)		3			8
Deferred fuel expenses, net		(269	)		(59	)		69
Accounts payable		(26	)		(42	)		25
Accrued interest, payroll and taxes		(8	)		17			49
Net realized and unrealized changes related to derivative activities		119			13			(153	)
Asset retirement obligations		(54	)		(88	)		(59	)
Other operating assets and liabilities		188			(181	)		77
Net cash provided by operating activities		2,840			2,961			3,269
Investing Activities
Plant construction and other property additions		(2,228	)		(2,496	)		(2,489	)
Purchases of nuclear fuel		(173	)		(192	)		(153	)
Acquisition of solar development projects		(141	)		(41	)		(7	)
Purchases of securities		(925	)		(884	)		(775	)
Proceeds from sales of securities		887			849			733
Other		(63	)		(41	)		(33	)
Net cash used in investing activities		(2,643	)		(2,805	)		(2,724	)
Financing Activities
Issuance (repayment) of short-term debt, net		(228	)		477			(1,591	)
Issuance (repayment) of affiliated current borrowings, net		191			(229	)		(114	)
Issuance and remarketing of long-term debt		1,300			1,500			1,688
Repayment and repurchase of long-term debt		(964	)		(681	)		(517	)
Common dividend payments to parent		(464	)		(1,199	)		—
Other		(18	)		(11	)		(18	)
Net cash used in financing activities		(183	)		(143	)		(552	)
Increase (decrease) in cash, restricted cash and equivalents		14			13			(7	)
Cash, restricted cash and equivalents at beginning of year		24			11			18
Cash, restricted cash and equivalents at end of year	$	38		$	24		$	11
Supplemental Cash Flow Information
Cash paid during the year for:
Interest and related charges, excluding capitalized amounts	$	498		$	458		$	435
Income taxes		128			362			79
Significant noncash investing activities:
Accrued capital expenditures		204			169			256

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


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86

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of

Dominion Energy Gas Holdings, LLC

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Dominion Energy Gas Holdings, LLC (a wholly-owned subsidiary of Dominion Energy, Inc.) and subsidiaries (“Dominion Energy Gas”) at December 31, 2018 and 2017, the related consolidated statements of income, comprehensive income, equity, and cash flows, for each of the three years in the period ended December 31, 2018, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Dominion Energy Gas at December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These consolidated financial statements are the responsibility of Dominion Energy Gas’ management. Our responsibility is to express an opinion on Dominion Energy Gas’ consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to Dominion Energy Gas 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 audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Dominion Energy Gas is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of Dominion Energy Gas’ internal control over financial reporting. Accordingly, we express no such opinion.

/s/ Deloitte & Touche LLP

Richmond, Virginia

February 28, 2019

We have served as Dominion Energy Gas’ auditor since 2012.


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Dominion Energy Gas Holdings, LLC

Consolidated Statements of Income


Year Ended December 31,	2018			2017			2016
(millions)

Operating Revenue(1)	$	1,940		$	1,814		$	1,638
Operating Expenses
Purchased gas(1)		40			132			109
Other energy-related purchases		135			21			12
Other operations and maintenance:
Affiliated suppliers		94			87			81
Other(1)		665			578			514
Depreciation and amortization		244			227			204
Other taxes		200			185			170
Impairment of assets and related charges		346			16			—
Gains on sales of assets		(119	)		(70	)		(45	)
Total operating expenses		1,605			1,176			1,045
Income from operations		335			638			593
Earnings from equity method investee		24			21			21
Other income		133			104			87
Interest and related charges(1)		105			97			94
Income from operations before income tax expense		387			666			607
Income tax expense		86			51			215
Net Income	$	301		$	615		$	392

(1)	See Note 24 for amounts attributable to related parties.

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


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Dominion Energy Gas Holdings, LLC

Consolidated Statements of Comprehensive Income


Year Ended December 31,	2018			2017			2016
(millions)

Net Income	$	301		$	615		$	392
Other comprehensive income (loss), net of taxes:
Net deferred gains (losses) on derivatives-hedging activities, net of $6, $(3) and $10 tax		(17	)		5			(16	)
Changes in net unrecognized pension benefit (costs) , net of $20, $(8) and $14 tax		(52	)		20			(20	)
Amounts reclassified to net income:
Net derivative (gains) losses-hedging activities, net of $(7), $3 and $(6) tax		20			(4	)		9
Net pension and other postretirement benefit costs, net of $(2), $(2) and $(2) tax		4			4			3
Other comprehensive income (loss)		(45	)		25			(24	)
Comprehensive income	$	256		$	640		$	368

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


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Dominion Energy Gas Holdings, LLC

Consolidated Balance Sheets


At December 31,	2018			2017
(millions)

ASSETS
Current Assets
Cash and cash equivalents	$	10		$	4
Customer receivables (less allowance for doubtful accounts of less than $1 and $1)(1)		309			297
Other receivables (less allowance for doubtful accounts of $2 and $1)(1)		17			15
Affiliated receivables		10			10
Inventories:
Materials and supplies		53			55
Gas stored		12			9
Prepayments		116			112
Gas imbalances(1)		162			46
Other(1)		58			52
Total current assets		747			600
Investments		93			97
Property, Plant and Equipment
Property, plant and equipment		11,238			11,173
Accumulated depreciation and amortization		(2,971	)		(3,018	)
Total property, plant and equipment, net		8,267			8,155
Deferred Charges and Other Assets
Goodwill		547			542
Intangible assets, net		109			109
Pension and other postretirement benefit assets(1)		1,775			1,828
Regulatory assets		727			511
Other(1)		86			98
Total deferred charges and other assets		3,244			3,088
Total assets	$	12,351		$	11,940

(1)	See Note 24 for amounts attributable to related parties.


90


At December 31,	2018			2017
(millions)

LIABILITIES AND EQUITY
Current Liabilities
Securities due within one year	$	449		$	—
Short-term debt		10			629
Accounts payable		196			193
Payables to affiliates		65			62
Affiliated current borrowings		218			18
Accrued interest, payroll and taxes		265			250
Other(1)		198			189
Total current liabilities		1,401			1,341
Long-Term Debt		3,609			3,570
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		1,465			1,454
Regulatory liabilities		1,285			1,227
Other(1)		194			185
Total deferred credits and other liabilities		2,944			2,866
Total liabilities		7,954			7,777
Commitments and Contingencies (see Note 22)
Equity
Membership interests		4,566			4,261
Accumulated other comprehensive loss		(169	)		(98	)
Total equity		4,397			4,163
Total liabilities and equity	$	12,351		$	11,940

(1)	See Note 24 for amounts attributable to related parties.

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


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Dominion Energy Gas Holdings, LLC

Consolidated Statements of Equity


	Membership Interests			Accumulated Other Comprehensive Income (Loss)			Total
(millions)

December 31, 2015	$	3,417		$	(99	)	$	3,318
Net income		392						392
Distributions		(150	)					(150	)
Other comprehensive loss, net of tax					(24	)		(24	)
December 31, 2016		3,659			(123	)		3,536
Net income		615						615
Distributions		(15	)					(15	)
Other comprehensive income, net of tax					25			25
Other		2						2
December 31, 2017		4,261			(98	)		4,163
Cumulative-effect of changes in accounting principles		29			(26	)		3
Net income		301						301
Distributions		(25	)					(25	)
Other comprehensive loss, net of tax					(45	)		(45	)
December 31, 2018	$	4,566		$	(169	)	$	4,397

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


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Dominion Energy Gas Holdings, LLC

Consolidated Statements of Cash Flows


Year Ended December 31,	2018			2017			2016
(millions)

Operating Activities
Net income	$	301		$	615		$	392
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		244			227			204
Deferred income taxes and investment tax credits		33			27			238
Gains on sales of assets		(109	)		(70	)		(50	)
Impairment of assets and related charges		348			15			—
Other adjustments		(7	)		(7	)		(6	)
Changes in:
Accounts receivable		(14	)		(17	)		(68	)
Affiliated receivables and payables		3			40			88
Inventories		(1	)		6			8
Prepayments		(4	)		(18	)		(6	)
Accounts payable		(5	)		(17	)		15
Accrued interest, payroll and taxes		15			24			42
Pension and other postretirement benefits		(155	)		(143	)		(141	)
Other operating assets and liabilities		(17	)		(16	)		(68	)
Net cash provided by operating activities		632			666			648
Investing Activities
Plant construction and other property additions		(772	)		(778	)		(854	)
Proceeds from sale of equity method investment in Iroquois		—			—			7
Proceeds from assignments of shale development rights		109			70			10
Other		(16	)		(19	)		(12	)
Net cash used in investing activities		(679	)		(727	)		(849	)
Financing Activities
Issuance (repayment) of short-term debt, net		(619	)		169			69
Issuance (repayment) of affiliated current borrowings, net		200			(100	)		23
Issuance of long-term debt		500			—			680
Repayment of long-term debt		—			—			(400	)
Distribution payments to parent		(25	)		(15	)		(150	)
Other		(5	)		(6	)		(5	)
Net cash provided by financing activities		51			48			217
Increase (decrease) in cash, restricted cash and equivalents		4			(13	)		16
Cash, restricted cash and equivalents at beginning of year		30			43			27
Cash, restricted cash and equivalents at end of year	$	34		$	30		$	43
Supplemental Cash Flow Information
Cash paid (received) during the year for:
Interest and related charges, excluding capitalized amounts	$	95		$	89		$	81
Income taxes		79			9			(92	)
Significant noncash investing activities:
Accrued capital expenditures		38			38			59

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


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94

Combined Notes to Consolidated Financial Statements

NOTE 1. NATURE OF OPERATIONS

Dominion 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. Virginia Power is a member of PJM, an RTO, and its electric transmission facilities are integrated into the PJM wholesale electricity markets. All of Virginia Power’s stock is owned by Dominion Energy. Dominion Energy Gas is a holding company that conducts business activities through a regulated interstate natural gas transmission pipeline and underground storage system in the Northeast, mid-Atlantic and Midwest states, regulated gas transportation and distribution operations in Ohio, and gas gathering and processing activities primarily in West Virginia, Ohio and Pennsylvania. All of Dominion Energy Gas’ membership interests are held by Dominion Energy. The SCANA Combination was completed in January 2019. See Note 3 for a description of operations acquired in the SCANA Combination.

Dominion Energy’s operations also include the Cove Point LNG Facility, Cove Point Pipeline, Liquefaction Project, an equity investment in Atlantic Coast Pipeline and regulated gas transportation and distribution operations primarily in the eastern and Rocky Mountain regions of the U.S. Dominion Energy’s nonregulated operations include merchant generation, energy marketing and price risk management activities and retail energy marketing operations.

At December 31, 2018, Dominion Energy owned the general partner, 60.9% of the common units and 37.5% of the convertible preferred interests in Dominion Energy Midstream, which owned a preferred equity interest and the general partner interest in Cove Point, DECG, Dominion Energy Questar Pipeline and a 25.93% noncontrolling partnership interest in Iroquois. In January 2019, Dominion Energy acquired all outstanding partnership interests not owned by Dominion Energy and Dominion Energy Midstream became a wholly-owned subsidiary of Dominion Energy. At December 31, 2018, the public’s ownership interest in Dominion Energy Midstream is reflected as noncontrolling interest in Dominion Energy’s Consolidated Financial Statements.

Through December 2018, Dominion Energy managed its daily operations through three primary operating segments: Power Delivery, Power Generation and Gas Infrastructure. Dominion Energy also reports a Corporate and Other segment, which includes its corporate, service company and other functions (including unallocated debt). In addition, Corporate and Other includes specific items attributable to Dominion Energy’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or in allocating resources. Subsequent to the SCANA Combination, Dominion Energy manages the operations of SCANA through an additional operating segment, Southeast Energy.

Virginia Power manages its daily operations through two primary operating segments: Power Delivery and Power Generation. It also reports a Corporate and Other segment that 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.

Dominion Energy Gas manages its daily operations through one primary operating segment: Gas Infrastructure. It also reports a Corporate and Other segment that primarily includes specific items attributable to its operating segment that are not included in profit measures evaluated by executive management in assessing the segment’s performance or in allocating resources and the effect of certain items recorded at Dominion Energy Gas as a result of Dominion Energy’s basis in the net assets contributed.

See Note 25 for further discussion of the Companies’ operating segments.

NOTE 2. SIGNIFICANT ACCOUNTING POLICIES

General

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, expenses and cash flows for the periods presented. Actual results may differ from those estimates.

The Companies’ Consolidated Financial Statements include, after eliminating intercompany transactions and balances, their accounts, those of their respective majority-owned subsidiaries and non-wholly-owned entities in which they have a controlling financial interest. For certain partnership structures, income is allocated based on the liquidation value of the underlying contractual arrangements. At December 31, 2018, Dominion Energy owns 50% of the voting interests in Four Brothers and Three Cedars and has a controlling financial interest over the entities through its rights to control operations. In August 2018, NRG’s ownership interest in Four Brothers and Three Cedars was transferred to GIP. GIP’s ownership interest in Four Brothers and Three Cedars, Terra Nova Renewable Partners’ 33% interest in certain of Dominion Energy’s merchant solar projects and the non-Dominion Energy held interest in Dominion Energy Midstream (through January 2019), is reflected as noncontrolling interest in Dominion Energy’s Consolidated Financial Statements. Terra Nova Renewable Partners has a future option to buy all or a portion of Dominion Energy’s remaining 67% ownership in certain merchant projects upon the occurrence of certain events, none of which are expected to occur in 2019.

The Companies report certain contracts, instruments and investments at fair value. See Note 6 for further information on fair value measurements.

The Companies consider acquisitions or dispositions in which substantially all of the fair value of the gross assets acquired or disposed of is concentrated into a single identifiable asset or group of similar identifiable assets to be an acquisition or a disposition of an asset, rather than a business. See Notes 3 and 10 for further information on such transactions.

Dominion Energy maintains pension and other postretirement benefit plans. Virginia Power and Dominion Energy Gas participate in certain of these plans. See Note 21 for further information on these plans.

Certain amounts in the Companies’ 2017 and 2016 Consolidated Financial Statements and Notes have been reclassified to


				95

Combined Notes to Consolidated Financial Statements, Continued

conform to the 2018 presentation for comparative purposes; however, such reclassifications did not affect the Companies’ net income, total assets, liabilities, equity or cash flows.

Amounts disclosed for Dominion Energy are inclusive of Virginia Power and/or Dominion Energy Gas, where applicable.

Operating Revenue

Operating revenue is recorded on the basis of services rendered, commodities delivered or contracts settled and includes amounts yet to be billed to customers. Dominion Energy and Virginia Power collect sales, consumption and consumer utility taxes and Dominion Energy Gas collects sales taxes; however, these amounts are excluded from revenue. Dominion Energy’s customer receivables at December 31, 2018 and 2017 included $626 million and $661 million, respectively, of accrued unbilled revenue based on estimated amounts of electricity and natural gas delivered but not yet billed to its utility customers. Virginia Power’s customer receivables at December 31, 2018 and 2017 included $392 million and $400 million, respectively, of accrued unbilled revenue based on estimated amounts of electricity delivered but not yet billed to its customers. Dominion Energy Gas’ customer receivables at December 31, 2018 and 2017 included $131 million and $121 million, respectively, of accrued unbilled revenue based on estimated amounts of natural gas delivered but not yet billed to its customers. See Note 24 for amounts attributable to related parties.

The primary types of sales and service activities reported as operating revenue for Dominion Energy, subsequent to the adoption of revised guidance for revenue recognition from contracts with customers, are as follows:

REVENUE FROM CONTRACTS WITH CUSTOMERS

•		Regulated electric sales consist primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services;

•		Nonregulated electric sales consist primarily of sales of electricity at market-based rates and contracted fixed rates, and associated hedging activity;

•		Regulated gas sales consist primarily of state-regulated natural gas sales and related distribution services;

•		Nonregulated gas sales consist primarily of sales of natural gas production at market-based rates and contracted fixed prices, sales of gas purchased from third parties and associated hedging activity;

•		Regulated gas transportation and storage sales consist of FERC-regulated sales of transmission and storage services and state-regulated gas distribution charges to retail distribution service customers opting for alternate suppliers and sales of gathering services;

•		Nonregulated gas transportation and storage sales consist primarily of LNG terminalling services;

•		Other regulated revenue consists primarily of miscellaneous service revenue from electric and gas distribution operations and sales of excess electric capacity and other commodities; and

•		Other nonregulated revenue consists primarily of NGL gathering and processing, sales of NGL production and condensate, extracted products and associated hedging activity. Other nonregulated revenue also includes services performed for Atlantic Coast Pipeline, sales of energy-related products

		and services from Dominion Energy’s retail energy marketing operations, service concession arrangements and gas processing and handling revenue.

OTHER REVENUE

•		Other revenue consists primarily of alternative revenue programs, gains and losses from derivative instruments not subject to hedge accounting and lease revenues.

The primary types of sales and service activities reported as operating revenue for Dominion Energy, prior to the adoption of revised guidance for revenue recognition from contracts with customers, were as follows:

•		Regulated electric sales consisted primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services;

•		Nonregulated electric sales consisted primarily of sales of electricity at market-based rates and contracted fixed rates, and associated derivative activity;

•		Regulated gas sales consisted primarily of state- and FERC-regulated natural gas sales and related distribution services and associated derivative activity;

•		Nonregulated gas sales consisted primarily of sales of natural gas production at market-based rates and contracted fixed prices, sales of gas purchased from third parties, gas trading and marketing revenue and associated derivative activity;

•		Gas transportation and storage sales consisted primarily of FERC-regulated sales of transmission and storage services. Also included were state-regulated gas distribution charges to retail distribution service customers opting for alternate suppliers and sales of gathering services; and

•		Other revenue consisted primarily of sales of NGL production and condensate, extracted products and associated derivative activity. Other revenue also included miscellaneous service revenue from electric and gas distribution operations, sales of energy-related products and services from Dominion Energy’s retail energy marketing operations and gas processing and handling revenue.

The primary types of sales and service activities reported as operating revenue for Virginia Power, subsequent to the adoption of revised guidance for revenue recognition from contracts with customers, are as follows:

REVENUE FROM CONTRACTS WITH CUSTOMERS

•		Regulated electric sales consist primarily of state-regulated retail electric sales and federally-regulated wholesale electric sales and electric transmission services;

•		Other regulated revenue consists primarily of sales of excess capacity and other commodities and miscellaneous service revenue from electric distribution operations; and

•		Other nonregulated revenue consists primarily of sales to non-jurisdictional customers from certain solar facilities, revenue from renting space on certain electric transmission poles and distribution towers and service concession arrangements.

OTHER REVENUE

•		Other revenue consists primarily of alternative revenue programs, gains and losses from derivative instruments not subject to hedge accounting and lease revenues.


96

The primary types of sales and service activities reported as operating revenue for Virginia Power, prior to the adoption of revised guidance for revenue recognition from contracts with customers, were as follows:

•		Regulated electric sales consisted primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services; and

•		Other revenue consisted primarily of miscellaneous service revenue from electric distribution operations and miscellaneous revenue from generation operations, including sales of capacity and other commodities.

The primary types of sales and service activities reported as operating revenue for Dominion Energy Gas, subsequent to the adoption of revised guidance for revenue recognition from contracts with customers, are as follows:

REVENUE FROM CONTRACTS WITH CUSTOMERS

•		Regulated gas sales consist primarily of state-regulated natural gas sales and related distribution services;

•		Nonregulated gas sales consist primarily of sales of gas purchased from third parties and royalty revenues;

•		Regulated gas transportation and storage sales consist of FERC-regulated sales of transmission and storage services and state-regulated gas distribution charges to retail distribution service customers opting for alternate suppliers and sales of gathering services;

•		NGL revenue consists primarily of NGL gathering and processing, sales of NGL production and condensate, extracted products and associated hedging activity;

•		Management service revenue consists primarily of services performed for Atlantic Coast Pipeline;

•		Other regulated revenue consists primarily of miscellaneous regulated revenues; and

•		Other nonregulated revenue consists primarily of miscellaneous service revenue.

OTHER REVENUE

•		Other revenue consists primarily of gains and losses from derivative instruments not subject to hedge accounting.

The primary types of sales and service activities reported as operating revenue for Dominion Energy Gas, prior to the adoption of revised guidance for revenue recognition from contracts with customers, were as follows:

•		Regulated gas sales consisted primarily of state- and FERC-regulated natural gas sales and related distribution services;

•		Nonregulated gas sales consisted primarily of sales of natural gas production at market-based rates and contracted fixed prices and sales of gas purchased from third parties. Revenue from sales of gas production was recognized based on actual volumes of gas sold to purchasers and was reported net of royalties;

•		Gas transportation and storage sales consisted primarily of FERC-regulated sales of transmission and storage services. Also included were state-regulated gas distribution charges to retail distribution service customers opting for alternate suppliers and sales of gathering services;

•		NGL revenue consisted primarily of sales of NGL production and condensate, extracted products and associated derivative activity; and

•		Other revenue consisted primarily of miscellaneous service revenue, gas processing and handling revenue.

Dominion Energy and Virginia Power record refunds to customers as required by state commissions as a reduction to regulated electric sales or regulated gas sales, as applicable. Dominion Energy and Virginia Power’s revenue accounted for under the alternative revenue program guidance primarily consists of the equity return for under-recovery of certain riders. Alternative revenue programs compensate Dominion Energy and Virginia Power for certain projects and initiatives. Revenues arising from these programs are presented separately from revenue arising from contracts with customers in the categories above.

Revenues from electric and gas sales are recognized over time, as the customers of the Companies consume gas and electricity as it is delivered. Transportation and storage contracts are primarily stand-ready service contracts that include fixed reservation and variable usage fees. LNG terminalling services are also stand-ready service contracts, primarily consisting of fixed fees, offset by service credits associated with the start-up phase of the Liquefaction Project. Fixed fees are recognized ratably over the life of the contract as the stand-ready performance obligation is satisfied, while variable usage fees are recognized when Dominion Energy and Dominion Energy Gas have a right to consideration from a customer in an amount that corresponds directly with the value to the customer of the performance obligation completed to date. Sales of products and services, including NGLs, typically transfer control and are recognized as revenue upon delivery of the product or service. The customer is able to direct the use of, and obtain substantially all of the benefits from, the product at the time the product is delivered. The contract with the customer states the final terms of the sale, including the description, quantity and price of each product or service purchased. Payment for most sales and services varies by contract type, but is typically due within a month of billing.

Dominion Energy and Dominion Energy Gas typically receive or retain NGLs and natural gas from customers when providing natural gas processing, transportation or storage services. The revised guidance for revenue from contracts with customers requires entities to include the fair value of the noncash consideration in the transaction price. Therefore, subsequent to the adoption of the revised guidance for revenue recognition from contracts with customers, Dominion Energy and Dominion Energy Gas record the fair value of NGLs received during natural gas processing as service revenue recognized over time, and continue to recognize revenue from the subsequent sale of the NGLs to customers upon delivery. Dominion Energy and Dominion Energy Gas typically retain natural gas under certain transportation service arrangements that are intended to facilitate performance of the service and allow for natural losses that occur. As the intent of the allowance is to enable fulfillment of the contract rather than to provide compensation for services, the fuel allowance is not included in revenue.

Electric Fuel, Purchased Energy and Purchased Gas-Deferred Costs

Where permitted by regulatory authorities, the differences between Dominion Energy and Virginia Power’s actual electric fuel and purchased energy expenses and Dominion Energy and Dominion Energy Gas’ purchased gas expenses and the related


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Combined Notes to Consolidated Financial Statements, Continued

levels of recovery for these expenses in current rates are deferred and matched against recoveries in future periods. The deferral of costs in excess of current period fuel rate recovery is recognized as a regulatory asset, while rate recovery in excess of current period fuel expenses is recognized as a regulatory liability.

Of the cost of fuel used in electric generation and energy purchases to serve utility customers, at December 31, 2018, approximately 84% is subject to deferred fuel accounting, while substantially all of the remaining amount is subject to recovery through similar mechanisms.

Virtually all of Dominion Energy Gas, Cove Point, Questar Gas, Hope and SCE&G and PSNC’s, following the SCANA Combination, natural gas purchases are either subject to deferral accounting or are recovered from the customer in the same accounting period as the sale.

Income Taxes

A consolidated federal income tax return is filed for Dominion Energy and its subsidiaries, including Virginia Power and Dominion Energy Gas’ subsidiaries. In addition, where applicable, combined income tax returns for Dominion Energy and its subsidiaries are filed in various states; otherwise, separate state income tax returns are filed.

Although Dominion Energy Gas is disregarded for income tax purposes, a provision for income taxes is recognized to reflect the inclusion of its business activities in the tax returns of its parent, Dominion Energy. Virginia Power and Dominion Energy Gas participate in intercompany tax sharing agreements with Dominion Energy and its subsidiaries. Current income taxes are based on taxable income or loss and credits determined on a separate company basis.

Under the agreements, if a subsidiary incurs a tax loss or earns a credit, recognition of current income tax benefits is limited to refunds of prior year taxes obtained by the carryback of the net operating loss or credit or to the extent the tax loss or credit is absorbed by the taxable income of other Dominion Energy consolidated group members. Otherwise, the net operating loss or credit is carried forward and is recognized as a deferred tax asset until realized.

The 2017 Tax Reform Act included a broad range of tax reform provisions affecting the Companies, including changes in corporate tax rates and business deductions. The 2017 Tax Reform Act reduces the corporate income tax rate from 35% to 21% for tax years beginning after December 31, 2017. Deferred tax assets and liabilities are classified as noncurrent in the Consolidated Balance Sheets and measured at the enacted tax rate expected to apply when temporary differences are realized or settled. Thus, at the date of enactment, federal deferred taxes were remeasured based upon the new 21% tax rate. The total effect of tax rate changes on deferred tax balances was recorded as a component of the income tax provision related to continuing operations for the period in which the law is enacted, even if the assets and liabilities relate to other components of the financial statements, such as items of accumulated other comprehensive income. For Dominion Energy subsidiaries that are not rate-regulated utilities, existing deferred income tax assets or liabilities were adjusted for the reduction in the corporate income tax rate and allocated to continuing operations. Dominion Energy’s rate-regulated utility subsidiaries likewise were required to adjust deferred income tax assets and liabilities for the change in income tax rates. However, if it is probable that the effect of the change in

income tax rates will be recovered or refunded in future rates, the regulated utility recorded a regulatory asset or liability instead of an increase or decrease to deferred income tax expense.

Accounting for income taxes involves an asset and liability approach. Deferred income tax assets and liabilities are provided, representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Accordingly, deferred taxes are recognized for the future consequences of different treatments used for the reporting of transactions in financial accounting and income tax returns. The Companies establish a valuation allowance when it is more-likely-than-not that all, or a portion, of a deferred tax asset will not be realized. Where the treatment of temporary differences is different for rate-regulated operations, a regulatory asset is recognized if it is probable that future revenues will be provided for the payment of deferred tax liabilities.

The Companies recognize positions taken, or expected to be taken, in income tax returns that are more-likely-than-not to be realized, assuming that the position will be examined by tax authorities with full knowledge of all relevant information.

If it is not more-likely-than-not that a tax position, or some portion thereof, will be sustained, the related tax benefits are not recognized in the financial statements. Unrecognized tax benefits may result in an increase in income taxes payable, a reduction of income tax refunds receivable or changes in deferred taxes. Also, when uncertainty about the deductibility of an amount is limited to the timing of such deductibility, the increase in income taxes payable (or reduction in tax refunds receivable) is accompanied by a decrease in deferred tax liabilities. Except when such amounts are presented net with amounts receivable from or amounts prepaid to tax authorities, noncurrent income taxes payable related to unrecognized tax benefits are classified in other deferred credits and other liabilities on the Consolidated Balance Sheets and current payables are included in accrued interest, payroll and taxes on the Consolidated Balance Sheets.

The Companies recognize interest on underpayments and overpayments of income taxes in interest expense and other income, respectively. Penalties are also recognized in other income.

Interest for the Companies was immaterial in 2018 and 2016. Dominion Energy and Virginia Power both recognized interest income of $11 million in 2017. Dominion Energy Gas’ interest was immaterial in 2017. Dominion Energy, Virginia Power and Dominion Energy Gas’ penalties were immaterial in 2018, 2017 and 2016.

At December 31, 2018, Virginia Power had an income tax-related affiliated receivable of $36 million, comprised of $34 million of federal income taxes and $2 million of state income taxes due from Dominion Energy. Dominion Energy Gas also had a net affiliated receivable of $2 million due from Dominion Energy, representing $8 million of federal income taxes receivable and $6 million of state income taxes payable to Dominion Energy. The net affiliated receivables are expected to be received from Dominion Energy.

In addition, Dominion Energy Gas’ Consolidated Balance Sheet at December 31, 2018 included $13 million of state income taxes receivable. State income taxes receivable at Virginia Power were immaterial at December 31, 2018.


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At December 31, 2017, Virginia Power had an income tax-related affiliated payable of $16 million, comprised of $16 million of federal income taxes due to Dominion Energy. Dominion Energy Gas also had an affiliated payable of $25 million due to Dominion Energy, representing $21 million of federal income taxes and $4 million of state income taxes. The net affiliated payables were paid to Dominion Energy.

In addition, Virginia Power’s Consolidated Balance Sheet at December 31, 2017 included $1 million of noncurrent federal income taxes receivable, less than $1 million of state income taxes receivable and $1 million of noncurrent state income taxes receivable. Dominion Energy Gas’ Consolidated Balance Sheet at December 31, 2017 included $14 million of state income taxes receivable.

Investment tax credits are recognized by nonregulated operations in the year qualifying property is placed in service. For regulated operations, investment tax credits are deferred and amortized over the service lives of the properties giving rise to the credits. Production tax credits are recognized as energy is generated and sold.

Cash, Restricted Cash and Equivalents

Cash, restricted cash and equivalents include cash on hand, cash in banks and temporary investments purchased with an original maturity of three months or less.

Current banking arrangements generally do not require checks to be funded until they are presented for payment. The following table illustrates the checks outstanding but not yet presented for payment and recorded in accounts payable for the Companies:


At December 31,	2018		2017
(millions)
Dominion Energy	$	35	$	30
Virginia Power		16		17
Dominion Energy Gas		7		7

RESTRICTED CASH AND EQUIVALENTS

The Companies hold restricted cash and equivalent balances that primarily consist of amounts held for customer deposits, future debt payments on SBL Holdco and Dominion Solar Projects III, Inc.’s term loan agreements and on Eagle Solar’s senior note agreement.

The following table provides a reconciliation of the total cash, restricted cash and equivalents reported within the Companies’ Consolidated Balance Sheets to the corresponding amounts reported within the Companies’ Consolidated Statements of Cash Flows for the years ended December 31, 2018, 2017 and 2016:


	Cash, Restricted Cash and Equivalents at End/Beginning of Year
	December 31, 2018		December 31, 2017		December 31, 2016		December 31, 2015
(millions)
Dominion Energy
Cash and cash equivalents	$	268	$	120	$	261	$	607
Restricted cash and equivalents(1)		123		65		61		25
Cash, restricted cash and equivalents shown in the Consolidated Statements of Cash Flows	$	391	$	185	$	322	$	632
Virginia Power
Cash and cash equivalents	$	29	$	14	$	11	$	18
Restricted cash and equivalents(1)		9		10		—		—
Cash, restricted cash and equivalents shown in the Consolidated Statements of Cash Flows	$	38	$	24	$	11	$	18
Dominion Energy Gas
Cash and cash equivalents	$	10	$	4	$	23	$	13
Restricted cash and equivalents(1)		24		26		20		14
Cash, restricted cash and equivalents shown in the Consolidated Statements of Cash Flows	$	34	$	30	$	43	$	27

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

DISTRIBUTIONS FROM EQUITY METHOD INVESTEES

Dominion Energy and Dominion Energy Gas each hold investments that are accounted for under the equity method of accounting. Dominion Energy and Dominion Energy Gas classify distributions from equity method investees as either cash flows from operating activities or cash flows from investing activities in the Consolidated Statements of Cash Flows according to the nature of the distribution. Distributions received are classified on the basis of the nature of the activity of the investee that generated the distribution as either a return on investment (classified as cash flows from operating activities) or a return of an investment (classified as cash flows from investing activities) when such information is available to Dominion Energy and Dominion Energy Gas.


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Combined Notes to Consolidated Financial Statements, Continued

Derivative Instruments

The Companies are exposed to the impact of market fluctuations in the price of electricity, natural gas and other energy-related products they market and purchase, as well as interest rate and foreign currency exchange rate risks of their business operations. Dominion Energy uses derivative instruments such as physical and financial forwards, futures, swaps, options and FTRs to manage the commodity, interest rate and foreign currency exchange rate risks of its business operations. Virginia Power uses derivative instruments such as physical and financial forwards, futures, swaps, options and FTRs to manage commodity and interest rate risks. Dominion Energy Gas uses derivative instruments such as physical and financial forwards, futures and swaps to manage commodity, interest rate and foreign currency exchange rate risks.

All derivatives, except those for which an exception applies, are required to be reported in the Consolidated Balance Sheets at fair value. Derivative contracts representing unrealized gain positions and purchased options are reported as derivative assets. Derivative contracts representing unrealized losses and options sold are reported as derivative liabilities. One of the exceptions to fair value accounting, normal purchases and normal sales, may be elected when the contract satisfies certain criteria, including a requirement that physical delivery of the underlying commodity is probable. Expenses and revenues resulting from deliveries under normal purchase contracts and normal sales contracts, respectively, are included in earnings at the time of contract performance.

The Companies do not offset amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. Dominion Energy had margin assets of $95 million and $92 million associated with cash collateral at December 31, 2018 and 2017, respectively. Dominion Energy’s margin liabilities associated with cash collateral were less than $1 million at December 31, 2018 and 2017. Virginia Power had margin assets of $23 million associated with cash collateral at December 31, 2017. Virginia Power had no margin assets associated with cash collateral at December 31, 2018 and no margin liabilities associated with cash collateral at December 31, 2018 and 2017. Dominion Energy Gas had no margin assets or liabilities associated with cash collateral at December 31, 2018 and 2017. See Note 7 for further information about derivatives.

To manage price risk, the Companies hold certain derivative instruments that are not designated as hedges for accounting purposes. However, to the extent the Companies do not hold offsetting positions for such derivatives, they believe these instruments represent economic hedges that mitigate their exposure to fluctuations in commodity prices. All income statement activity, including amounts realized upon settlement, is presented in operating revenue, operating expenses, interest and related charges or other income based on the nature of the underlying risk.

Changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities for jurisdictions subject to cost-based rate regulation. Realized gains or losses on the derivative instruments are generally recognized when the related transactions impact earnings.

DERIVATIVE INSTRUMENTS DESIGNATED AS HEDGING INSTRUMENTS

In accordance with accounting guidance pertaining to derivatives and hedge accounting, the Companies designate a portion of their derivative instruments as either cash flow or fair value hedges for accounting purposes. For derivative instruments that are accounted for as fair value hedges or cash flow hedges, the cash flows from the derivatives and from the related hedged items are classified in operating cash flows.

Cash Flow Hedges-A majority of the Companies’ hedge strategies represents cash flow hedges of the variable price risk associated with the purchase and sale of electricity, natural gas and NGLs. The Companies also use interest rate swaps to hedge their exposure to variable interest rates on long-term debt as well as foreign currency swaps to hedge their exposure to interest payments denominated in Euros. For transactions in which the Companies are hedging the variability of cash flows, changes in the fair value of the derivatives are reported in AOCI, to the extent they are effective at offsetting changes in the hedged item. Any derivative gains or losses reported in AOCI are reclassified to earnings when the forecasted item is included in earnings, or earlier, if it becomes probable that the forecasted transaction will not occur. For cash flow hedge transactions, hedge accounting is discontinued if the occurrence of the forecasted transaction is no longer probable.

Dominion Energy entered into interest rate derivative instruments to hedge its forecasted interest payments related to planned debt issuances in 2014. These interest rate derivatives were designated by Dominion Energy as cash flow hedges prior to the formation of Dominion Energy Gas. For the purposes of the Dominion Energy Gas financial statements, the derivative balances, AOCI balance, and any income statement impact related to these interest rate derivative instruments entered into by Dominion Energy have been, and will continue to be, included in the Dominion Energy Gas’ Consolidated Financial Statements as the forecasted interest payments related to the debt issuances now occur at Dominion Energy Gas.

Fair Value Hedges-Dominion Energy has also designated interest rate swaps as fair value hedges on certain fixed rate long-term debt to manage interest rate exposure. In addition, Dominion Energy has used fair value hedges to mitigate the fixed price exposure inherent in commodity inventory. For fair value hedge transactions, changes in the fair value of the derivative are generally offset currently in earnings by the recognition of changes in the hedged item’s fair value. Hedge accounting is discontinued if the hedged item no longer qualifies for hedge accounting. See Note 6 for further information about fair value measurements and associated valuation methods for derivatives. See Note 7 for further information on derivatives.

Property, Plant and Equipment

Property, plant and equipment is recorded at lower of original cost or fair value, if impaired. Capitalized costs include labor, materials and other direct and indirect costs such as asset retirement costs, capitalized interest and, for certain operations subject to cost-of-service rate regulation, AFUDC and overhead costs. The cost of repairs and maintenance, including minor additions and replacements, is generally charged to expense as it is incurred.


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In 2018, 2017 and 2016, Dominion Energy capitalized interest costs and AFUDC to property, plant and equipment of $134 million, $236 million and $159 million, respectively. In 2018, 2017 and 2016, Virginia Power capitalized AFUDC to property, plant and equipment of $56 million, $37 million and $21 million, respectively. In 2018, 2017 and 2016, Dominion Energy Gas capitalized AFUDC to property, plant and equipment of $18 million, $25 million and $8 million, respectively.

Under Virginia law, certain Virginia jurisdictional projects qualify for current recovery of AFUDC through rate adjustment clauses. AFUDC on these projects is calculated and recorded as a regulatory asset and is not capitalized to property, plant and equipment. In 2018, 2017 and 2016, Virginia Power recorded $4 million, $22 million and $31 million of AFUDC related to these projects, respectively.

For property subject to cost-of-service rate regulation, including Dominion Energy and Virginia Power electric distribution, electric transmission and generation property, Dominion Energy Gas natural gas distribution and transmission property, and for certain Dominion Energy natural gas property, the undepreciated cost of such property, less salvage value, is generally charged to accumulated depreciation at retirement. Cost of removal collections from utility customers not representing AROs are recorded as regulatory liabilities. For property subject to cost-of-service rate regulation that will be abandoned significantly before the end of its useful life, the net carrying value is reclassified from plant-in-service when it becomes probable it will be abandoned. In January 2019, Virginia Power committed to a plan to retire certain automated meter reading infrastructure associated with its electric operations before the end of its useful life and replace such equipment with more current AMI technology. As a result, Virginia Power expects to incur a charge of approximately $190 million ($141 million after-tax) in 2019.

For property that is not subject to cost-of-service rate regulation, including nonutility property, cost of removal not associated with AROs is charged to expense as incurred. The Companies also record gains and losses upon retirement based upon the difference between the proceeds received, if any, and the property’s net book value at the retirement date.

Depreciation of property, plant and equipment is computed on the straight-line method based on projected service lives. The Companies’ average composite depreciation rates on utility property, plant and equipment are as follows:


Year Ended December 31,	2018		2017		2016
(percent)
Dominion Energy
Generation		2.71		2.94		2.83
Transmission		2.54		2.55		2.47
Distribution		2.97		3.00		3.02
Storage		2.40		2.48		2.29
Gas gathering and processing		2.62		2.21		2.66
General and other		4.56		4.89		4.12

Virginia Power
Generation		2.71		2.94		2.83
Transmission		2.52		2.54		2.36
Distribution		3.31		3.32		3.32
General and other		4.52		4.68		3.49

Dominion Energy Gas
Transmission		2.45		2.40		2.43
Distribution		2.41		2.42		2.55
Storage		2.46		2.45		2.19
Gas gathering and processing		3.07		2.42		2.58
General and other		5.59		4.96		4.54

In the second quarter of 2018, Virginia Power recorded an adjustment for the retroactive application of depreciation rates for regulated nuclear plants to comply with Virginia Commission requirements. This adjustment resulted in a decrease of $60 million ($44 million after-tax) in depreciation expense in Virginia Power’s Consolidated Statements of Income for the year ended December 31, 2018. This resulted in an increase to Dominion Energy’s EPS of $0.07 per share for the year ended December 31, 2018. This revision is expected to decrease annual depreciation expense by approximately $30 million ($23 million after-tax).

In the first quarter of 2017, Virginia Power revised the depreciation rates for its assets to reflect the results of a new depreciation study. This change resulted in an increase in annual depreciation expense of $40 million ($25 million after-tax) for 2017. Additionally, Dominion Energy revised the depreciable lives for its merchant generation assets, excluding Millstone, which resulted in a decrease in annual depreciation expense of $26 million ($16 million after-tax) for 2017.

Capitalized costs of development wells and leaseholds are amortized on a field-by-field basis using the unit-of-production method and the estimated proved developed or total proved gas and oil reserves, at a rate of $1.89 and $2.11 per mcfe in 2018 and 2017, respectively.

Dominion Energy’s nonutility property, plant and equipment is depreciated using the straight-line method over the following estimated useful lives:


Asset	Estimated Useful Lives
Merchant generation-nuclear		44 years
Merchant generation-other		15-30 years
Nonutility gas gathering and processing		3-50 years
LNG facility		40 years
General and other		5-59 years


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Combined Notes to Consolidated Financial Statements, Continued

Depreciation and amortization related to Virginia Power and Dominion Energy Gas’ nonutility property, plant and equipment and exploration and production properties was immaterial for the years ended December 31, 2018, 2017 and 2016, except for Dominion Energy Gas’ nonutility gas gathering and processing properties which are depreciated using the straight-line method over estimated useful lives between 10 and 50 years.

Nuclear fuel used in electric generation is amortized over its estimated service life on a units-of-production basis. Dominion Energy and Virginia Power report the amortization of nuclear fuel in electric fuel and other energy-related purchases expense in their Consolidated Statements of Income and in depreciation and amortization in their Consolidated Statements of Cash Flows.

Long-Lived and Intangible Assets

The Companies perform an evaluation for impairment whenever events or changes in circumstances indicate that the carrying amount of long-lived assets or intangible assets with finite lives may not be recoverable. A long-lived or intangible asset is written down to fair value if the sum of its expected future undiscounted cash flows is less than its carrying amount. Intangible assets with finite lives are amortized over their estimated useful lives. See Note 6 for further discussion on the impairment of long-lived assets.

Regulatory Assets and Liabilities

The accounting for Dominion Energy and Dominion Energy Gas’ regulated gas and Dominion Energy and Virginia Power’s regulated electric operations differs from the accounting for nonregulated operations in that they are required to reflect the effect of rate regulation in their Consolidated Financial Statements. For regulated businesses subject to federal or state cost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by nonregulated companies. When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, these costs that otherwise would be expensed by nonregulated companies are deferred as regulatory assets. Likewise, regulatory liabilities are recognized when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have yet to be incurred. Generally, regulatory assets and liabilities are amortized into income over the period authorized by the regulator.

The Companies evaluate whether or not recovery of their regulatory assets through future rates is probable and make various assumptions in their analyses. The expectations of future recovery are generally based on orders issued by regulatory commissions, legislation or historical experience, as well as discussions with applicable regulatory authorities and legal counsel. If recovery of a regulatory asset is determined to be less than probable, it will be written off in the period such assessment is made.

Asset Retirement Obligations

The Companies recognize AROs at fair value as incurred or when sufficient information becomes available to determine a reasonable estimate of the fair value of future retirement activities to be performed, for which a legal obligation exists. These amounts are generally capitalized as costs of the related tangible long-lived assets. Since relevant market information is not available, fair

value is estimated using discounted cash flow analyses. Quarterly, the Companies assess their AROs to determine if circumstances indicate that estimates of the amounts or timing of future cash flows associated with retirement activities have changed. AROs are adjusted when significant changes in the amounts or timing of future cash flows are identified. Dominion Energy and Dominion Energy Gas report accretion of AROs and depreciation on asset retirement costs associated with their natural gas pipeline and storage well assets as an adjustment to the related regulatory liabilities when revenue is recoverable from customers for AROs. Dominion Energy, following the SCANA Combination, and Virginia Power report accretion of AROs and depreciation on asset retirement costs associated with decommissioning its nuclear power stations as an adjustment to the regulatory liability for certain jurisdictions. Additionally, Dominion Energy and Virginia Power report accretion of AROs and depreciation on asset retirement costs associated with certain rider and prospective rider projects as an adjustment to the regulatory asset for certain jurisdictions. Accretion of all other AROs and depreciation of all other asset retirement costs are reported in other operations and maintenance expense and depreciation expense, respectively, in the Consolidated Statements of Income.

Debt Issuance Costs

The Companies defer and amortize debt issuance costs and debt premiums or discounts over the expected lives of the respective debt issues, considering maturity dates and, if applicable, redemption rights held by others. Deferred debt issuance costs are recorded as a reduction in long-term debt in the Consolidated Balance Sheets. Amortization of the issuance costs is reported as interest expense. Unamortized costs associated with redemptions of debt securities prior to stated maturity dates are generally recognized and recorded in interest expense immediately. As permitted by regulatory authorities, gains or losses resulting from the refinancing of debt allocable to utility operations subject to cost-based rate regulation are deferred and amortized.

Investments

DEBT AND EQUITY SECURITIES WITH READILY DETERMINABLE FAIR VALUES

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

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

•		Debt securities classified as available-for-sale securities include all other debt securities, primarily comprised of securities held in the nuclear decommissioning trusts. These investments are reported at fair value in nuclear decommissioning trust funds in the Consolidated Balance Sheets. Net realized and unrealized gains and losses (including any other-than-temporary impairments) on investments held in Virginia Power’s nuclear decommissioning trusts are recorded to a regulatory liability


102

		for certain jurisdictions subject to cost-based regulation. For all other available-for-sale debt securities, including those held in Dominion Energy’s merchant generation nuclear decommissioning trusts, net realized gains and losses (including any other-than-temporary impairments) are included in other income and unrealized gains and losses are reported as a component of AOCI, after-tax.

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

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

EQUITY SECURITIES WITHOUT READILY DETERMINABLE FAIR VALUES

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

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

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

OTHER-THAN-TEMPORARY IMPAIRMENT

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

Decommissioning Trust Investments —Special Considerations for Debt Securities

•		The recognition provisions of other-than-temporary impairment guidance apply only to debt securities classified as available-for-sale or held-to-maturity.

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

Inventories

Materials and supplies and fossil fuel inventories are valued primarily using the weighted-average cost method. Stored gas inventory is valued using the weighted-average cost method, except for East Ohio gas distribution operations, which are valued using the LIFO method. Under the LIFO method, current stored gas inventory was valued at $12 million and $9 million at December 31, 2018 and December 31, 2017, respectively. Based on the average price of gas purchased during 2018 and 2017, the cost of replacing the current portion of stored gas inventory exceeded the amount stated on a LIFO basis by $87 million and $79 million, respectively.

Gas Imbalances

Natural gas imbalances occur when the physical amount of natural gas delivered from, or received by, a pipeline system or storage facility differs from the contractual amount of natural gas delivered or received. Dominion Energy and Dominion Energy Gas value these imbalances due to, or from, shippers and operators at an appropriate index price at period end, subject to the terms of its tariff for regulated entities. Imbalances are primarily settled in-kind. Imbalances due to Dominion Energy from other parties are reported in other current assets and imbalances that Dominion Energy and Dominion Energy Gas owe to other parties are


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Combined Notes to Consolidated Financial Statements, Continued

reported in other current liabilities in the Consolidated Balance Sheets.

Goodwill

Dominion Energy and Dominion Energy Gas evaluate goodwill for impairment annually as of April 1 and whenever an event occurs or circumstances change in the interim that would more-likely-than-not reduce the fair value of a reporting unit below its carrying amount.

New Accounting Standards

REVENUE RECOGNITION

In May 2014, the FASB issued revised accounting guidance for revenue recognition from contracts with customers. The Companies adopted this revised accounting guidance for interim and annual reporting periods beginning January 1, 2018 using the modified retrospective method. Upon the adoption of the standard, Dominion Energy and Dominion Energy Gas recorded the cumulative-effect of a change in accounting principle of $3 million to retained earnings and membership interests, respectively, and to establish a contract asset related to changes in the timing of revenue recognition for three existing contracts with customers at DETI.

As a result of adopting this revised accounting guidance, Dominion Energy and Dominion Energy Gas record offsetting operating revenue and other energy-related purchases for non-cash consideration of performing processing and fractionation services related to NGLs. Such amounts at Dominion Energy were $107 million and at Dominion Energy Gas were $103 million, recorded in the Consolidated Statements of Income for the year ended December 31, 2018. No such amounts were recorded during the year ended December 31, 2017. Dominion Energy and Dominion Energy Gas no longer record offsetting operating revenue and purchased gas for fuel retained to offset costs on certain transportation and storage arrangements. Such amounts at Dominion Energy were $111 million and at Dominion Energy Gas were $79 million, recorded in the Consolidated Statements of Income for the year ended December 31, 2017.

FINANCIAL INSTRUMENTS

In January 2016, the FASB issued revised accounting guidance for the recognition, measurement, presentation and disclosure of financial instruments. The guidance became effective for the Companies’ interim and annual reporting periods beginning January 1, 2018 and the Companies adopted the standard using the modified retrospective method. Upon adoption of this guidance for equity securities held at January 1, 2018, Dominion Energy and Virginia Power recorded the cumulative-effect of a change in accounting principle to reclassify net unrealized gains from AOCI to retained earnings and to recognize equity securities previously categorized as cost method investments at fair value (using NAV) in nuclear decommissioning trust funds in the Consolidated Balance Sheets and a cumulative-effect adjustment to retained earnings. Dominion Energy and Virginia Power reclassified approximately $1.1 billion ($734 million after-tax) and $119 million ($73 million after-tax), respectively, of net unrealized gains from AOCI to retained earnings. Dominion Energy and Virginia Power also recorded approximately $36 million ($22 million after-tax) in net unrealized gains on

equity securities previously classified as cost method investments, of which $3 million was recorded to retained earnings and $33 million was recorded to regulatory liabilities for net unrealized gains subject to cost-based regulation. As a result of adopting this revised accounting guidance, Dominion Energy recorded unrealized losses on equity securities, net of regulatory deferrals, of $190 million ($142 million after-tax) in other income in the Consolidated Statements of Income for the year ended December 31, 2018, resulting in an $0.22 loss per share for the year ended December 31, 2018. Virginia Power recorded unrealized losses on equity securities, net of regulatory deferrals, of $24 million ($18 million after-tax) in other income in the Consolidated Statements of Income for the year ended December 31, 2018.

LEASES

In February 2016, the FASB issued revised accounting guidance for the recognition, measurement, presentation and disclosure of leasing arrangements. The update requires that a liability and corresponding right-of-use asset are recorded on the balance sheet for all leases, including those leases currently classified as operating leases, while also refining the definition of a lease. In addition lessees will be required to disclose key information about the amount, timing, and uncertainty of cash flows arising from leasing arrangements. Lessor accounting remains largely unchanged.

The guidance is effective for the Companies’ interim and annual reporting periods beginning January 1, 2019. The Companies will adopt this revised accounting guidance using a modified retrospective approach, which requires lessees and lessors to recognize and measure leases at the date of adoption. Under this approach, the Companies are permitted to utilize the transition practical expedient to maintain historical presentation for periods before January 1, 2019. The Companies will apply the other practical expedients, which would require no reassessment of whether existing contracts are or contain leases, no reassessment of lease classification for existing leases and no reassessment of existing or expired land easements that were not previously accounted for as leases. Dominion Energy, Virginia Power and Dominion Energy Gas anticipate that the adoption of this guidance will result in approximately $450 million to $500 million, $200 million to $250 million and $60 million to $70 million, respectively, of offsetting right-of-use assets and liabilities added to their Consolidated Balance Sheets for operating leases in effect at the adoption date. Dominion Energy’s anticipated right-of-use asset and liability associated with operating leases includes those acquired as part of the SCANA Combination of approximately $30 million to $35 million. No material changes are expected to the Companies’ results of operations.

DERECOGNITION AND PARTIAL SALES OF NONFINANCIAL ASSETS

In February 2017, the FASB issued revised accounting guidance clarifying the scope of asset derecognition guidance and accounting for partial sales of nonfinancial assets. The guidance became effective for the Companies’ interim and annual reporting periods beginning January 1, 2018, and the Companies adopted the standard using the modified retrospective method. Upon adoption of the standard, Dominion Energy recorded the cumulative-effect of a change in accounting principle to reclassify


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$127 million from noncontrolling interests to common stock related to the sale of a noncontrolling interest in certain merchant solar projects completed in December 2015 and January 2016.

NET PERIODIC PENSION AND OTHER POSTRETIREMENT BENEFIT COSTS

In March 2017, the FASB issued revised accounting guidance for the presentation of net periodic pension and other postretirement benefit costs. This guidance became effective for the Companies beginning January 1, 2018 and requires that the service cost component of net periodic pension and other postretirement benefit costs be classified in the same line item as other compensation costs arising from services rendered by employees, while all other components of net periodic pension and other postretirement costs are classified outside of income from operations. In addition, only the service cost component remains eligible for capitalization during construction. These changes do not impact the accounting by participants in a multi-employer plan. The standard also recognizes that in the event that a regulator continues to require capitalization of all net periodic benefit costs prospectively, the difference would result in recognition of a regulatory asset or liability. For costs not capitalized for which regulators are expected to provide recovery, a regulatory asset will be established. As such, the amounts eligible for capitalization in the Consolidated Financial Statements of Virginia Power and Dominion Energy Gas, as subsidiary participants in Dominion Energy’s multi-employer plans, will differ from the amounts eligible for capitalization in the Consolidated Financial Statements of Dominion Energy, the plan administrator. These differences will result in a regulatory asset or liability recorded in the Consolidated Financial Statements of Dominion Energy.

TAX REFORM

In December 2017, the staff of the SEC issued guidance which clarifies accounting for income taxes if information is not yet available or complete and provided for up to a one-year measurement period in which to complete the required analyses and accounting. The guidance described three scenarios associated with a company’s status of accounting for income tax reform: (1) a company is complete with its accounting for certain effects of tax reform, (2) a company is able to determine a reasonable estimate for certain effects of tax reform and records that estimate as a provisional amount, or (3) a company is not able to determine a reasonable estimate and therefore continues to apply accounting for income taxes based on the provisions of the tax laws that were in effect immediately prior to the 2017 Tax Reform Act being enacted. The Companies have accounted for the effects of the 2017 Tax Reform Act, although additional changes could occur as guidance is issued and finalized as described below. In addition, certain states in which the Companies operate may or may not conform to some or all of the provisions of the 2017 Tax Reform Act. Ultimate resolution or clarification of these matters may result in favorable or unfavorable impacts to results of operations and cash flows, and adjustments to tax-related assets and liabilities, and could be material.

In August 2018, the U.S. Department of Treasury issued proposed regulations addressing the availability of federal bonus depreciation for the period beginning after September 27, 2017

through December 31, 2017. The application of these changes decreased Dominion Energy’s net operating loss carryforward utilization on its 2017 tax return as discussed in Note 5.

In November 2018, the U.S. Department of Treasury issued proposed regulations defining interest as any amounts associated with the time value of money or use of funds. These proposed regulations provide guidance for purposes of the exception to the interest limitation for regulated public utilities, the application of the interest limitation to consolidated groups, such as Dominion Energy, and the interest limitation with respect to partnerships and partners in those partnerships. It is unclear when the guidance may be finalized, or whether that guidance could result in a disallowance of a portion of the Companies’ interest deductions in the future.

In February 2018, the FASB issued revised accounting guidance to provide clarification on the application of the 2017 Tax Reform Act for balances recorded within AOCI. The revised guidance provides for stranded amounts within AOCI from the impacts of the 2017 Tax Reform Act to be reclassified to retained earnings. The Companies adopted this guidance for interim and annual reporting periods beginning January 1, 2018 on a prospective basis. In connection with the adoption of this guidance, Dominion Energy reclassified a benefit of $289 million from AOCI to retained earnings, Virginia Power reclassified a benefit of $3 million from AOCI to retained earnings and Dominion Energy Gas reclassified a benefit of $26 million from AOCI to membership interests. The amounts reclassified reflect the reduction in the federal income tax rate, and the federal benefit of state income taxes, on the components of the Companies’ AOCI.

NOTE 3. ACQUISITIONS AND DISPOSITIONS

DOMINION ENERGY

Acquisition of SCANA

In January 2019, Dominion Energy issued 95.6 million shares of Dominion Energy common stock, valued at $6.8 billion, representing 0.6690 of a share of Dominion Energy common stock for each share of SCANA common stock, in connection with the completion of the SCANA Combination. SCANA, through its regulated subsidiaries, is primarily engaged in the generation, transmission and distribution of electricity in the central, southern, and southwestern portions of South Carolina and in the distribution of natural gas in North Carolina and South Carolina. In addition, SCANA markets natural gas to retail customers in the southeast U.S. Following completion of the SCANA Combination, SCANA operates as a wholly-owned subsidiary of Dominion Energy. In addition, SCANA’s outstanding debt totaled $6.9 billion at closing. The SCANA Combination expands Dominion Energy’s portfolio of regulated electric generation, transmission and distribution and regulated natural gas distribution infrastructure and operations.

MERGER APPROVAL AND CONDITIONS

Merger Approval

The SCANA Combination required approval of SCANA’s shareholders, FERC, the North Carolina Commission, the South Carolina Commission, the Georgia Public Service Commission


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and the NRC and clearance from the Federal Trade Commission under the Hart-Scott-Rodino Act. All such approvals were received prior to closing of the SCANA Combination.

Various parties filed petitions for rehearing or reconsideration of the SCANA Merger Approval Order. In January 2019, the South Carolina Commission issued a directive (1) granting the request of various parties and finding that SCE&G was imprudent in its actions by not disclosing material information to the South Carolina Office of Regulatory Staff and the South Carolina Commission with regard to costs incurred subsequent to March 2015 and (2) denying the petitions for rehearing or consideration as to other issues raised in the various petitions. The SCANA Merger Approval Order and the order on rehearing are subject to appeal by various parties.

Refunds to Customers

As a condition to the SCANA Merger Approval Order, SCE&G will provide refunds and restitution of $2.0 billion over 20 years with capital support from Dominion Energy.

In September and October 2017, SCE&G received proceeds from Toshiba Corporation totaling $1.1 billion in full satisfaction of its share of a settlement agreement between SCE&G, Santee Cooper and Toshiba Corporation in connection with Westinghouse and WECTEC, both wholly-owned subsidiaries of Toshiba Corporation and responsible for the engineering and construction of the NND Project, filing for bankruptcy. The purchase price allocation below includes a previously established regulatory liability at SCE&G totaling $1.1 billion associated with the monetization of the bankruptcy settlement with Toshiba Corporation. In accordance with the terms of the SCANA Merger Approval Order, this regulatory liability, net of amounts that may be required to satisfy any liens against NND Project property totaling $1.0 billion, will be refunded to SCE&G electric service customers over a 20-year period ending in 2039.

Additionally, SCE&G will reflect in the first quarter of 2019 a reduction in operating revenue and a corresponding regulatory liability of $1.0 billion of which approximately $140 million will be considered current, representing a refund of amounts previously collected from retail electric customers of SCE&G for the NND Project to be credited over an estimated 11-year period. This will result in a $756 million after-tax charge in Dominion Energy’s Consolidated Statements of Income in the first quarter of 2019.

NND Project

As a condition to the SCANA Merger Approval Order, SCE&G will exclude from rate recovery $2.4 billion of costs related to the NND Project and $180 million of costs associated with the purchase of the Columbia Energy Center power station. Regulatory assets included in SCANA’s historical balance sheet at December 31, 2018 reflected these disallowances.

The remaining regulatory asset associated with the NND Project of $2.8 billion will be collected over a 20-year period, including a return on investment. In January 2019, SCE&G filed the NND Project rider in accordance with the terms of the SCANA Merger Approval Order for rates effective in February 2019 for SCE&G’s retail electric customers. The South Carolina Commission approved this filing in January 2019.

Other Terms and Conditions

•		SCE&G will not file an application for a general rate case with the South Carolina Commission with a requested effective date earlier than January 2021;

•		PSNC will not file an application for a general rate case with the North Carolina Commission with a requested effective date earlier than April 2021;

•		Dominion Energy has committed to increasing SCANA’s historical level of corporate contributions to charities by $1 million per year over the next five years;

•		Dominion Energy will maintain SCE&G and PSNC’s headquarters in Cayce, South Carolina and Gastonia, North Carolina, respectively; and

•		Dominion Energy will seek to minimize reductions in local employment by allowing some DES employees supporting shared and common services functions and activities to be located in Cayce, South Carolina where it makes economic and practical sense to do so.

PURCHASE PRICE ALLOCATION

SCANA’s assets acquired and liabilities assumed will be measured at estimated fair value at closing and will be included in the Southeast Energy operating segment, which was established following the closing of the SCANA Combination. The majority of the operations acquired are subject to the rate setting authority of FERC and the North and South Carolina Commissions and are therefore accounted for pursuant to ASC 980, Regulated Operations. The fair values of SCANA’s assets and liabilities subject to rate-setting and cost recovery provisions provide revenues derived from costs, including a return on investment of assets and liabilities included in rate base. As such, the fair values of these assets and liabilities equal their carrying values. Accordingly, neither the assets and liabilities acquired, nor the unaudited pro forma financial information, reflect any adjustments related to these amounts.

The fair value of SCANA’s assets acquired and liabilities assumed that are not subject to the rate-setting provisions discussed above and the fair values of SCANA’s investments accounted for under the equity method will be determined using the income approach and the market approach. The valuation of SCANA’s long-term debt is considered a Level 2 fair value measurement. All other valuations will be considered Level 3 fair value measurements due to the use of significant judgmental and unobservable inputs, including projected timing and amount of future cash flows and discount rates reflecting risk inherent in the future market prices.

The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed will be reflected as goodwill in the first quarter of 2019. The goodwill reflects the value associated with enhancing Dominion Energy’s portfolio of regulated operations in the growing southeast region of the U.S. The goodwill to be recognized will not be deductible for income tax purposes, and as such, no deferred taxes will be recorded related to goodwill.


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The table below shows the preliminary allocation of the purchase price to the assets acquired and liabilities assumed at closing to be reflected in Dominion Energy’s Consolidated Balance Sheet in the first quarter of 2019. The allocation is subject to change during the measurement period as additional information is obtained about the facts and circumstances that existed at closing. The allocation of the purchase price excludes certain contracts and intangible assets related to nonregulated operations, including SEMI, equity method investments and certain income tax-related amounts, which will be included as Dominion Energy completes its valuation analysis. As a result, the amount of goodwill included below may change by a material amount as Dominion Energy finalizes the allocation of the purchase price during the first quarter of 2019.


	Amount
(millions)
Total current assets	$	1,756
Investments		213
Property, plant and equipment, net		10,982
Goodwill		2,438
Regulatory assets		4,219
Other deferred charges and other assets, including intangible assets		314
Total Assets		19,922
Total current liabilities		1,506
Long-term debt		6,707
Deferred income taxes		1,097
Regulatory liabilities		2,664
Other deferred credits and other liabilities		1,109
Total Liabilities		13,083
Total purchase price	$	6,839

INFORMATION ON ASSETS AND LIABILITIES ACQUIRED

Cash, Restricted Cash and Equivalents

The total current assets line above includes $389 million of cash, restricted cash and equivalents, of which $115 million is considered restricted, acquired by Dominion Energy in connection with the SCANA Combination.

Investments

Investments acquired in connection with the SCANA Combination include $20 million pertaining to certain investments accounted for under the equity method, at carrying value. Dominion Energy is still assessing the fair value of these investments.

Income Taxes

Deferred income taxes include a deferred tax asset recorded on a federal net operating loss carryforward of $1.8 billion and a state net operating loss carryforward of $2.4 billion. Based on the available evidence, Dominion Energy believes it is more likely than not that the benefit of the federal net operating loss will be utilized during the carryforward period, and therefore no valuation allowance has been established. Dominion Energy is still assessing whether a valuation allowance is required on the state net operating loss carryforward. Deferred income taxes also include unrecognized tax benefits of $106 million, which could increase as Dominion Energy continues and completes its evaluation of positions taken on SCANA’s federal and state income tax returns.

Property, Plant and Equipment

At the date of the SCANA Combination, major classes of property, plant and equipment and their respective balances for SCANA are as follows:


	2018
(millions)
Utility:
Generation	$	5,720
Transmission		2,416
Distribution		6,044
Storage		99
Nuclear fuel		611
General and other		631
Plant under construction		527
Total utility		16,048
Nonutility, including plant under construction		283
Total property, plant and equipment	$	16,331

In connection with the SCANA Combination, Dominion Energy intends to forego recovery of approximately $105 million of certain assets for which it expects to recognize a $79 million after-tax charge in the first quarter of 2019.

Regulated property will be depreciated on a straight-line basis based on projected service lives. Actual average composite depreciation rates for SCANA’s utility property, plant and equipment were as follows:


	2018
(millions)
Generation		2.61	%
Transmission		2.47
Distribution		2.48
Storage		2.48
General and other		5.64

Nonregulated property, plant and equipment, excluding land, will be depreciated on a straight-line basis over the remaining useful lives of such property, primarily ranging from 5 to 78 years.

SCE&G jointly owns and is the operator of Summer. At December 31, 2018, and subsequent to the SCANA Combination, SCE&G had a 66.7% ownership interest in Summer, of which its proportionate share of plant in service, accumulated depreciation and plant under construction was $1.5 billion, $644 million and $128 million, respectively. The co-owners are obligated to pay their share of all future construction expenditures and operating costs of Summer in the same proportion as their respective ownership interest.

Regulatory Assets

In addition to the items discussed above related to the NND Project, Dominion Energy intends to forego recovery of approximately $190 million of regulatory assets related to certain deferred income taxes for which it expects to recognize a $145 million after-tax charge in the first quarter of 2019.

Intangible Assets

Other current assets presented in the table above include intangible assets subject to regulatory recovery with a gross carrying value of $281 million and related accumulated amortization of $181 million. Such intangible assets have an estimated


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weighted-average amortization period of approximately five years. Annual amortization expense for these intangible assets is estimated to be as follows:


	2019		2020		2021		2022		2023
(millions)
SCANA	$	95	$	90	$	80	$	74	$	71

Asset Retirement Obligations

The purchase price allocation above includes $577 million of AROs, of which $23 million is considered to be a current liability. These AROs are associated with SCANA’s legal obligation to decommission Summer, as well as conditional obligations related to generation, transmission and distribution properties, including gas pipelines.

Short-Term and Long-Term Debt

At closing of the SCANA Combination, commercial paper and letters of credit outstanding, as well as capacity available under SCANA’s existing credit facilities were as follows:


	SCANA Corporation			SCE&G			PSNC			Total
(millions, except percentages)
Total facility limit	$	400		$	1,200	(1)	$	200		$	1,800
Letters of credit advances		40	(2)		—			—			40
Weighted-average interest rate		3.87	%		n/a			n/a			3.87	%
Outstanding commercial paper		2			73			98			173
Weighted-average interest rate		3.65	%		3.82	%		3.49	%		3.63	%
Outstanding letters of credit		37			—			—			37
Facility capacity available	$	321		$	1,127		$	102		$	1,550

(1)	Includes South Carolina Fuel Company, Inc.’s $500 million credit facility.

(2)	In January 2019, SCANA repaid $40 million in letter of credit advances.

In connection with the SCANA Combination, Dominion Energy intends to terminate SCANA, SCE&G and PSNC’s existing credit facilities, scheduled to expire in December 2020, and add SCE&G as a co-borrower to its $6.0 billion joint revolving credit facility in the first quarter of 2019 once certain regulatory approvals are obtained. In January 2019, Virginia Power and SCE&G, as co-borrowers, filed with the Virginia Commission and the South Carolina Commission, respectively, for approval. In February 2019, the Virginia Commission approved the request. SCE&G is required to obtain FERC approval to issue short-term indebtedness, including commercial paper, and to assume liabilities as a guarantor. In February 2019, Dominion Energy terminated South Carolina Fuel Company, Inc.’s existing credit facility, scheduled to expire in December 2020.

At closing of the SCANA Combination, SCANA had the following long-term debt outstanding which is part of the total consideration provided for the transaction.


	Weighted- average Coupon(1)			Amount
(millions, except percentages)
Unsecured medium term notes, due 2020 to 2022		5.42	%	$	800
Unsecured senior notes, due 2019 to 2034		3.44			70
First mortgage bonds, due 2021 to 2065		5.52			4,990
GENCO notes, due 2019 to 2024		5.49			40
Industrial and pollution control bonds, due 2028 to 2038(2)		3.52			122
PSNC senior debentures and notes, due 2020 to 2047		5.07			700
Other, due 2019 to 2027		3.46			73
Total principal				$	6,795
Current maturities of long-term debt					(59	)
Unamortized discount, premium and debt issuance costs, net					(29	)
SCANA total long-term debt				$	6,707

(1)	Represents weighted-average coupon rates for debt outstanding at closing of the SCANA Combination.

(2)	Includes variable rate debt of $68 million, with a weighted-average interest rate of 1.72%, which is hedged by fixed swaps.

Based on stated maturity dates rather than early redemption dates that could be elected by instrument holders, the scheduled principal payments of long-term debt at closing of the SCANA Combination, were as follows:


	2019			2020			2021			2022			2023			Thereafter			Total
(millions, except percentages)
Unsecured senior notes	$	4		$	4		$	4		$	4		$	4		$	50		$	70
Unsecured medium term notes		—			250			300			250			—			—			800
First mortgage bonds		—			—			330			—			—			4,660			4,990
PSNC senior debentures and notes		—			100			150			—			—			450			700
GENCO notes		7			7			7			7			7			5			40
Industrial and pollution control bonds		—			—			—			—			—			122			122
Other		48			7			6			5			3			4			73
Total	$	59		$	368		$	797		$	266		$	14		$	5,291		$	6,795
Weighted-average coupon		3.91	%		6.26	%		4.20	%		5.22	%		3.29	%		5.51	%		5.36	%

In February 2019, SCANA launched a tender offer for certain of its medium term notes having an aggregate purchase price of up to $300 million that expires in March 2019. Also in February 2019, SCE&G launched a tender offer for any and all of certain of its first mortgage bonds pursuant to which it purchased first mortgage bonds having an aggregate purchase price of $1.0 billion. SCE&G simultaneously launched a tender offer that expires in March 2019 for certain other of its first mortgage bonds having an aggregate purchase price equal to $1.2 billion less the aggregate purchase price paid in the any and all tender offer.


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Preferred Stock

At the closing of the SCANA Combination, authorized shares of SCE&G preferred stock were 20 million, of which 1,000 shares, no par value, were held by SCANA.

REGULATORY MATTERS AND PROCEEDINGS

Base Load Review Act

In 2016, the South Carolina Commission approved revised rates under the Base Load Review Act allowing the incorporation of financing costs associated with SCE&G’s incremental construction work in progress incurred for the NND Project and setting an allowed ROE of 10.5%. In July 2018, the South Carolina Commission issued orders implementing a June 2018 legislatively-mandated temporary reduction in revenues that could be collected by SCE&G from its electric utility customers under the Base Load Review Act and altering certain provisions previously applicable under the Base Load Review Act, including redefining the standard of care required by the associated regulations and supplying definitions of key terms that would affect the evidence required to establish SCE&G’s ability to recover its costs associated with the NND Project. These orders reduced the portion of SCE&G’s retail electric rates associated with the NND Project from approximately 18% of the average residential electric customer’s bill, which equates to a reduction in revenues of approximately $31 million per month, retroactive to April 2018. These lower rates remained in effect until February 2019, when the new rates pursuant to the SCANA Merger Approval Order became effective.

In June 2018, SCE&G filed a lawsuit in the U.S. District Court for the District of South Carolina challenging the constitutionality of the rate reductions under the Base Load Review Act. In the lawsuit, which was subsequently amended, SCE&G sought a declaration that the new laws are unconstitutional. In January 2019, SCE&G voluntarily dismissed this lawsuit.

2017 Tax Reform Act

In connection with the SCANA Merger Approval Order, the South Carolina Commission approved SCE&G’s provision of approximately $100 million in bill credits related to the 2017 Tax Reform Act’s impact on retail electric customer rates for the period beginning January 2018 through January 2019. These credits have been included in bills rendered on and after the first billing cycle of February 2019. In addition, the South Carolina Commission approved a tax rider whereby the effects of the reduction in the corporate income tax rate resulting from the 2017 Tax Reform Act will benefit retail electric customers. This tax rider is expected to reduce base rates to retail electric customers by approximately $67 million in each of 2019 and 2020, effective with the first billing cycle of February 2019.

In October 2018, the South Carolina Commission issued an order approving adjustment to SCE&G’s natural gas rate schedules, under the terms of the Natural Gas Rate Stabilization Act, to reflect the reduction in the federal corporate tax rate arising from the 2017 Tax Reform Act. The approved natural gas rate schedules also included a tax reform rate rider to refund certain income tax amounts previously collected from customers. These lower rates, representing a $20 million decreased revenue requirement, became effective for bills rendered on and after the first billing cycle in November 2018.

In December 2018, the North Carolina Commission issued an order approving PSNC’s proposed adjustments to customer rates, representing a $13 million decreased revenue requirement, to reflect the reduction in the federal corporate tax rate arising from the 2017 Tax Reform Act. These lower rates became effective for service rendered on and after January 1, 2019. Amounts collected in customer rates during 2018 and amounts arising from excess deferred income taxes have been recorded in regulatory liabilities and must be considered in PSNC’s next general rate case proceeding or in three years, whichever is sooner. The reduction in the federal corporate tax rate and its impact on PSNC’s various rate riders will be addressed in future proceedings related to those riders.

DSM Programs

SCE&G has approval for a DSM rider through which it recovers expenditures related to its DSM programs. In January 2019, SCE&G filed an application with the South Carolina Commission seeking approval to recover $30 million of costs and net lost revenues associated with these programs, along with an incentive to invest in such programs. This matter is pending.

LEGAL PROCEEDINGS

The following describes certain legal proceedings to which SCANA or SCE&G were a party to at closing of the SCANA Combination. Dominion Energy intends to vigorously contest the lawsuits, claims and assessments which have been filed or initiated against SCANA and SCE&G. No reference to, or disclosure of, any proceeding, item or matter described below shall be construed as an admission or indication that such proceeding, item or matter is material. Due to the uncertainty surrounding these matters, Dominion Energy is unable to make an estimate of the potential financial statement impacts; however, they could have a material impact on its results of operations, financial condition and/or cash flows.

Ratepayer Class Actions

In May 2018, a consolidated complaint against SCE&G, SCANA, and the State of South Carolina was filed in the State Court of Common Pleas in Hampton County, South Carolina (the SCE&G Ratepayer Case). In September 2018, the court certified this case as a class action. The plaintiffs allege, among other things, that SCE&G was negligent and unjustly enriched, breached alleged fiduciary and contractual duties and committed fraud and misrepresentation in failing to properly manage the NND Project, and that SCE&G committed unfair trade practices and violated state anti-trust laws. The plaintiffs sought a declaratory judgment that SCE&G may not charge its customers for any past or continuing costs of the NND Project, sought to have SCANA and SCE&G’s assets frozen and all monies recovered from Toshiba Corporation and other sources be placed in a constructive trust for the benefit of ratepayers and sought specific performance of the alleged implied contract to construct the NND Project.

In December 2018, the State Court of Common Pleas in Hampton County entered an order granting preliminary approval of a class action settlement and a stay of pre-trial proceedings in the SCE&G Ratepayer Case. The settlement agreement, contingent upon the closing of the SCANA Combination, provides that SCANA and SCE&G would establish an escrow account and proceeds from the escrow account would be distributed to the


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Combined Notes to Consolidated Financial Statements, Continued

class members, after payment of certain taxes, attorneys’ fees and other expenses and administrative costs. The escrow account would include (1) up to $2.0 billion, net of a credit of up to $2.0 billion in future electric bill relief, which would inure to the benefit of the escrow account in favor of class members over a period of time established by the South Carolina Commission in its order related to matters before the South Carolina Commission related to the NND Project, (2) a cash payment of $115 million and (3) the transfer of certain SCE&G-owned real estate or sales proceeds from the sale of such properties, which counsel for the SCE&G Ratepayer Class estimate to have an aggregate value between $60 million and $85 million. At the closing of the SCANA Combination, SCANA and SCE&G have funded this escrow account. The court has scheduled a fairness hearing on the settlement in May 2019. Any distribution from the escrow account is subject to court approval. As a result, Dominion Energy expects to reflect an approximately $180 million ($135 million after-tax) charge in the first quarter of 2019.

In September 2017, a purported class action was filed against Santee Cooper, SCE&G, Palmetto Electric Cooperative, Inc. and Central Electric Power Cooperative, Inc. in the State Court of Common Pleas in Hampton County, South Carolina (the Santee Cooper Ratepayer Case). The allegations are substantially similar to those in the SCE&G Ratepayer Case. The plaintiffs seek a declaratory judgment that the defendants may not charge the purported class for reimbursement for past or future costs of the NND Project. In March 2018, the plaintiffs filed an amended complaint including as additional named defendants, including certain then current and former directors of Santee Cooper and SCANA. In June 2018, Santee Cooper filed a Notice of Petition for Original Jurisdiction with the Supreme Court of South Carolina. In December 2018, Santee Cooper filed its answer to the plaintiffs’ fourth amended complaint and filed cross claims against SCE&G. This case is pending. Dominion Energy cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to its results of operations, financial condition and/or cash flows.

RICO Class Action

In January 2018, a purported class action was filed, and subsequently amended, against SCANA, SCE&G and certain former executive officers in the U.S. District Court for the District of South Carolina. The plaintiff alleges, among other things, that SCANA, SCE&G and the individual defendants participated in an unlawful racketeering enterprise in violation of RICO and conspired to violate RICO by fraudulently inflating utility bills to generate unlawful proceeds. The SCE&G Ratepayer Class Action settlement described previously contemplates dismissal of claims by SCE&G ratepayers in this case against SCE&G, SCANA and their officers. This case is pending. Dominion Energy cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to its results of operations, financial condition and/or cash flows.

State Court Shareholder Actions

In September 2017, a purported shareholder derivative action was filed against certain former executive officers and directors of SCANA in the State Court of Common Pleas in Richland County, South Carolina. In September 2018, this action was consolidated with another action in the Business Court Pilot

Program in Richland County. The plaintiffs allege, among other things, that the defendants breached their fiduciary duties to shareholders by their gross mismanagement of the NND Project, and that the defendants were unjustly enriched by bonuses they were paid in connection with the project. The defendants have filed a motion to dismiss the consolidated action in favor of the pending federal derivative action. This case is pending. Dominion Energy cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to its results of operations, financial condition and/or cash flows.

In January 2018, a purported class action was filed against SCANA, Dominion Energy and certain former executive officers and directors in the State Court of Common Pleas in Lexington County, South Carolina (the City of Warren Lawsuit). The plaintiff alleges, among other things, that defendants violated their fiduciary duties to shareholders by executing a merger agreement that would unfairly deprive plaintiffs of the true value of their SCANA stock, and that Dominion Energy aided and abetted these actions. Among other remedies, the plaintiff seeks to enjoin and/or rescind the merger. In February 2018, Dominion Energy removed the case to the U.S. District Court for the District of South Carolina, and filed a Motion to Dismiss in March 2018. In June 2018, the case was remanded back to the State Court of Common Pleas in Lexington County. Dominion Energy appealed the decision to remand to the U.S. Court of Appeals for the Fourth Circuit, where the appeal has been consolidated with a similar appeal and remains pending. In October 2018, the U.S. District Court for the District of South Carolina granted Dominion Energy’s motion to stay pending appeal. This case is pending. Dominion Energy cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to its results of operations, financial condition and/or cash flows.

In February 2018, a purported class action was filed against certain former directors of SCANA and SCE&G and Dominion Energy in the State Court of Common Pleas in Richland County, South Carolina. The allegations made and the relief sought by the plaintiffs are substantially similar to that described for the City of Warren Lawsuit. In February 2018, Dominion Energy removed the case to the U.S. District Court for the District of South Carolina, and filed a Motion to Dismiss in March 2018. In August 2018, the case was remanded back to the State Court of Common Pleas in Richland County. Dominion Energy appealed the decision to remand to the U.S. Court of Appeals for the Fourth Circuit, where the appeal has been consolidated with the City of Warren Lawsuit. This case is pending. Dominion Energy cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to its results of operations, financial condition and/or cash flows.

Federal Court Shareholder Action

In November 2017, a purported shareholder derivative action was filed against SCANA and certain former executive officers and directors in the U.S. District Court of the District of South Carolina. Another purported shareholder derivative action was filed against nearly all of these defendants. In January 2018, the U.S. District Court for the District of South Carolina consolidated these suits, and the plaintiffs filed a consolidated amended complaint. The plaintiffs allege, among other things, that the defendants violated their fiduciary duties to shareholders by


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disseminating false and misleading information about the NND Project, failing to maintain proper internal controls, failing to properly oversee and manage SCANA and that the individual defendants were unjustly enriched in their compensation. In June 2018, the court denied the defendants’ motions to dismiss and in October 2018, the court denied SCANA’s motion to stay all proceedings pending investigation by a Special Litigation Committee, with leave to refile after the SCANA Merger Approval Order was issued. The plaintiffs have agreed to a stay of this action on the condition that defendants file a motion for judgment on the pleadings, which was filed in January 2019. This case is pending. Dominion Energy cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to its results of operations, financial condition and/or cash flows.

Federal Court 10b-5 and Merger Actions

In September 2017, a purported class action was filed against SCANA and certain former executive officers and directors in the U.S. District Court for the District of South Carolina. Subsequent additional purported class actions were separately filed against all or nearly all of these defendants. In January 2018, the U.S. District Court for the District of South Carolina consolidated these suits, and the plaintiffs filed a consolidated amended complaint in March 2018. The plaintiffs allege, among other things, that the defendants violated §10(b) of the Securities Exchange Act of 1934, as amended, and Rule 10b-5 promulgated thereunder, and that the individually named defendants are liable under §20(a) of same act. In June 2018, the defendants filed motions to dismiss, which are pending. Dominion Energy cannot currently estimate the financial statement impacts of this matter, but there could be a material impact to its results of operations, financial condition and/or cash flows.

Employment Class Action and Indemnification

In July 2018, a case filed in the U.S. District Court for the District of South Carolina was certified as a class action on behalf of persons who were formerly employed at the NND Project. The plaintiffs allege, among other things, that SCANA, Fluor Corporation and Fluor Enterprises, Inc. violated the Worker Adjustment and Retraining Notification Act in connection with the decision to stop construction at the NND Project. The plaintiffs allege that the defendants failed to provide adequate advance written notice of their terminations of employment, which is estimated to be as much as $75 million. SCE&G as co-owner of the NND project would have a 55% proportional share in the ultimate outcome. The ultimate loss could rise due to the Fluor defendants seeking indemnification from SCE&G.

In September 2018, a case was filed in the State Court of Common Pleas in Fairfield County, South Carolina by Fluor Enterprises, Inc. and Fluor Daniel Maintenance Services, Inc. against SCE&G and Santee Cooper. The plaintiffs make claims for indemnification, breach of contract and promissory estoppel arising from, among other things, the defendants’ alleged failure and refusal to defend and indemnify the Fluor defendants in the aforementioned case. These cases are pending.

FILOT Litigation and Related Matters

In November 2017, Fairfield County filed a complaint and a motion for temporary injunction against SCE&G in the State Court of Common Pleas in Fairfield County, South Carolina,

making allegations of breach of contract, fraud, negligent misrepresentation, breach of fiduciary duty, breach of implied duty of good faith and fair dealing and unfair trade practices related to SCE&G’s termination of the FILOT agreement between SCE&G and Fairfield County related to the NND Project. The plaintiff sought a temporary and permanent injunction to prevent SCE&G from terminating the FILOT agreement. The plaintiff withdrew the motion for temporary injunction in December 2017. Dominion Energy is currently unable to make an estimate of the potential impacts to its consolidated financial statements related to this matter. This case is pending.

Governmental Proceedings and Investigations

In June 2018, SCE&G received a notice of proposed assessment of approximately $410 million, excluding interest, from the SCDOR following its audit of SCE&G’s sales and use tax returns for the periods September 1, 2008 through December 31, 2017. The proposed assessment, which includes 100% of the NND Project, is based on the SCDOR’s position that SCE&G’s sales and use tax exemption for the NND Project does not apply because the facility will not become operational. SCE&G has protested the proposed assessment, which remains pending, and recorded an $11 million liability in its Consolidated Balance Sheet as of December 31, 2018 for its share of any taxes ultimately due.

In September and October 2017, SCANA was served with subpoenas issued by the U.S. Attorney’s Office for the District of South Carolina and the Staff of the SEC’s Division of Enforcement seeking documents related to the NND Project. In addition, the South Carolina Law Enforcement Division is conducting a criminal investigation into the handling of the NND Project by SCANA and SCE&G. These matters are pending. SCANA and SCE&G are cooperating fully with the investigations; however, Dominion Energy cannot currently predict whether or to what extent SCANA or SCE&G may incur a material liability.

Other

In December 2018, arbitration proceedings commenced between SCE&G and Cameco Corporation related to a supply agreement signed in May 2008. This agreement provides the terms and conditions under which SCE&G agreed to purchase uranium hexafluoride from Cameco Corporation over a period from 2010 to 2020. Cameco Corporation alleges that SCE&G violated this agreement by failing to purchase the stated quantities of uranium hexafluoride for 2017 and 2018 delivery years. SCE&G denies that it is in breach of the agreement and believes that it has reduced its purchase quantity within the terms of the agreement. Dominion Energy cannot determine the outcome or timing of this matter.

COMMITMENTS AND CONTINGENCIES

Abandoned NND Project

SCE&G, for itself and as agent for Santee Cooper, entered into an engineering, construction and procurement contract with Westinghouse and WECTEC in 2008 for the design and construction of the NND Project, of which SCE&G’s ownership share is 55%. Various difficulties were encountered in connection with the project. The ability of Westinghouse and WECTEC to adhere to established budgets and construction schedules was affected by many variables, including unanticipated difficulties encountered in connection with project engineering and the con


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Combined Notes to Consolidated Financial Statements, Continued

struction of project components, constrained financial resources of the contractors, regulatory, legal, training and construction processes associated with securing approvals, permits and licenses and necessary amendments to them within projected time frames, the availability of labor and materials at estimated costs and the efficiency of project labor. There were also contractor and supplier performance issues, difficulties in timely meeting critical regulatory requirements, contract disputes, and changes in key contractors or subcontractors. These matters preceded the filing for bankruptcy protection by Westinghouse and WECTEC in March 2017, and were the subject of comprehensive analyses performed by SCANA and Santee Cooper.

Based on the results of SCANA’s analysis, and in light of Santee Cooper’s decision to suspend construction on the NND Project, in July 2017, SCANA determined to stop the construction of the units and to pursue recovery of costs incurred in connection with the construction under the abandonment provisions of the Base Load Review Act or through other means. This decision by SCANA became the focus of numerous legislative, regulatory and legal proceedings. Some of these proceedings remain unresolved and are described above under the heading Legal Proceedings.

In September 2017, SCE&G, for itself and as agent for Santee Cooper, filed with the Bankruptcy Court Proofs of Claim for unliquidated damages against each of Westinghouse and WECTEC. These Proofs of Claim were based upon the anticipatory repudiation and material breach by Westinghouse and WECTEC of the contract, and assert against Westinghouse and WECTEC any and all claims that are based thereon or that may be related thereto. SCE&G and Santee Cooper remain responsible for any claims that may be made by Westinghouse and WECTEC against them relating to the contract.

Westinghouse’s reorganization plan was confirmed by the Bankruptcy Court and became effective in August 2018. In connection with the effectiveness of the reorganization plan, the contract associated with the NND Project was deemed rejected. SCE&G is contesting approximately $285 million of filed liens in Fairfield County, South Carolina. Most of these asserted liens are claims that relate to work performed by Westinghouse subcontractors before the Westinghouse bankruptcy, although some of them are claims arising from work performed after the Westinghouse bankruptcy.

Westinghouse has indicated that some unsecured creditors have sought or may seek amounts beyond what Westinghouse allocated when it submitted its reorganization plan to the Bankruptcy Court. If any unsecured creditor is successful in its attempt to include its claim as part of the class of general unsecured creditors beyond the amounts in the bankruptcy reorganization plan allocated by Westinghouse, it is possible that the reorganization plan will not provide for payment in full or nearly in full to its pre-petition trade creditors. The shortfall could be significant.

SCE&G and Santee Cooper are responsible for amounts owed to Westinghouse for valid work performed by Westinghouse subcontractors on the NND Project after the Westinghouse bankruptcy filing until termination of the interim assessment agreement. SCE&G does not believe that the claims asserted related to the interim assessment agreement period will exceed the amounts previously funded, whether relating to claims already paid or those remaining to be paid. SCE&G intends to oppose

any previously unasserted claim that is asserted against it, whether directly or indirectly by a claim through the interim assessment agreement. To the extent any such claim is determined to be valid, SCE&G may be responsible for paying its 55% share thereof.

Further, some Westinghouse subcontractors who have made claims against Westinghouse in the bankruptcy proceeding also filed against SCE&G and Santee Cooper in South Carolina state court for damages. Many of these claimants have also asserted construction liens against the NND Project site. SCE&G also intends to oppose these claims and liens. With respect to claims of Westinghouse Subcontractors, SCE&G believes there were sufficient amounts previously funded during the interim assessment agreement period to pay such validly asserted claims. With respect to the Westinghouse subcontractor claims which relate to other periods, SCE&G understands that such claims will be paid pursuant to Westinghouse’s confirmed bankruptcy reorganization plan. SCE&G further understands that the amounts paid under the plan may satisfy such claims in full. Therefore, SCE&G believes that the Westinghouse subcontractors may be paid substantially (and potentially in full) by Westinghouse. While Dominion Energy cannot be assured that it will not have any exposure on account of unpaid Westinghouse subcontractor claims, which SCE&G is presently disputing, Dominion Energy believes it is unlikely that it will be required to make payments on account of such claims. To the extent any such claim is determined to be valid, SCE&G may be responsible for paying its 55% share thereof.

Environmental Matters

Contingencies involving environmental matters, including ash pond and landfill closure costs, affecting SCANA have been included within Note 22.

Nuclear Insurance and Spent Nuclear Fuel

SCE&G’s maximum assessment for a nuclear incident under the Price-Anderson Amendments Act of 1988 would be $92 million per incident, but not more than $14 million per year, for its proportionate ownership interest in Summer. SCE&G currently maintains insurance policies, for itself and on behalf of Santee Cooper, with NEIL. The policies provide coverage to Summer for property damage and outage costs up to $2.8 billion resulting from an event of nuclear origin. The NEIL policies, in aggregate, are subject to a maximum loss of $2.8 billion for any single loss occurrence. Based on the current annual premium, SCE&G’s portion of the retrospective premium assessment would not exceed $23 million.

In addition, SCE&G currently maintains an excess property insurance policy, for itself and on behalf of Santee Cooper. The policy provides coverage to Summer for property damage and outage costs up to $415 million resulting from an event of non-nuclear origin. Based on the current annual premium, SCE&G’s portion of the retrospective premium assessment would not exceed $2 million.

SCE&G entered into a contract with the DOE for the disposal of spent nuclear fuel under provisions of the Nuclear Waste Policy Act of 1982.

Long-Term Purchase Agreements

SCANA has the following long-term commitments that are noncancelable or are cancelable only under certain conditions, and


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that a third party has used to secure financing for the facility that will provide the contracted goods or services:


	2019		2020		2021		2022		2023		Thereafter		Total
(millions)
Purchased electric capacity(1)	$	31	$	30	$	30	$	30	$	30	$	310	$	461

(1)	Commitments represent estimated amounts payable for capacity under power purchase contracts with qualifying facilities which expire at various dates through 2046. Capacity payments under the contracts are generally based on fixed dollar amounts per month.

Lease Commitments

SCANA is obligated under various operating leases for land, office space, furniture, equipment, rail cars and airplanes. Such leases expire at various dates through 2057.


	2019		2020		2021		2022		2023		Thereafter		Total
(millions)
Operating leases	$	10	$	8	$	7	$	6	$	4	$	30	$	65

Unaudited Pro Forma Information

Dominion Energy incurred transaction costs of $27 million, recorded in other operations and maintenance expense in the Consolidated Statements of Income for the year end December 31, 2018. These costs consist of professional fees and other miscellaneous costs.

The following unaudited pro forma financial information reflects the consolidated results of operations of Dominion Energy assuming the SCANA Combination had taken place on January 1, 2018. The unaudited pro forma financial information has been presented for illustrative purposes only and may change as Dominion Energy finalizes its valuation of certain assets acquired and liabilities assumed at the acquisition date. The unaudited pro forma financial information is not necessarily indicative of the consolidated results of operations that would have been achieved or the future consolidated results of operations of the combined company.


	Twelve Months Ended December 31,
	2018(1)
(millions, except EPS)
Operating Revenue	$	17,505
Net income attributable to Dominion Energy		2,081
Earnings Per Common Share – Basic	$	2.78
Earnings Per Common Share – Diluted	$	2.77

(1)	Amounts include adjustments for non-recurring costs directly related to the SCANA Combination.

ACQUISITION OF DOMINION ENERGY QUESTAR

In September 2016, Dominion Energy completed the Dominion Energy Questar Combination and Dominion Energy Questar, a Rockies-based integrated natural gas company consisting of Questar Gas, Wexpro and Dominion Energy Questar Pipeline, became a wholly-owned subsidiary of Dominion Energy. Questar Gas has regulated gas distribution operations in Utah, southwestern Wyoming and southeastern Idaho. Wexpro develops and produces natural gas from reserves supplied to Questar Gas under a cost-of-service framework. Dominion Energy Questar Pipeline provides FERC-regulated interstate natural gas transportation and storage services in Utah, Wyoming and western Colorado. The Dominion Energy Questar Combination provides Dominion Energy with pipeline infrastructure that provides a principal

source of gas supply to Western states. Dominion Energy Questar’s regulated businesses also provide further balance between Dominion Energy’s electric and gas operations.

In accordance with the terms of the Dominion Energy Questar Combination, at closing, each share of issued and outstanding Dominion Energy Questar common stock was converted into the right to receive $25.00 per share in cash. The total consideration was $4.4 billion based on 175.5 million shares of Dominion Energy Questar outstanding at closing.

Dominion Energy financed the Dominion Energy Questar Combination through the: (1) August 2016 issuance of $1.4 billion of 2016 Equity Units, (2) August 2016 issuance of $1.3 billion of senior notes, (3) September 2016 borrowing of $1.2 billion under a term loan agreement and (4) $500 million of the proceeds from the April 2016 issuance of common stock.

Purchase Price Allocation

Dominion Energy Questar’s assets acquired and liabilities assumed were measured at estimated fair value at the closing date and are included in the Gas Infrastructure operating segment. The majority of operations acquired are subject to the rate-setting authority of FERC, as well as the Utah Commission and/or the Wyoming Commission and therefore are accounted for pursuant to ASC 980, Regulated Operations. The fair values of Dominion Energy Questar’s assets and liabilities subject to rate-setting and cost recovery provisions provide revenues derived from costs, including a return on investment of assets and liabilities included in rate base. As such, the fair values of these assets and liabilities equal their carrying values. Accordingly, neither the assets and liabilities acquired, nor the pro forma financial information, reflect any adjustments related to these amounts.

The fair value of Dominion Energy Questar’s assets acquired and liabilities assumed that are not subject to the rate-setting provisions discussed above was determined using the income approach. In addition, the fair value of Dominion Energy Questar’s 50% interest in White River Hub, accounted for under the equity method, was determined using the market approach and income approach. The valuations are considered Level 3 fair value measurements due to the use of significant judgmental and unobservable inputs, including projected timing and amount of future cash flows and discount rates reflecting risk inherent in the future cash flows and future market prices.

The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill at the closing date. The goodwill reflects the value associated with enhancing Dominion Energy’s regulated portfolio of businesses, including the expected increase in demand for low-carbon, natural gas-fired generation in the Western states and the expected continued growth of rate-regulated businesses located in a defined service area with a stable regulatory environment. The goodwill recognized is not deductible for income tax purposes, and as such, no deferred taxes have been recorded related to goodwill.

The table below shows the allocation of the purchase price to the assets acquired and liabilities assumed at closing which reflects the following adjustments from the preliminary valuation recognized during the measurement period. During the fourth quarter of 2016, certain modifications were made to preliminary valuation amounts for acquired property, plant and equipment, current liabilities, and deferred income taxes, resulting in a $6 million net decrease to goodwill, which related primarily to


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Combined Notes to Consolidated Financial Statements, Continued

the sale of Questar Fueling Company in December 2016 as further described in the Sale of Questar Fueling Company. In the third quarter of 2017, certain modifications were made to the valuation amounts for regulatory liabilities, current liabilities and deferred income taxes, resulting in a $6 million net increase to goodwill recorded in Dominion Energy’s Consolidated Balance Sheets. The modifications relate primarily to the finalization of Dominion Energy Questar’s 2016 tax return for the period January 1, 2016 through the Dominion Energy Questar Combination, as well as certain regulatory adjustments.


	Amount
(millions)
Total current assets	$	224
Investments(1)		58
Property, plant and equipment, net(2)		4,131
Goodwill		3,111
Total deferred charges and other assets, excluding goodwill		75
Total Assets		7,599
Total current liabilities(3)		793
Long-term debt(4)		963
Deferred income taxes		807
Regulatory liabilities		259
Asset retirement obligations		160
Other deferred credits and other liabilities		220
Total Liabilities		3,202
Total purchase price		4,397

(1)	Includes $40 million for an equity method investment in White River Hub. The fair value adjustment on the equity method investment in White River Hub is considered to be equity method goodwill and is not amortized.

(2)	Nonregulated property, plant and equipment, excluding land, will be depreciated over remaining useful lives primarily ranging from 9 to 18 years.

(3)	Includes $301 million of short-term debt, of which no amounts remain outstanding at December 31, 2018, as well as a $250 million variable interest rate term loan due in August 2017 that was paid in July 2017.

(4)	Unsecured senior and medium-term notes with maturities which range from 2017 to 2048 and bear interest at rates from 2.98% to 7.20%.

Regulatory Matters

The transaction required approval of Dominion Energy Questar’s shareholders, clearance from the Federal Trade Commission under the Hart-Scott-Rodino Act and approval from both the Utah Commission and the Wyoming Commission. In February 2016, the Federal Trade Commission granted antitrust approval of the Dominion Energy Questar Combination under the Hart-Scott-Rodino Act. In May 2016, Dominion Energy Questar’s shareholders voted to approve the Dominion Energy Questar Combination. In August 2016 and September 2016, approvals were granted by the Utah Commission and the Wyoming Commission, respectively. Information regarding the transaction was also provided to the Idaho Commission, who acknowledged the Dominion Energy Questar Combination in October 2016, and directed Dominion Energy Questar to notify the Idaho Commission when it makes filings with the Utah Commission.

With the approval of the Dominion Energy Questar Combination in Utah and Wyoming, Dominion Energy agreed to the following:

	•		Contribution of $75 million to Dominion Energy Questar’s qualified and non-qualified defined-benefit pension plans and its other post-employment benefit plans within

		six months of the closing date. This contribution was made in January 2017.

	•		Increasing Dominion Energy Questar’s historical level of corporate contributions to charities by $1 million per year for at least five years.

	•		Withdrawal of Questar Gas’ general rate case filed in July 2016 with the Utah Commission and agreement to not file a general rate case with the Utah Commission to adjust its base distribution non-gas rates prior to July 2019, unless otherwise ordered by the Utah Commission. In addition, Questar Gas agreed not to file a general rate case with the Wyoming Commission with a requested rate effective date earlier than January 2020. Questar Gas’ ability to adjust rates through various riders is not affected.

Results of Operations and Unaudited Pro Forma Information

The impact of the Dominion Energy Questar Combination on Dominion Energy’s operating revenue and net income attributable to Dominion Energy in the Consolidated Statements of Income for the twelve months ended December 31, 2016 was an increase of $379 million and $73 million, respectively.

Dominion Energy incurred transaction and transition costs in 2018, 2017 and 2016, of which $9 million, $26 million and $58 million was recorded in other operations and maintenance expense, respectively, and $16 million was recorded in interest and related charges in 2016 in Dominion Energy’s Consolidated Statements of Income. These costs consist of the amortization of financing costs, the charitable contribution commitment described above, employee-related expenses, professional fees, and other miscellaneous costs.

The following unaudited pro forma financial information reflects the consolidated results of operations of Dominion Energy assuming the Dominion Energy Questar Combination had taken place on January 1, 2016. The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of the consolidated results of operations that would have been achieved or the future consolidated results of operations of the combined company.


	Twelve Months Ended December 31,
	2016(1)
(millions, except EPS)
Operating Revenue	$	12,497
Net income attributable to Dominion Energy		2,300
Earnings Per Common Share – Basic	$	3.73
Earnings Per Common Share – Diluted	$	3.73

(1)	Amounts include adjustments for non-recurring costs directly related to the Dominion Energy Questar Combination.

Contribution of Dominion Energy Questar Pipeline to Dominion Energy Midstream

In October 2016, Dominion Energy entered into the Contribution Agreement under which Dominion Energy contributed Dominion Energy Questar Pipeline to Dominion Energy Midstream. Upon closing of the agreement on December 1, 2016, Dominion Energy Midstream became the owner of all of the issued and outstanding membership interests of Dominion Energy Questar Pipeline in exchange for consideration consisting


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of Dominion Energy Midstream common and convertible preferred units with a combined value of $467 million and cash payment of $823 million, $300 million of which is considered a debt-financed distribution, for a total of $1.3 billion. In addition, under the terms of the Contribution Agreement, Dominion Energy Midstream repurchased 6,656,839 common units from Dominion Energy, and repaid its $301 million promissory note to Dominion Energy in December 2016. The cash proceeds from these transactions were utilized in December 2016 to repay the $1.2 billion term loan agreement borrowed in September 2016. Since Dominion Energy consolidates Dominion Energy Midstream for financial reporting purposes, the transactions associated

with the Contribution Agreement were eliminated upon consolidation. See Note 5 for the tax impacts of the transactions.

Sale of Questar Fueling Company

In December 2016, Dominion Energy completed the sale of Questar Fueling Company. The proceeds from the sale were $28 million, net of transaction costs. No gain or loss was recorded in Dominion Energy’s Consolidated Statements of Income, as the sale resulted in measurement period adjustments to the net assets acquired of Dominion Energy Questar. See the Purchase Price Allocation section above for additional details on the measurement period adjustments recorded.

Wholly-Owned Merchant Solar Projects

ACQUISITIONS

The following table presents significant completed acquisitions of wholly-owned merchant solar projects by Dominion Energy.


Completed Acquisition Date	Seller	Number of Projects			Project Location	Project Name(s)	Initial Acquisition (millions)(1)		Project Cost (millions)(2)		Date of Commercial Operations	MW Capacity
February 2017	Community Energy Solar, LLC		1		Virginia	Amazon Solar Farm Virginia—Southhampton	$	29	$	205	December 2017		100
March 2017	Solar Frontier Americas Holding LLC		1	(3)	California	Midway II		77		78	June 2017		30
May 2017	Cypress Creek Renewables, LLC		1		North Carolina	IS37		154		160	June 2017		79
June 2017	Hecate Energy Virginia C&C LLC		1		Virginia	Clarke County		16		16	August 2017		10
June 2017	Strata Solar Development, LLC/Moorings Farm 2 Holdco, LLC		2		North Carolina	Fremont, Moorings 2		20		20	November 2017		10
September 2017	Hecate Energy Virginia C&C LLC		1		Virginia	Cherrydale		40		41	November 2017		20
October 2017	Strata Solar Development, LLC		2		North Carolina	Clipperton, Pikeville		20		21	November 2017		10

(1)	The purchase price was primarily allocated to Property, Plant and Equipment.

(2)	Includes acquisition cost.

(3)	In April 2017, Dominion Energy discontinued efforts on the acquisition of the additional 20 MW solar project from Solar Frontier Americas Holding LLC.

In addition during 2016, Dominion Energy acquired 100% of the equity interests of seven solar projects in Virginia, North Carolina and South Carolina for an aggregate purchase price of $32 million, all of which was allocated to property, plant and equipment. The projects cost $421 million in total, including initial acquisition costs, and generate 221 MW combined. One of the projects commenced commercial operations in 2016 and the remaining projects commenced commercial operations in 2017.

Long-term power purchase, interconnection and operation and maintenance agreements have been executed for all of the projects described above. These projects are included in the Power Generation operating segment. Dominion Energy has claimed federal investment tax credits on these solar projects.

SALE OF INTEREST IN MERCHANT SOLAR PROJECTS

In September 2015, Dominion Energy signed an agreement to sell a noncontrolling interest (consisting of 33% of the equity interests) in all of its then-currently wholly-owned merchant solar projects, 24 solar projects totaling 425 MW, to SunEdison. In December 2015, the sale of interest in 15 of the solar projects closed for $184 million with the sale of interest in the remaining projects completed in January 2016 for $117 million. Upon closing, SunEdison sold its interest in these projects to Terra Nova Renewable Partners.

Non-Wholly-Owned Merchant Solar Projects

ACQUISITIONS OF FOUR BROTHERS AND THREE CEDARS

In June 2015, Dominion Energy acquired 50% of the units in Four Brothers from SunEdison for $64 million of consideration. Four Brothers operates four solar projects located in Utah, which produce and sell electricity and renewable energy credits. The facilities began commercial operations during the third quarter of 2016, generating 320 MW, at a cost of approximately $670 million.

In September 2015, Dominion Energy acquired 50% of the units in Three Cedars from SunEdison for $43 million of consideration. Three Cedars operates three solar projects located in Utah, which produce and sell electricity and renewable energy credits. The facilities began commercial operations during the third quarter of 2016, generating 210 MW, at a cost of approximately $450 million.

The Four Brothers and Three Cedars facilities operate under long-term power purchase, interconnection and operation and maintenance agreements. Dominion Energy claimed 99% of the federal investment tax credits on the projects.


				115

Combined Notes to Consolidated Financial Statements, Continued

Dominion Energy has assumed the majority of the agreements to provide administrative and support services in connection with operations and maintenance of the facilities and technical management services of the solar facilities. Costs related to services to be provided under these agreements were immaterial for the years ended December 31, 2018, 2017 and 2016.

In November 2016, NRG acquired the 50% of units in Four Brothers and Three Cedars previously held by SunEdison. Subsequent to Dominion Energy’s acquisition of Four Brothers and

Three Cedars, SunEdison and NRG made contributions to Four Brothers and Three Cedars of $301 million in aggregate through December 31, 2017, which are reflected as noncontrolling interests in the Consolidated Balance Sheets. In August 2018, NRG’s ownership in Four Brothers and Three Cedars was transferred to GIP.

DOMINION ENERGY AND DOMINION ENERGY GAS

Blue Racer

See Note 9 for a discussion of transactions related to Blue Racer.

NOTE 4. OPERATING REVENUE

The Companies’ operating revenue, subsequent to the adoption of revised guidance for revenue recognition from contracts with customers, consists of the following:


Year Ended December 31,	2018
(millions)
Dominion Energy
Regulated electric sales:
Residential	$	3,413
Commercial		2,503
Industrial		490
Government and other retail		854
Wholesale		137
Nonregulated electric sales		1,294
Regulated gas sales:
Residential		818
Commercial		221
Other		36
Nonregulated gas sales		214
Regulated gas transportation and storage:
FERC-regulated		1,091
State-regulated		640
Nonregulated gas transportation and storage		442
Other regulated revenues		179
Other nonregulated revenues(1)(2)		563
Total operating revenue from contracts with customers		12,895
Other revenues(2)(3)		471
Total operating revenue	$	13,366
Virginia Power
Regulated electric sales:
Residential	$	3,413
Commercial		2,503
Industrial		490
Government and other retail		854
Wholesale		137
Other regulated revenues		132
Other nonregulated revenues(1)(2)		55
Total operating revenue from contracts with customers		7,584
Other revenues(1)(3)		35
Total operating revenue	$	7,619
Dominion Energy Gas
Regulated gas sales:
Residential	$	81
Other		27
Nonregulated gas sales(1)		13
Regulated gas transportation and storage:
FERC-regulated(1)		763
State-regulated(1)		605
NGL revenue(1)(2)		223
Management service revenue(1)		205
Other regulated revenues(1)		22
Other nonregulated revenues(1)		10
Total operating revenue from contracts with customers		1,949
Other revenues		(9	)
Total operating revenue	$	1,940


116

(1)	See Notes 9 and 24 for amounts attributable to related parties and affiliates.

(2)

Amounts above include $241 million and $206 million for the year ended December 31, 2018 primarily consisting of NGL sales at Dominion Energy and Dominion Energy Gas, respectively, which are considered to be goods transferred at a point in time. In addition, the amounts include $17 million and $11 million of sales of renewable energy credits at both Dominion Energy and Virginia Power for the year ended December 31, 2018, respectively, which are considered to be goods transferred at a point in time.

(3)	Amounts above include $15 million of alternative revenue at Dominion Energy and Virginia Power for the year ended December 31, 2018.

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


Revenue expected to be recognized on multi-year contracts in place at December 31, 2018	2019		2020		2021		2022		2023		Thereafter		Total
(millions)

Dominion Energy	$	1,643	$	1,563	$	1,448	$	1,319	$	1,154	$	13,693	$	20,820
Virginia Power		21		3		1		—		—		—		25
Dominion Energy Gas		600		560		475		384		268		1,612		3,899

Contract assets represent an entity’s right to consideration in exchange for goods and services that the entity has transferred to a customer. At December 31, 2018 and December 31, 2017, Dominion Energy’s contract asset balances were $42 million and $46 million, respectively. Dominion Energy Gas’ contract asset balances were $58 million and $66 million at December 31, 2018 and December 31, 2017, respectively. Dominion Energy and Dominion Energy Gas’ contract assets are recorded in other deferred charges and other assets in the Consolidated Balance Sheets. Contract liabilities represent an entity’s obligation to transfer goods or services to a customer for which the entity has received consideration, or the amount that is due, from the customer. At December 31, 2018 and December 31, 2017, Dominion Energy’s contract liability balances were $106 million and $132 million, respectively. At December 31, 2018 and December 31, 2017, Virginia Power’s contract liability balances were $22 million and $50 million, respectively. At December 31, 2018 and December 31, 2017, Dominion Energy Gas’ contract liability balances were $40 million and $41 million, respectively. During the year ended December 31, 2018, Dominion Energy, Virginia Power and Dominion Energy Gas recognized revenue of $94 million, $25 million and $41 million, respectively, from the beginning contract liability balances as the Companies fulfilled their obligations to provide service to their customers. The Companies’ contract liabilities are recorded in other current liabilities and other deferred credits and other liabilities in the Consolidated Balance Sheets.

The Companies’ operating revenue, prior to the adoption of revised guidance for revenue recognition from contracts with customers, consisted of the following:


Year Ended December 31,	2017		2016
(millions)
Dominion Energy
Electric sales:
Regulated	$	7,383	$	7,348
Nonregulated		1,429		1,519
Gas sales:
Regulated		1,067		500
Nonregulated		457		354
Gas transportation and storage		1,786		1,636
Other		464		380
Total operating revenue	$	12,586	$	11,737
Virginia Power
Regulated electric sales	$	7,383	$	7,348
Other		173		240
Total operating revenue	$	7,556	$	7,588
Dominion Energy Gas
Gas sales:
Regulated	$	87	$	119
Nonregulated		20		13
Gas transportation and storage		1,435		1,307
NGL revenue		91		62
Other		181		137
Total operating revenue	$	1,814	$	1,638

NOTE 5. INCOME TAXES

Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. The interpretation of tax laws involves uncertainty, since tax authorities may interpret the laws differently. The Companies are routinely audited by federal and state tax authorities. Ultimate resolution of income tax matters may result in favorable or unfavorable impacts to net income and cash flows, and adjustments to tax-related assets and liabilities could be material.


				117

Combined Notes to Consolidated Financial Statements, Continued

The 2017 Tax Reform Act included a broad range of tax reform provisions affecting the Companies as discussed in Note 2. The 2017 Tax Reform Act reduced the corporate income tax rate from 35% to 21% for tax years beginning after December 31, 2017. At the date of enactment, deferred tax assets and liabilities were remeasured based upon the new 21% enacted tax rate expected to apply when temporary differences are realized or settled. The specific provisions related to regulated public utilities in the 2017 Tax Reform Act generally allow for the continued deductibility of interest expense, changed the tax depreciation of certain property acquired after September 27, 2017, and continued certain rate normalization requirements for accelerated depreciation benefits.

As indicated in Note 2, certain of the Companies’ operations, including accounting for income taxes, are subject to regulatory accounting treatment. For regulated operations, many of the changes in deferred taxes represent amounts probable of collection from or refund to customers, and were recorded as either an

increase to a regulatory asset or liability. The 2017 Tax Reform Act included provisions that stipulate how these excess deferred taxes may be passed back to customers for certain accelerated tax depreciation benefits. Potential refunds of other deferred taxes may be determined by our regulators. See Note 13 for more information.

The Companies have accounted for the effects of the 2017 Tax Reform Act, although changes could occur as additional guidance is issued and finalized. In addition, certain states in which the Companies operate may or may not conform to some or all of the provisions of the 2017 Tax Reform Act. Ultimate resolution or clarification of these matters may result in favorable or unfavorable impacts to net income, cash flows, and tax-related assets and liabilities and could be material. The changes in deferred taxes resulting from the 2017 Tax Reform Act, and the Companies’ interpretations of proposed regulations issued in 2018, were recorded as either an increase to a regulatory liability or as an adjustment to the deferred tax provision.

Continuing Operations

Details of income tax expense for continuing operations including noncontrolling interests were as follows:


	Dominion Energy									Virginia Power									Dominion Energy Gas
Year Ended December 31,	2018			2017			2016			2018			2017			2016			2018			2017			2016
(millions)
Current:
Federal	$	(45	)	$	(1	)	$	(155	)	$	36		$	432		$	168		$	23		$	16		$	(27	)
State		108			(26	)		85			40			73			90			30			8			4
Total current expense (benefit)		63			(27	)		(70	)		76			505			258			53			24			(23	)
Deferred:
Federal
2017 Tax Reform Act impact		46			(851	)		—			21			(93	)		—			(11	)		(197	)		—
Taxes before operating loss carryforwards and investment tax credits		436			739			1,050			199			319			435			48			199			239
Tax utilization expense (benefit) of operating loss carryforwards		92			174			(161	)		—			4			(2	)		—			5			(2	)
Investment tax credits		(56	)		(200	)		(248	)		(51	)		(23	)		(25	)		—			—			—
State		(1	)		132			50			55			59			27			(4	)		20			1
Total deferred expense (benefit)		517			(6	)		691			224			266			435			33			27			238
Investment tax credit-gross deferral		2			5			35			2			5			35			—			—			—
Investment tax credit-amortization		(2	)		(2	)		(1	)		(2	)		(2	)		(1	)		—			—			—
Total income tax expense (benefit)	$	580		$	(30	)	$	655		$	300		$	774		$	727		$	86		$	51		$	215

The 2017 Tax Reform Act reduced the statutory federal income tax rate to 21% beginning in January 2018. Accordingly, current income taxes, and deferred income taxes that originate in 2018, are recorded at the new 21% rate. Dominion Energy had less than $1 million of state deferred income tax expense as a result of the reversal of deferred taxes upon the sale of its interest in Blue Racer and Fairless and Manchester. Dominion Energy’s current federal income taxes primarily include the recognition of a $47 million benefit related to a carryback claim for specified liability losses involving prior tax years.

The accounting for the reduction in the corporate income tax rate decreased deferred income tax expense by $851 million at Dominion Energy, $93 million at Virginia Power, and $197 million for Dominion Energy Gas for the year ending December 31, 2017. The decrease in deferred income taxes at Dominion Energy primarily relates to the remeasurement of deferred taxes on merchant operations and includes the effects at Virginia Power and Dominion Energy Gas. Virginia Power and Dominion Energy Gas have certain regulatory assets and liabilities that have not yet been charged or returned to customers through rates, or on which they do not earn a return, including unrecognized pension and other postretirement benefits. The remeasurement of the deferred taxes on these regulatory balances was charged to continuing operations in 2017. For ratemaking purposes, Dominion Energy Gas’ subsidiary DETI follows the cash method on pension contributions. Deferred taxes recorded on pension balances as required by GAAP are not included as a component of rates and therefore the remeasurement of these deferred taxes were charged to continuing operations in 2017.

In 2016, Dominion Energy realized a taxable gain resulting from the contribution of Dominion Energy Questar Pipeline to Dominion Energy Midstream. The contribution and related transactions resulted in increases in the tax basis of Dominion Energy Questar Pipeline’s assets and the number of Dominion Energy Midstream’s common and convertible preferred units held by noncontrolling interests. The direct tax effects of the transactions included a provision for current income taxes ($212 million) and an offsetting benefit for deferred income taxes ($96 million) and were charged to common shareholders’ equity. The federal tax liability was reduced by $129 million of tax


118

credits generated in 2016 that otherwise would have resulted in additional credit carryforwards and a $17 million benefit provided by the domestic production activities deduction. These benefits, as indirect effects of the contribution transaction, were reflected in Dominion Energy’s 2016 current federal income tax expense.

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


	Dominion Energy									Virginia Power									Dominion Energy Gas
Year Ended December 31,	2018			2017			2016			2018			2017			2016			2018			2017			2016
U.S. statutory rate		21.0	%		35.0	%		35.0	%		21.0	%		35.0	%		35.0	%		21.0	%		35.0	%		35.0	%
Increases (reductions) resulting from:
State taxes, net of federal benefit		3.0			2.0			2.4			4.7			3.7			3.8			3.2			2.4			0.5
Investment tax credits		(1.9	)		(6.3	)		(11.7	)		(3.5	)		(0.8	)		—			—			—			—
Production tax credits		(0.7	)		(0.7	)		(0.8	)		(0.7	)		(0.4	)		(0.5	)		—			—			—
Valuation allowances		0.3			0.2			1.2			—			—			0.1			1.8			0.3			—
Reversal of excess deferred income taxes		(2.0	)		—			—			(3.2	)		—			—			(1.7	)		—			—
Federal legislative change		1.5			(27.5	)		—			1.3			(4.0	)		—			(2.8	)		(29.5	)		—
State legislative change		(0.6	)		—			(0.6	)		—			—			—			0.2			—			—
AFUDC—equity		(0.8	)		(1.4	)		(0.6	)		(0.5	)		(0.6	)		(0.6	)		(0.6	)		(0.9	)		(0.2	)
Employee stock ownership plan deduction		(0.4	)		(0.6	)		(0.6	)		—			—			—			—			—			—
Other, net		(0.9	)		(1.7	)		(1.4	)		(0.1	)		0.6			(0.4	)		1.2			0.4			0.1
Effective tax rate		18.5	%		(1.0	)%		22.9	%		19.0	%		33.5	%		37.4	%		22.3	%		7.7	%		35.4	%

For the Companies’ rate-regulated entities, deferred taxes will reverse at the weighted average rate used to originate the deferred tax liability, which in some cases will be 35%. The Companies have recorded an estimate of the portion of excess deferred income tax amortization in 2018, and changes in estimates of amounts probable of collection from or return to customers. The reversal of these excess deferred income taxes will impact the effective tax rate, and may ultimately impact rates charged to customers. As described in Note 13 to the Consolidated Financial Statements, the Companies decreased revenue and increased regulatory liabilities to offset these deferred tax impacts in accordance with applicable regulatory commission orders or formula rate mechanisms.

In 2018, the Companies applied the provisions of recently proposed regulations addressing the availability of federal bonus depreciation for the period beginning after September 27, 2017 through December 31, 2017. The application of these changes increased Dominion Energy’s 2017 net operating loss carryforward, the benefit of which will be recognized at the 21% rate. As a result, Dominion Energy’s effective tax rate reflects a $23 million increase to deferred income tax expense associated with the remeasurement of this deferred tax asset. The application of these proposed regulations at Dominion Energy Gas had no impact on income tax expense as the changes in, and remeasurement of, deferred tax liabilities increased regulatory liabilities by $35 million. The effects of these changes at Virginia Power were immaterial. These amounts and adjustments represent the Companies’ best estimate based on available information, and could be subject to change based on additional guidance in yet to be finalized regulations. In addition, changes in estimates of amounts probable of return to or collection from customers increased deferred income tax expense at Virginia Power by $23 million and increased regulatory liabilities by $31 million. At Dominion Energy Gas similar changes in estimates decreased income tax expense by $11 million and regulatory liabilities by $16 million. These changes also impacted Dominion Energy. In addition, Dominion Energy and Dominion Energy Gas’ effective tax rates reflect the impacts of a state legislative change enacted in the second quarter of 2018 that was retroactive to January 1, 2018.

In 2017, the Companies’ effective tax rates reflect the net benefit of remeasurement of deferred taxes resulting from the lower corporate income tax rate promulgated by the 2017 Tax Reform Act, and the completion of audits by state tax authorities that resulted in the recognition of previously unrecognized tax benefits. At December 31, 2016, Virginia Power’s unrecognized tax benefits included state refund claims for open tax years through 2011. Management believed settlement of the claims, including interest thereon, within the next twelve months was remote. In June 2017, Virginia Power received and accepted a cash offer to settle the refund claims. As a result of the settlement, Virginia Power decreased its unrecognized tax benefits by $8 million, and recognized a $2 million tax benefit, which impacted its effective tax rate. Also in connection with this settlement, Virginia Power realized interest income of $11 million, which is reflected in other income in the Consolidated Statements of Income.

In 2016, Dominion Energy’s effective tax rate reflects a valuation allowance on a state credit not expected to be utilized by a Dominion Energy subsidiary which files a separate state return.


				119

Combined Notes to Consolidated Financial Statements, Continued

The Companies’ deferred income taxes consist of the following:


	Dominion Energy						Virginia Power						Dominion Energy Gas
At December 31,	2018			2017			2018			2017			2018			2017
(millions)

Deferred income taxes:
Total deferred income tax assets	$	2,748		$	2,686		$	1,054			$ 923			$ 318		$	320
Total deferred income tax liabilities		7,813			7,158			4,020			3,600			1,783			1,774
Total net deferred income tax liabilities	$	5,065		$	4,472		$	2,966			$2,677			$1,465		$	1,454

Total deferred income taxes:
Plant and equipment, primarily depreciation method and basis differences	$	4,933		$	5,056		$	3,367			$2,969			$1,170		$	1,132
Excess deferred income taxes		(993	)		(1,050	)		(678	)		(687	)		(254	)		(244	)
Nuclear decommissioning		815			829			273			260			—			—
Deferred state income taxes		626			834			284			378			175			227
Federal benefit of deferred state income taxes		(132	)		(175	)		(60	)		(79	)		(37	)		(48	)
Deferred fuel, purchased energy and gas costs		60			1			59			(3	)		1			2
Pension benefits		81			141			(132	)		(104	)		431			419
Other postretirement benefits		(5	)		(51	)		55			44			(1	)		(2	)
Loss and credit carryforwards		(1,546	)		(1,536	)		(183	)		(111	)		(7	)		(4	)
Valuation allowances		158			146			5			5			12			3
Partnership basis differences		1,135			473			—			—			26			26
Other		(67	)		(196	)		(24	)		5			(51	)		(57	)
Total net deferred income tax liabilities	$	5,065		$	4,472		$	2,966			$2,677			$1,465		$	1,454
Deferred Investment Tax Credits – Regulated Operations		51			51			51			51			—			—
Total Deferred Taxes and Deferred Investment Tax Credits	$	5,116		$	4,523		$	3,017			$2,728			$1,465		$	1,454

The most significant impact reflected for the 2017 Tax Reform Act is the adjustment of the net accumulated deferred income tax liability for the reduction in the corporate income tax rate to 21%. In addition to amounts recognized in deferred income tax expense, the impacts of the 2017 Tax Reform Act decreased the accumulated deferred income tax liability by $3.1 billion at Dominion Energy, $1.9 billion at Virginia Power and $0.8 billion at Dominion Energy Gas at December 31, 2017. At Dominion Energy, the December 31, 2017 balance sheet reflected the impact of the 2017 Tax Reform Act on our regulatory liabilities which increased our regulatory liabilities by $4.2 billion, and created a corresponding deferred tax asset of $1.1 billion. At Virginia Power, our regulatory liabilities increased $2.6 billion, and created a deferred tax asset of $0.7 billion. At Dominion Energy Gas, our regulatory liabilities increased $1.0 billion, and created a deferred tax asset of $0.2 billion. These adjustments had no impact on 2017 cash flows.

At December 31, 2018, Dominion Energy had the following deductible loss and credit carryforwards:


	Deductible Amount		Deferred Tax Asset		Valuation Allowance			Expiration Period
(millions)
Federal losses		$ 120	$	25		$ —			2034
Federal investment credits		—		1,007		—			2033-2038
Federal production credits		—		150		—			2031-2038
Other federal credits		—		62		—			2031-2038
State losses		1,126		73		(61	)		2019-2038
State minimum tax credits		—		122		—			No expiration
State investment and other credits		—		107		(90	)		2019-2025
Total		$1,246	$	1,546		$(151)

At December 31, 2018, Virginia Power had the following deductible loss and credit carryforwards:


	Deductible Amount		Deferred Tax Asset		Valuation Allowance			Expiration Period
(millions)
Federal losses		$ 1		$ —		$ —			2034
Federal investment credits		—		113		—			2034-2038
Federal production and other credits		—		61		—			2031-2038
State investment credits		—		9		(5	)		2024
Total		$ 1		$183		$(5	)

At December 31, 2018, Dominion Energy Gas had the following deductible loss and credit carryforwards:


	Deductible Amount		Deferred Tax Asset		Valuation Allowance			Expiration Period
(millions)
Other federal credits	$	—	$	1	$	—			2032-2037
State losses		53		5		(5	)		2036-2038
Total	$	53	$	6	$	(5	)

A reconciliation of changes in the Companies’ unrecognized tax benefits follows:


	Dominion Energy									Virginia Power									Dominion Energy Gas
	2018			2017			2016			2018			2017			2016			2018		2017			2016
(millions)
Balance at January 1	$	38		$	64		$	103		$	4		$	13		$	12			$ —	$	7			$29
Increases-prior period positions		10			1			9			—			—			4			—		—			1
Decreases-prior period positions		—			(9	)		(44	)		—			(1	)		(3	)		—		—			(19	)
Increases-current period positions		10			5			6			—			—			—			—		—			—
Settlements with tax authorities		(6	)		(23	)		(8	)		(1	)		(8	)		—			—		(7	)		(4	)
Expiration of statutes of limitations		(8	)		—			(2	)		(1	)		—			—			—		—			—
Balance at December 31	$	44		$	38		$	64		$	2		$	4		$	13			$—	$	—			$ 7

Certain unrecognized tax benefits, or portions thereof, if recognized, would affect the effective tax rate. Changes in these unrecognized tax benefits may result from remeasurement of amounts expected to be realized, settlements with tax authorities


120

and expiration of statutes of limitations. For Dominion Energy and its subsidiaries, these unrecognized tax benefits were $37 million, $31 million and $45 million at December 31, 2018, 2017 and 2016, respectively. For Dominion Energy, the change in these unrecognized tax benefits increased income tax expense by $5 million in 2018 and decreased income tax expense by $9 million and $18 million in 2017 and 2016 respectively. For Virginia Power, these unrecognized tax benefits were $2 million, $3 million, and $9 million at December 31, 2018, 2017 and 2016, respectively. For Virginia Power, the change in these unrecognized tax benefits decreased income tax expense by $2 million and $6 million in 2018 and 2017, respectively, and increased income tax expense by $1 million in 2016. For Dominion Energy Gas, these unrecognized tax benefits were less than $1 million, at December 31, 2018 and 2017, and $5 million at December 31, 2016. For Dominion Energy Gas, the change in these unrecognized tax benefits decreased income tax expense by less than $1 million, $5 million, and $11 million in 2018, 2017, and 2016, respectively.

Dominion Energy participates in the IRS Compliance Assurance Process which provides the opportunity to resolve complex tax matters with the IRS before filing its federal income tax returns, thus achieving certainty for such tax return filing positions agreed to by the IRS. In 2018, Dominion Energy submitted carryback claims for specified liability losses involving prior tax years. These claims will be subject to IRS examination. With the exception of these claims, the IRS has completed its audit of tax years through 2017. The statute of limitations has not yet expired for tax years after 2012. Although Dominion Energy has not received a final letter indicating no changes to its taxable income for tax year 2017, no material adjustments are expected. The IRS examination of tax year 2018 is ongoing.

It is reasonably possible that settlement negotiations and expiration of statutes of limitations could result in a decrease in unrecognized tax benefits in 2019 by up to $18 million for Dominion Energy and less than $1 million for Virginia Power and Dominion Energy Gas. If such changes were to occur, other than revisions of the accrual for interest on tax underpayments and overpayments, earnings could increase by up to $17 million for Dominion Energy and less than $1 million for Virginia Power and Dominion Energy Gas.

Otherwise, with regard to 2018 and prior years, Dominion Energy, Virginia Power and Dominion Energy Gas cannot estimate the range of reasonably possible changes to unrecognized tax benefits that may occur in 2019.

For each of the major states in which Dominion Energy operates, the earliest tax year remaining open for examination is as follows:


State	Earliest Open Tax Year
Pennsylvania(1)		2012
Connecticut		2015
Virginia(2)		2015
West Virginia(1)		2015
New York(1)		2011
Utah		2015

(1)	Considered a major state for Dominion Energy Gas’ operations.

(2)	Considered a major state for Virginia Power’s operations.

The Companies are also obligated to report adjustments resulting from IRS settlements to state tax authorities. In addition, if Dominion Energy utilizes operating losses or tax credits generated in years for which the statute of limitations has expired, such amounts are generally subject to examination.

NOTE 6. FAIR VALUE MEASUREMENTS

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. However, the use of a mid-market pricing convention (the mid-point between bid and ask prices) is permitted. Fair values are based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. This includes not only the credit standing of counterparties involved and the impact of credit enhancements but also the impact of the Companies’ own nonperformance risk on their liabilities. Fair value measurements assume that the transaction occurs in the principal market for the asset or liability (the market with the most volume and activity for the asset or liability from the perspective of the reporting entity), or in the absence of a principal market, the most advantageous market for the asset or liability (the market in which the reporting entity would be able to maximize the amount received or minimize the amount paid). Dominion Energy applies fair value measurements to certain assets and liabilities including commodity, interest rate, and foreign currency derivative instruments, and other investments including those held in nuclear decommissioning, Dominion Energy’s rabbi, and pension and other postretirement benefit plan trusts, in accordance with the requirements discussed above. Virginia Power applies fair value measurements to certain assets and liabilities including commodity and interest rate derivative instruments and other investments including those held in the nuclear decommissioning trust, in accordance with the requirements discussed above. Dominion Energy Gas applies fair value measurements to certain assets and liabilities including commodity, interest rate, and foreign currency derivative instruments and other investments including those held in pension and other postretirement benefit plan trusts, in accordance with the requirements described above. The Companies apply credit adjustments to their derivative fair values in accordance with the requirements described above.

Inputs and Assumptions

Fair value is based on actively-quoted market prices, if available. In the absence of actively-quoted market prices, price information is sought from external sources, including industry publications, and to a lesser extent, broker quotes. When evaluating pricing information provided by Designated Contract Market settlement pricing, other pricing services, or brokers, the Companies consider the ability to transact at the quoted price, i.e. if the quotes are based on an active market or an inactive market and to the extent which pricing models are used, if pricing is not readily available. If pricing information from external sources is not available, or if the Companies believe that observable pricing is not indicative of fair value, judgment is required to develop the estimates of fair value. In those cases the unobservable inputs are developed and substantiated using historical information, avail-


				121

Combined Notes to Consolidated Financial Statements, Continued

able market data, third-party data, and statistical analysis. Periodically, inputs to valuation models are reviewed and revised as needed, based on historical information, updated market data, market liquidity and relationships, and changes in third-party sources.

For options and contracts with option-like characteristics where observable pricing information is not available from external sources, Dominion Energy and Virginia Power generally use a modified Black-Scholes Model that considers time value, the volatility of the underlying commodities and other relevant assumptions when estimating fair value. Dominion Energy and Virginia Power use other option models under special circumstances, including but not limited to Spread Approximation Model and a Swing Option Model. For contracts with unique characteristics, the Companies may estimate fair value using a discounted cash flow approach deemed appropriate in the circumstances and applied consistently from period to period. For individual contracts, the use of different valuation models or assumptions could have a significant effect on the contract’s estimated fair value.

The inputs and assumptions used in measuring fair value include the following:

For commodity derivative contracts:

	•		Forward commodity prices

	•		Transaction prices

	•		Price volatility

	•		Price correlation

	•		Volumes

	•		Commodity location

	•		Interest rates

	•		Credit quality of counterparties and the Companies

	•		Credit enhancements

	•		Time value

For interest rate derivative contracts:

	•		Interest rate curves

	•		Credit quality of counterparties and the Companies

	•		Notional value

	•		Credit enhancements

	•		Time value

For foreign currency derivative contracts:

	•		Foreign currency forward exchange rates

	•		Interest rates

	•		Credit quality of counterparties and the Companies

	•		Notional value

	•		Credit enhancements

	•		Time value

For investments:

	•		Quoted securities prices and indices

	•		Securities trading information including volume and restrictions

	•		Maturity

	•		Interest rates

	•		Credit quality

Levels

The Companies also utilize the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:

•		Level 1—Quoted prices (unadjusted) in active markets for identical assets and liabilities that they have the ability to access at the measurement date. Instruments categorized in Level 1 primarily consist of financial instruments such as certain exchange-traded derivatives, and exchange-listed equities, U.S. and international equity securities, mutual funds and certain Treasury securities held in nuclear decommissioning trust funds for Dominion Energy and Virginia Power, benefit plan trust funds for Dominion Energy and Dominion Energy Gas, and rabbi trust funds for Dominion Energy.

•		Level 2—Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 primarily include commodity forwards and swaps, interest rate swaps, foreign currency swaps and cash and cash equivalents, corporate debt instruments, government securities and other fixed income investments held in nuclear decommissioning trust funds for Dominion Energy and Virginia Power, benefit plan trust funds for Dominion Energy and Dominion Energy Gas and rabbi trust funds for Dominion Energy.

•		Level 3—Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. Instruments categorized in Level 3 for the Companies consist of long-dated commodity derivatives, FTRs, certain natural gas and power options and other modeled commodity derivatives.

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. In these cases, the lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability. Alternative investments, consisting of investments in partnerships, joint ventures and other alternative investments held in nuclear decommissioning and benefit plan trust funds, are generally valued using NAV based on the proportionate share of the fair value as determined by reference to the most recent audited fair value financial statements or fair value statements provided by the investment manager adjusted for any significant events occurring between the investment manager’s and the Companies’ measurement date. Alternative investments recorded at NAV are not classified in the fair value hierarchy.

Transfers out of Level 3 represent assets and liabilities that were previously classified as Level 3 for which the inputs became


122

observable for classification in either Level 1 or Level 2. Because the activity and liquidity of commodity markets vary substantially between regions and time periods, the availability of observable inputs for substantially the full term and value of the Companies’ over-the-counter derivative contracts is subject to change.

Level 3 Valuations

The Companies enter into certain physical and financial forwards, futures, options and swaps, which are considered Level 3 as they have one or more inputs that are not observable and are significant to the valuation. The discounted cash flow method is used to value Level 3 physical and financial forwards and futures

contracts. An option model is used to value Level 3 physical and financial options. The discounted cash flow model for forwards and futures calculates mark-to-market valuations based on forward market prices, original transaction prices, volumes, risk-free rate of return, and credit spreads. The option model calculates mark-to-market valuations using variations of the Black-Scholes option model. The inputs into the models are the forward market prices, implied price volatilities, risk-free rate of return, the option expiration dates, the option strike prices, the original sales prices, and volumes. For Level 3 fair value measurements, certain forward market prices and implied price volatilities are considered unobservable.

The following table presents Dominion Energy’s quantitative information about Level 3 fair value measurements at December 31, 2018. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility.


	Fair Value (millions)		Valuation Techniques		Unobservable Input		Range		Weighted Average(1)

Assets
Physical and financial forwards and futures:
Natural gas(2)		$42		Discounted cash flow		Market price (per Dth)(3)		(2) - 8		(1	)
FTRs		15		Discounted cash flow		Market price (per MWh)(3)		(2) - 7		1
Physical options:
Natural gas		2		Option model		Market price (per Dth)(3)		1 - 8		3
						Price volatility (4)		18% - 73%		30	%
Electricity		11		Option model		Market price (per MWh)(3)		34 - 50		42
						Price volatility (4)		39% - 60%		49	%
Total assets		$70

Liabilities

Financial forwards:
FTRs		$ 6		Discounted cash flow		Market price (per MWh)(3)		(2) - 6		—
Total liabilities		$ 6

(1)	Averages weighted by volume.

(2)	Includes basis.

(3)	Represents market prices beyond defined terms for Levels 1 and 2.

(4)	Represents volatilities unrepresented in published markets.


				123

Combined Notes to Consolidated Financial Statements, Continued

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


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

Nonrecurring Fair Value Measurements

DOMINION ENERGY

See Note 9 for information regarding an impairment charge recognized associated with Dominion Energy’s equity method investment in Fowler Ridge.

ATLANTIC COAST PIPELINE GUARANTEE AGREEMENT

In October 2017, Dominion Energy entered into a guarantee agreement in connection with Atlantic Coast Pipeline’s obligation under a $3.4 billion revolving credit facility. See Note 22 for more information about the guarantee agreement associated with Atlantic Coast Pipeline’s revolving credit facility. Dominion Energy recorded a liability of $30 million, the fair value of the guarantee at inception, associated with the guarantee agreement. The fair value was estimated using a discounted cash flow method and is considered a Level 3 fair value measurement due to the use of a significant unobservable input related to the interest rate differential between the interest rate charged on the guaranteed revolving credit facility and the estimated interest rate that would have been charged had the loan not been guaranteed.

DOMINION ENERGY GAS

In the fourth quarter of 2018, subsequent to the announcement of the sale of Dominion Energy’s interest in Blue Racer, Dominion Energy Gas conducted a review of strategic alternatives of its remaining gathering and processing assets at DGP. Based on an evaluation of DGP’s long-lived assets for recoverability under a probability weighted approach, Dominion Energy Gas determined the assets were impaired. As a result of this evaluation, Dominion Energy Gas recorded a charge of $219 million ($165 million after-tax) in impairment of assets and related charges in its Consolidated Statements of Income to write down DGP’s property, plant and equipment to its estimated fair value of $190 million. The fair value of the property, plant and equipment was estimated using an income approach and market approach. The valuation is considered a Level 3 fair value measurement due to the use of significant judgmental and unobservable inputs, including projected timing and amount of future cash flows and discount rates reflecting risks inherent in the future cash flows and market prices.

Recurring Fair Value Measurements

Fair value measurements are separately disclosed by level within the fair value hierarchy with a separate reconciliation of fair value measurements categorized as Level 3. Fair value disclosures for assets held in Dominion Energy and Dominion Energy Gas’ pension and other postretirement benefit plans are presented in Note 21.


124

DOMINION ENERGY

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


	Level 1		Level 2		Level 3		Total
(millions)

December 31, 2018
Assets
Derivatives:
Commodity	$	—	$	180		$ 70	$	250
Interest rate		—		18		—		18
Foreign currency		—		26		—		26
Investments(1):
Equity securities:
U.S.		3,277		—		—		3,277
Fixed income:
Corporate debt instruments		—		431		—		431
Government securities		455		688		—		1,143
Cash equivalents and other		11		—		—		11
Total assets	$	3,743	$	1,343		$ 70	$	5,156
Liabilities
Derivatives:
Commodity	$	—	$	129		$ 6	$	135
Interest rate		—		142		—		142
Foreign currency		—		2		—		2
Total liabilities	$	—	$	273		$ 6	$	279
December 31, 2017
Assets
Derivatives:
Commodity	$	—	$	101		$157	$	258
Interest rate		—		17		—		17
Foreign currency		—		32		—		32
Investments(1):
Equity securities:
U.S.		3,493		—		—		3,493
Fixed income:
Corporate debt instruments		—		444		—		444
Government securities		307		794		—		1,101
Cash equivalents and other		34		—		—		34
Total assets	$	3,834	$	1,388		$157	$	5,379
Liabilities
Derivatives:
Commodity	$	—	$	190		$ 7	$	197
Interest rate		—		85		—		85
Foreign currency		—		2		—		2
Total liabilities	$	—	$	277		$ 7	$	284

(1)	Includes investments held in the nuclear decommissioning and rabbi trusts. Excludes $220 million and $88 million of assets at December 31, 2018 and 2017, respectively, measured at fair value using NAV (or its equivalent) as a practical expedient which are not required to be categorized in the fair value hierarchy.

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


	2018			2017			2016
(millions)
Balance at January 1,	$	150		$	139		$	95
Total realized and unrealized gains (losses):
Included in earnings:
Operating Revenue		(2	)		3			—
Electric fuel and other energy-related purchases		(15	)		(42	)		(35	)
Purchased gas		—			1			—
Included in other comprehensive income (loss)		1			(2	)		—
Included in regulatory assets/liabilities		(44	)		42			(39	)
Settlements		(27	)		6			38
Purchases		—			—			87
Transfers out of Level 3		1			3			(7	)
Balance at December 31,	$	64		$	150		$	139
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date:
Operating Revenue	$	—		$	2		$	—
Electric fuel and other energy-related purchases		—			—			(1	)


				125

Combined Notes to Consolidated Financial Statements, Continued

VIRGINIA POWER

The following table presents Virginia Power’s quantitative information about Level 3 fair value measurements at December 31, 2018. The range and weighted average are presented in dollars for market price inputs and percentages for price volatility.


	Fair Value (millions)		Valuation Techniques		Unobservable Input		Range		Weighted Average(1)
Assets
Physical and financial forwards and futures:
Natural gas(2)		$38		Discounted cash flow		Market price (per Dth)(3)		(2)-8		(1	)
FTRs		15		Discounted cash flow		Market price (per MWh)(3)		(2)-7		1
Physical options:
Natural gas		2		Option model		Market price (per Dth)(3)		1-8		3
						Price volatility (4)		18%-73%		30	%
Electricity		11		Option model		Market price (per MWh)(3)		34-50		42
						Price volatility (4)		39%-60%		49	%
Total assets		$66
Liabilities
Financial forwards:
FTRs		$ 6		Discounted cash flow		Market price (per MWh)(3)		(2)-6		—
Total liabilities		$ 6

(1)	Averages weighted by volume.

(2)	Includes basis.

(3)	Represents market prices beyond defined terms for Levels 1 and 2.

(4)	Represents volatilities unrepresented in published markets.


126

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


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

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


	Level 1		Level 2		Level 3		Total
(millions)
December 31, 2018
Assets
Derivatives:
Commodity	$	—	$	24	$	66	$	90
Interest rate		—		3		—		3
Investments(1):
Equity securities:
U.S.		1,476		—		—		1,476
Fixed income:
Corporate debt instruments		—		221		—		221
Government securities		164		343		—		507
Total assets	$	1,640	$	591	$	66	$	2,297
Liabilities
Derivatives:
Commodity	$	—	$	9	$	6	$	15
Interest rate		—		88		—		88
Total liabilities	$	—	$	97	$	6	$	103
December 31, 2017
Assets
Derivatives:
Commodity	$	—	$	14	$	152	$	166
Investments(1):
Equity securities:
U.S.		1,566		—		—		1,566
Fixed income:
Corporate debt instruments		—		224		—		224
Government securities		168		326		—		494
Cash equivalents and other		16		—		—		16
Total assets	$	1,750	$	564	$	152	$	2,466
Liabilities
Derivatives:
Commodity	$	—	$	4	$	5	$	9
Interest rate		—		57		—		57
Total liabilities	$	—	$	61	$	5	$	66

(1)	Includes investments held in the nuclear decommissioning trusts. Excludes $160 million and $27 million of assets at December 31, 2018 and 2017, respectively, measured at fair value using NAV (or its equivalent) as a practical expedient which are not required to be categorized in the fair value hierarchy.

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


	2018			2017			2016
(millions)
Balance at January 1,	$	147		$	143		$	93
Total realized and unrealized gains (losses):
Included in earnings:
Electric fuel and other energy-related purchases		(17	)		(43	)		(35	)
Included in regulatory assets/liabilities		(45	)		40			(37	)
Settlements		(25	)		7			35
Purchases		—			—			87
Balance at December 31,	$	60		$	147		$	143

There were no unrealized gains and losses included in earnings in the Level 3 fair value category relating to assets/liabilities still held at the reporting date for the years ended December 31, 2018, 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)
December 31, 2018
Assets
Commodity		$ —		$ 3		$ —		$ 3
Foreign currency		—		26		—		26
Total assets		$ —		$29		$ —		$29
Liabilities
Interest rate		$ —		$17		$ —		$17
Foreign currency		—		2		—		2
Total liabilities		$ —		$19		$ —		$19
December 31, 2017
Assets
Foreign currency		$ —		$32		$ —		$32
Total assets		$ —		$32		$ —		$32
Liabilities
Commodity		$ —		$ 4		$ 2		$ 6
Foreign currency		—		2		—		2
Total liabilities		$ —		$ 6		$ 2		$ 8

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


	2018			2017			2016
(millions)
Balance at January 1,	$	(2	)	$	(2	)	$	6
Total realized and unrealized gains (losses):
Included in other comprehensive income (loss)		1			(3	)		—
Transfers out of Level 3		1			3			(8	)
Balance at December 31,	$	—		$	(2	)	$	(2	)


				127

Combined Notes to Consolidated Financial Statements, Continued

There were no gains and losses included in earnings in the Level 3 fair value category for the years ended December 31, 2018, 2017 and 2016. There were no unrealized gains and losses included in earnings in the Level 3 fair value category relating to assets/liabilities still held at the reporting date for the years ended December 31, 2018, 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, restricted cash and equivalents, customer and other receivables, affiliated receivables, short-term debt, affiliated current borrowings, payables to affiliates and accounts payable are representative of fair value because of the short-term nature of these instruments. For the Companies’ financial instruments that are not recorded at fair value, the carrying amounts and estimated fair values are as follows:


December 31,	2018				2017
	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)	$	29,952		$31,045	$	28,666		$31,233
Credit facility borrowings		73		73		—		—
Junior subordinated notes(3)		3,430		3,358		3,981		4,102
Remarketable subordinated notes(3)		1,386		1,340		1,379		1,446
Virginia Power
Long-term debt, including securities due within one year(3)	$	11,671		$12,400	$	11,346		$12,842
Dominion Energy Gas
Long-term debt, including securities due within one year(4)	$	4,058		$ 4,072	$	3,570		$ 3,719

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

(2)	Carrying amount includes amounts which represent, the unamortized debt issuance costs, discount or premium, and foreign currency remeasurement adjustments. At December 31, 2018, and 2017, includes the valuation of certain fair value hedges associated with Dominion Energy’s fixed rate debt of $(20) million and $(22) 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 7. DERIVATIVES AND HEDGE ACCOUNTING ACTIVITIES

See Note 2 for the Companies’ accounting policies, objectives, and strategies for using derivative instruments. See Note 6 for further information about fair value measurements and associated valuation methods for derivatives.

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

In general, most over-the-counter transactions and all exchange contracts are subject to collateral requirements. Types of collateral for over-the-counter and exchange contracts include cash, letters of credit, and, in some cases, other forms of security, none of which are subject to restrictions. Cash collateral is used in the table below to offset derivative assets and liabilities. Certain accounts receivable and accounts payable recognized on the Companies’ Consolidated Balance Sheets, as well as letters of credit and other forms of security, all of which are not included in the tables below, are subject to offset under master netting or similar arrangements and would reduce the net exposure. See Note 23 for further information regarding credit-related contingent features for the Companies derivative instruments.


128

DOMINION ENERGY

Balance Sheet Presentation

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


			December 31, 2018								December 31, 2017
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Gross Assets Presented in the Consolidated Balance Sheet(1)		Financial Instruments		Cash Collateral Received		Net Amounts		Gross Assets Presented in the Consolidated Balance Sheet(1)		Financial Instruments		Cash Collateral Received		Net Amounts
(millions)
Commodity contracts:
Over-the-counter	$	175	$	12	$	—	$	163	$	174	$	9	$	—	$	165
Exchange		68		68		—		—		80		80		—		—
Interest rate contracts:
Over-the-counter		18		1		—		17		17		8		—		9
Foreign currency contracts:
Over-the-counter		26		2		—		24		32		2		—		30
Total derivatives, subject to a master netting or similar arrangement	$	287	$	83	$	—	$	204	$	303	$	99	$	—	$	204

(1)	Excludes $7 million and $4 million of derivative assets at December 31, 2018 and 2017, respectively, which are not subject to master netting or similar arrangements.


	December 31, 2018								December 31, 2017
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Gross Liabilities Presented in the Consolidated Balance Sheet(1)		Financial Instruments		Cash Collateral Paid		Net Amounts		Gross Liabilities Presented in the Consolidated Balance Sheet(1)		Financial Instruments		Cash Collateral Paid		Net Amounts
(millions)
Commodity contracts:
Over-the-counter	$	19	$	12	$	—	$	7	$	76	$	9	$	6	$	61
Exchange		115		68		47		—		120		80		40		—
Interest rate contracts:
Over-the-counter		142		1		—		141		85		8		—		77
Foreign currency contracts:
Over-the-counter		2		2		—		—		2		2		—		—
Total derivatives, subject to a master netting or similar arrangement	$	278	$	83	$	47	$	148	$	283	$	99	$	46	$	138

(1)	Excludes $1 million of derivative liabilities at December 31, 2018 and 2017, which are not subject to master netting or similar arrangements.


				129

Combined Notes to Consolidated Financial Statements, Continued

Volumes

The following table presents the volume of Dominion Energy’s derivative activity as of December 31, 2018. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions.


	Current		Noncurrent
Natural Gas (bcf):
Fixed price(1)		56		27
Basis		214		557
Electricity (MWh):
Fixed price(1)		11,101,869		1,537,200
FTRs		45,351,415		—
Liquids (Gal)(2)		14,413,200		—
Interest rate(3)	$	2,700,000,000	$	3,915,839,913
Foreign currency(3)(4)	$	—	$	280,000,000

(1)	Includes options.

(2)	Includes NGLs and oil.

(3)	Maturity is determined based on final settlement period.

(4)	Euro equivalent volumes are € 250,000,000.

Ineffectiveness and AOCI

For the years ended December 31, 2018, 2017 and 2016, gains or losses on hedging instruments determined to be ineffective and amounts excluded from the assessment of effectiveness were immaterial. Amounts excluded from the assessment of effectiveness include gains or losses attributable to changes in the time value of options and changes in the differences between spot prices and forward prices.

The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in Dominion Energy’s Consolidated Balance Sheet at December 31, 2018:


	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax			Maximum Term
(millions)
Commodities:
Gas		$ —			$ 1			36 months
Electricity		27			26			24 months
Other		2			2			3 months
Interest rate		(276	)		(29	)		396 months
Foreign currency		12			(2	)		90 months
Total		$(235	)		$ (2	)

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


130

Fair Value and Gains and Losses on Derivative Instruments

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


	Fair Value – Derivatives under Hedge Accounting		Fair Value – Derivatives not under Hedge Accounting		Total Fair Value
(millions)

At December 31, 2018
ASSETS
Current Assets
Commodity		$ 55		$154	$	209
Interest rate		14		—		14
Total current derivative assets(1)		69		154		223
Noncurrent Assets
Commodity		6		35		41
Interest rate		4		—		4
Foreign currency		26		—		26
Total noncurrent derivative assets(2)		36		35		71
Total derivative assets		$105		$189	$	294
LIABILITIES
Current Liabilities
Commodity		$ 17		$112	$	129
Interest rate		26		—		26
Foreign currency		2		—		2
Total current derivative liabilities(3)		45		112		157
Noncurrent Liabilities
Commodity		5		1		6
Interest rate		116		—		116
Total noncurrent derivative liabilities(4)		121		1		122
Total derivative liabilities		$166		$113	$	279
At December 31, 2017
ASSETS
Current Assets
Commodity		$ 5		$158	$	163
Interest rate		6		—		6
Total current derivative assets(1)		11		158		169
Noncurrent Assets
Commodity		—		95		95
Interest rate		11		—		11
Foreign currency		32		—		32
Total noncurrent derivative assets(2)		43		95		138
Total derivative assets		$ 54		$253	$	307
LIABILITIES
Current Liabilities
Commodity		$103		$ 92	$	195
Interest rate		53		—		53
Foreign currency		2		—		2
Total current derivative liabilities(3)		158		92		250
Noncurrent Liabilities
Commodity		1		1		2
Interest rate		32		—		32
Total noncurrent derivative liabilities(4)		33		1		34
Total derivative liabilities		$191		$ 93	$	284

(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)

Year Ended December 31, 2018
Derivative type and location of gains (losses):
Commodity:
Operating revenue					$ (90	)
Electric fuel and other energy-related purchases					14
Total commodity		$ 64			$(76	)		$ —
Interest rate(3)		(18	)		(48	)		39
Foreign currency(4)		(6	)		(13	)		—
Total		$ 40			$(137	)		$39
Year Ended December 31, 2017
Derivative type and location of gains (losses):
Commodity:
Operating revenue					$ 81
Purchased gas					(2	)
Total commodity		$ 1			$ 79			$ —
Interest rate(3)		(8	)		(52	)		(58	)
Foreign currency(4)		18			20			—
Total		$ 11			$ 47			$(58	)
Year Ended December 31, 2016
Derivative type and location of gains (losses):
Commodity:
Operating revenue					$330
Purchased gas					(13	)
Electric fuel and other energy-related purchases					(10	)
Total commodity		$164			$307			$ —
Interest rate(3)		(66	)		(31	)		(26	)
Foreign currency(4)		(6	)		(17	)		—
Total		$ 92			$259			$(26	)

(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.


				131

Combined Notes to Consolidated Financial Statements, Continued


Derivatives not designated as hedging instruments	Amount of Gain (Loss) Recognized in Income on Derivatives(1)
Year Ended December 31,	2018			2017			2016
(millions)
Derivative type and location of gains (losses):
Commodity:
Operating revenue		$(28	)		$ 18			$ 2
Purchased gas		11			(3	)		4
Electric fuel and other energy-related purchases		(9	)		(59	)		(70	)
Other operations & maintenance		—			(1	)		1
Total		$(26	)		$(45	)		$(63	)

(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, if the gross amounts recognized in its Consolidated Balance Sheets were netted with derivative instruments and cash collateral received or paid:


	December 31, 2018								December 31, 2017
			Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Gross Assets Presented in the Consolidated Balance Sheet(1)		Financial Instruments		Cash Collateral Received		Net Amounts		Gross Assets Presented in the Consolidated Balance Sheet(1)		Financial Instruments		Cash Collateral Received		Net Amounts
(millions)

Commodity contracts:
Over-the-counter		$64		$ 6		$—		$58		$155		$ 4		$—		$151
Interest rate contracts:
Over-the-counter		3		—		—		3		—		—		—		—
Total derivatives, subject to a master netting or similar arrangement		$67		$ 6		$—		$61		$155		$ 4		$—		$151

(1)	Excludes $26 million and $11 million of derivative assets at December 31, 2018 and 2017, respectively, which are not subject to master netting or similar arrangements.


	December 31, 2018								December 31, 2017
			Gross Amounts Not Offset in the Consolidated Balance Sheet						Gross Amounts Not Offset in the Consolidated Balance Sheet
	Gross Liabilities Presented in the Consolidated Balance Sheet(1)		Financial Instruments		Cash Collateral Paid		Net Amounts		Gross Liabilities Presented in the Consolidated Balance Sheet(1)		Financial Instruments		Cash Collateral Paid		Net Amounts
(millions)

Commodity contracts:
Over-the-counter		$ 6		$ 6		$—		$—		$ 4		$ 4		$—		$ —
Interest rate contracts:
Over-the-counter		88		—		—		88		57		—		—		57
Total derivatives, subject to a master netting or similar arrangement		$94		$ 6		$—		$88		$61		$ 4		$—		$57

(1)	Excludes $9 million and $5 million of derivative liabilities at December 31, 2018 and 2017, respectively, which are not subject to master netting or similar arrangements.


132

Volumes

The following table presents the volume of Virginia Power’s derivative activity at December 31, 2018. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions.


	Current		Noncurrent
Natural Gas (bcf):
Fixed price(1)		29		8
Basis		136		488
Electricity (MWh):
Fixed price(1)		367,019		—
FTRs		45,351,415		—
Interest rate(2)	$	700,000,000	$	1,200,000,000

(1)	Includes options.

(2)	Maturity is determined based on final settlement period.

Ineffectiveness and AOCI

For the years ended December 31, 2018, 2017 and 2016, gains or losses on hedging instruments determined to be ineffective were immaterial.

The following table presents selected information related to losses on cash flow hedges included in AOCI in Virginia Power’s Consolidated Balance Sheet at December 31, 2018:


	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax			Maximum Term
(millions)
Interest rate	$	(13	)	$	(1	)		396 months
Total	$	(13	)	$	(1	)

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


				133

Combined Notes to Consolidated Financial Statements, Continued

Fair Value and Gains and Losses on Derivative Instruments

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


	Fair Value – Derivatives under Hedge Accounting		Fair Value – Derivatives not under Hedge Accounting		Total Fair Value
(millions)
At December 31, 2018
ASSETS
Current Assets
Commodity		$ —		$ 60		$ 60
Interest rate		3		—		3
Total current derivative assets(1)		3		60		63
Noncurrent Assets
Commodity		—		30		30
Total noncurrent derivative assets(2)		—		30		30
Total derivative assets		$ 3		$ 90		$ 93
LIABILITIES
Current Liabilities
Commodity		$ —		$ 15		$ 15
Interest rate		10		—		10
Total current derivative liabilities(3)		10		15		25
Noncurrent Liabilities
Interest rate		78		—		78
Total noncurrent derivatives liabilities(4)		78		—		78
Total derivative liabilities		$88		$ 15		$103
At December 31, 2017
ASSETS
Current Assets
Commodity		$ —		$ 75		$ 75
Total current derivative assets(1)		—		75		75
Noncurrent Assets
Commodity		—		91		91
Total noncurrent derivative assets(2)		—		91		91
Total derivative assets		$ —		$166		$166
LIABILITIES
Current Liabilities
Commodity		$ —		$ 9		$ 9
Interest rate		44		—		44
Total current derivative liabilities(3)		44		9		53
Noncurrent Liabilities
Interest rate		13		—		13
Total noncurrent derivative liabilities(4)		13		—		13
Total derivative liabilities		$57		$ 9		$ 66

(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 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:


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)
Year Ended December 31, 2018
Derivative type and location of gains (losses):
Interest rate(3)	$	2		$	(1	)	$	39
Total	$	2		$	(1	)	$	39
Year Ended December 31, 2017
Derivative type and location of gains (losses):
Interest rate(3)	$	(8	)	$	(1	)	$	(58	)
Total	$	(8	)	$	(1	)	$	(58	)
Year Ended December 31, 2016
Derivative type and location of gains (losses):
Interest rate(3)	$	(3	)	$	(1	)	$	(26	)
Total	$	(3	)	$	(1	)	$	(26	)

(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.


Derivatives not designated as hedging instruments	Amount of Gain (Loss) Recognized in Income on Derivatives(1)
Year Ended December 31,	2018		2017		2016
(millions)
Derivative type and location of gains (losses):
Commodity(2)		$2		$(57)		$(70)
Total		$2		$(57)		$(70)

(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.


134

DOMINION ENERGY GAS

Balance Sheet Presentation

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


	December 31, 2018								December 31, 2017
	Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Offset in the Consolidated Balance Sheet
	Gross Assets Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Received		Net Amounts		Gross Assets Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Received		Net Amounts
(millions)
Commodity contracts:
Over-the-counter	$	3	$	—	$	—	$	3	$	—	$	—	$	—	$	—
Foreign currency contracts:
Over-the-counter		26		2		—		24		32		2		—		30
Total derivatives, subject to a master netting or similar arrangement	$	29	$	2	$	—	$	27	$	32	$	2	$	—	$	30


	December 31, 2018								December 31, 2017
	Gross Amounts Not Offset in the Consolidated Balance Sheet								Gross Amounts Not Off set in the Consolidated Balance Sheet
	Gross Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts		Gross Liabilities Presented in the Consolidated Balance Sheet		Financial Instruments		Cash Collateral Paid		Net Amounts
(millions)
Commodity contracts
Over-the-counter	$	—	$	—	$	—	$	—	$	6	$	—	$	—	$	6
Interest rate contracts:
Over-the-counter		17		—		—		17		—		—		—		—
Foreign currency contracts:
Over-the-counter		2		2		—		—		2		2		—		—
Total derivatives, subject to a master netting or similar arrangement	$	19	$	2	$	—	$	17	$	8	$	2	$	—	$	6


				135

Combined Notes to Consolidated Financial Statements, Continued

Volumes

The following table presents the volume of Dominion Energy Gas’ derivative activity at December 31, 2018. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting transactions, for which they represent the absolute value of the net volume of their long and short positions.


	Current		Noncurrent
NGLs (Gal)		14,413,200		—
Interest rate(1)	$	300,000,000	$	750,000,000
Foreign currency(1)(2)	$	—	$	280,000,000

(1)	Maturity is determined based on final settlement period.

(2)	Euro equivalent volumes are €250,000,000.

Ineffectiveness and AOCI

For the years ended December 31, 2018, 2017 and 2016, gains or losses on hedging instruments determined to be ineffective were immaterial.

The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in Dominion Energy Gas’ Consolidated Balance Sheet at December 31, 2018:


	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings During the Next 12 Months After-Tax			Maximum Term
(millions)
Commodities:
NGLs		$ 2			$ 2			3 months
Interest rate		(39	)		(4	)		312 months
Foreign currency		12			(2	)		90 months
Total		$(25	)		$(4	)

Fair Value and Gains and Losses on Derivative Instruments

The following table presents 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)

At December 31, 2018
ASSETS
Current Assets
Commodity		$ 3		$—		$ 3
Total current derivative assets(1)		3		—		3
Noncurrent Assets
Foreign currency		26		—		26
Total noncurrent derivative assets(2)		26		—		26
Total derivative assets		$29		$—		$29
LIABILITIES
Current Liabilities
Interest rate		$ 9		$—		$ 9
Foreign currency		2		—		2
Total current derivative liabilities(3)		11		—		11
Noncurrent Liabilities
Interest rate		8		—		8
Total noncurrent derivative liabilities(4)		8		—		8
Total derivative liabilities		$19		$—		$19
At December 31, 2017
ASSETS
Noncurrent Assets
Foreign currency	$32		$—		$32
Total noncurrent derivative assets(2)		32		—		32
Total derivative assets		$32		$—		$32
LIABILITIES
Current Liabilities
Commodity		$ 6		$—		$ 6
Foreign currency		2		—		2
Total current derivative liabilities(3)		8		—		8
Total derivative liabilities		$ 8		$—		$ 8

(1)	Current derivative assets are presented in other current assets in Dominion Energy Gas’ Consolidated Balance Sheets.

(2)	Noncurrent derivative 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.


136

The following tables present 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)
Year Ended December 31, 2018
Derivative type and location of gains (losses):
Commodity:
Operating revenue					$ (8	)
Total commodity		$ 1			$ (8	)
Interest rate(2)		(18	)		(6	)
Foreign currency(3)		(6	)		(13	)
Total		$(23	)		$(27	)
Year Ended December 31, 2017
Derivative type and location of gains (losses):
Commodity:
Operating revenue					$ (8	)
Total commodity		$(10	)		$ (8	)
Interest rate(2)		—			(5	)
Foreign currency(3)		18			20
Total		$ 8			$ 7
Year Ended December 31, 2016
Derivative type and location of gains (losses):
Commodity:
Operating revenue					$ 4
Total commodity		$(12	)		$ 4
Interest rate(2)		(8	)		(2	)
Foreign currency(3)		(6	)		(17	)
Total		$(26	)		$(15	)

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

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

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


Derivatives not designated as hedging instruments	Amount of Gain (Loss) Recognized in Income on Derivatives
Year Ended December 31,	2018			2017		2016
(millions)
Derivative type and location of gains (losses):
Commodity
Operating revenue		$(11	)		$—		$1
Total		$(11	)		$—		$1

NOTE 8. EARNINGS PER SHARE

The following table presents the calculation of Dominion Energy’s basic and diluted EPS:


	2018		2017		2016
(millions, except EPS)
Net Income Attributable to Dominion Energy	$	2,447	$	2,999	$	2,123
Average shares of common stock outstanding – Basic		654.2		636.0		616.4
Net effect of dilutive securities(1)		0.7		—		0.7
Average shares of common stock outstanding – Diluted		654.9		636.0		617.1
Earnings Per Common Share – Basic	$	3.74	$	4.72	$	3.44
Earnings Per Common Share – Diluted	$	3.74	$	4.72	$	3.44

(1)	Dilutive securities for 2018 consist primarily of forward sale agreements, effective April 2018 to December 2018. Dilutive securities for 2016 consist primarily of the 2013 Equity Units. See Notes 17 and 19 for more information.

The 2014 Equity Units were excluded from the calculation of diluted EPS for the year ended December 31, 2016 as the dilutive stock price threshold was not met. The 2016 Equity Units were excluded from the calculation of diluted EPS for the years ended December 31, 2018, 2017 and 2016, as the dilutive stock price threshold was not met. See Note 17 for more information. The Dominion Energy Midstream convertible preferred units were potentially dilutive securities but had no effect on the calculation of diluted EPS for the years ended December 31, 2018, 2017 and 2016. See Note 19 for more information.


				137

Combined Notes to Consolidated Financial Statements, Continued

NOTE 9. INVESTMENTS

DOMINION ENERGY

Equity and Debt Securities

RABBI TRUST SECURITIES

Equity and debt securities and cash equivalents in Dominion Energy’s rabbi trusts and classified as trading totaled $111 million and $112 million at December 31, 2018 and 2017, respectively.

DECOMMISSIONING TRUST SECURITIES

Dominion Energy holds equity and debt securities, 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		Total Unrealized Losses			Fair Value
(millions)
December 31, 2018
Equity securities:(1)
U.S.		$1,741		$1,640		$(51)			$3,330
Fixed income securities:(2)
Corporate debt instruments		435		5		(9)			431
Government securities		1,092		17		(12)			1,097
Common/collective trust funds		76		—		—			76
Cash equivalents and other(3)		4		—		—			4
Total		$3,348		$1,662		$(72)	(4)		$4,938
December 31, 2017
Equity securities:(2)
U.S.		$1,569		$1,857		$ —			$3,426
Fixed income securities:(2)
Corporate debt instruments		430		15		(1)			444
Government securities		1,039		27		(5)			1,061
Common/collective trust funds		60		—		—			60
Cost method investments		68		—		—			68
Cash equivalents and other(3)		34		—		—			34
Total		$3,200		$1,899		$ (6)	(4)		$5,093

(1)	Effective January 2018, unrealized gains and losses on equity securities, including those previously classified as cost method investments, are included in other income and the nuclear decommissioning trust regulatory liability as discussed in Note 2.

(2)	Unrealized gains and losses on equity securities (for 2017) and fixed income securities are included in AOCI and the nuclear decommissioning trust regulatory liability as discussed in Note 2.

(3)	Includes pending sales of securities of $5 million at December 31, 2017.

(4)	The fair value of securities in an unrealized loss position was $833 million and $565 million at December 31, 2018 and 2017, respectively.

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


	Twelve Months Ended December 31, 2018
(millions)
Net losses recognized during the period	$	(245	)
Less: Net gains recognized during the period on securities sold during the period		(58	)
Unrealized losses recognized during the period on securities still held at December 31, 2018(1)	$	(303	)

(1)	Included in other income and the nuclear decommissioning trust regulatory liability as discussed in Note 2.

The fair value of Dominion Energy’s debt securities with readily determinable fair values held in nuclear decommissioning trust funds at December 31, 2018 by contractual maturity is as follows:


	Amount
(millions)

Due in one year or less	$	167
Due after one year through five years		389
Due after five years through ten years		376
Due after ten years		672
Total	$	1,604


138

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


Year Ended December 31,	2018		2017		2016
(millions)

Proceeds from sales	$	1,804	$	1,831	$	1,422
Realized gains(1)		140		166		128
Realized losses(1)		91		71		55

(1)	Includes realized gains and losses recorded to the nuclear decommissioning trust regulatory liability as discussed in Note 2.

Dominion Energy recorded other-than-temporary impairment losses on investments held in nuclear decommissioning trust funds as follows:


Year Ended December 31,	2018			2017			2016
(millions)

Total other-than-temporary impairment losses(1)	$	30		$	44		$	51
Losses recorded to the nuclear decommissioning trust regulatory liability		—			(16	)		(16	)
Losses recognized in other comprehensive income (before taxes)		(30	)		(5	)		(12	)
Net impairment losses recognized in earnings	$	—		$	23		$	23

(1)	Amounts include other-than-temporary impairment losses for debt securities of $5 million and $13 million at December 31, 2017 and 2016, respectively.

VIRGINIA POWER

Virginia Power holds equity and debt securities, 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		Total Unrealized Losses			Fair Value
(millions)
December 31, 2018
Equity securities:(1)
U.S.		$858		$751		$(24	)		$1,585
Fixed income securities:(2)
Corporate debt instruments		224		2		(5	)		221
Government securities		504		7		(5	)		506
Common/collective trust funds		51		—		—			51
Cash equivalents and other(3)		6		—		—			6
Total		$1,643		$760		$(34)	(4)		$2,369
December 31, 2017
Equity securities:(2)
U.S.		$ 734		$831		$—			$1,565
Fixed income securities:(2)
Corporate debt instruments		216		8		—			224
Government securities		482		13		(2	)		493
Common/collective trust funds		27		—		—			27
Cost method investments		68		—		—			68
Cash equivalents and other(3)		22		—		—			22
Total		$1,549		$852		$(2	)(4)		$2,399

(1)	Effective January 2018, unrealized gains and losses on equity securities, including those previously classified as cost method investments, are included in other income and the nuclear decommissioning trust regulatory liability as discussed in Note 2.

(2)	Unrealized gains and losses on equity securities (for 2017) and fixed income securities are included in AOCI and the nuclear decommissioning trust regulatory liability as discussed in Note 2.

(3)	Includes pending sales of securities of $6 million at both December 31, 2018 and 2017.

(4)	The fair value of securities in an unrealized loss position was $404 million and $234 million at December 31, 2018 and 2017, respectively.

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


	Twelve Months Ended December 31, 2018
(millions)
Net losses recognized during the period	$	(105	)
Less: Net gains recognized during the period on securities sold during the period		(32	)
Unrealized losses recognized during the period on securities still held at December 31, 2018(1)	$	(137	)

(1)	Included in other income and the nuclear decommissioning trust regulatory liability as discussed in Note 2.

The fair value of Virginia Power’s debt securities with readily determinable fair values held in nuclear decommissioning trust funds at December 31, 2018, by contractual maturity is as follows:


	Amount
(millions)
Due in one year or less	$	54
Due after one year through five years		156
Due after five years through ten years		210
Due after ten years		358
Total	$	778

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


Year Ended December 31,	2018		2017		2016
(millions)

Proceeds from sales	$	887	$	849	$	733
Realized gains(1)		60		75		63
Realized losses(1)		27		30		27

(1)	Includes realized gains and losses recorded to the nuclear decommissioning trust regulatory liability as discussed in Note 2.


				139

Combined Notes to Consolidated Financial Statements, Continued

Virginia Power recorded other-than-temporary impairment losses on investments held in nuclear decommissioning trust funds as follows:


Year Ended December 31,	2018			2017			2016
(millions)

Total other-than-temporary impairment losses(1)	$	15		$	20		$	26
Losses recorded to the nuclear decommissioning trust regulatory liability		—			(16	)		(16	)
Losses recognized in other comprehensive income (before taxes)		(15	)		(2	)		(7	)
Net impairment losses recognized in earnings	$	—		$	2		$	3

(1)	Amounts include other-than-temporary impairment losses for debt securities of $2 million and $8 million at December 31, 2017 and 2016 , respectively.

Equity Method Investments

DOMINION ENERGY AND DOMINION ENERGY GAS

Investments that Dominion Energy and Dominion Energy Gas account for under the equity method of accounting are as follows:


Company	Ownership%			Investment Balance				Description
As of December 31,				2018		2017
(millions)
Dominion Energy
Atlantic Coast Pipeline		48	%	$	820	$	382		Gas transmission system
Blue Racer		50	%		—		691		Midstream gas and related services
Iroquois		50	%(1)		302		311		Gas transmission system
Fowler Ridge		50	%		82		81		Wind-powered merchant generation facility
Other(2)		various			74		79
Total				$	1,278	$	1,544
Dominion Energy Gas
Iroquois		24.07	%	$	91	$	95		Gas transmission system
Total				$	91	$	95

(1)	Comprised of Dominion Energy Midstream’s interest of 25.93% and Dominion Energy Gas’ interest of 24.07%. See Note 15 for more information.

(2)	Liability of less than $1 million and $17 million associated with NedPower recorded to other deferred credits and other liabilities, on the Consolidated Balance Sheets as of December 31, 2018 and 2017, respectively. See additional discussion of NedPower below.

Dominion Energy’s equity earnings on its investments totaled $197 million, $14 million and $111 million in 2018, 2017 and 2016, respectively, included in other income in Dominion Energy’s Consolidated Statements of Income. Dominion Energy received distributions from these investments of $209 million, $419 million and $104 million in 2018, 2017 and 2016, respectively. As of December 31, 2018 and 2017, the carrying amount of Dominion Energy’s investments exceeded its share of underlying equity in net assets by $161 million and $249 million, respectively. At December 31, 2018 these differences are comprised of $146 million of equity method goodwill that is not being amortized and $15 million related to basis differences from Dominion Energy’s investments in wind projects, which are being amortized over the useful lives of the underlying assets, and in Atlantic Coast Pipeline, which is being amortized over the term of its credit facility. At December 31, 2017 these differences are

comprised of $176 million of equity method goodwill and $73 million related to basis differences from Dominion Energy’s investments in Blue Racer and wind projects, and in Atlantic Coast Pipeline.

Dominion Energy Gas’ equity earnings on its investment totaled $24 million in 2018 and $21 million in 2017 and 2016. Dominion Energy Gas received distributions from its investment of $28 million, $24 million and $22 million in 2018, 2017 and 2016, respectively. As of December 31, 2018 and 2017, the carrying amount of Dominion Energy Gas’ investment exceeded its share of underlying equity in net assets by $8 million. The difference reflects equity method goodwill and is not being amortized. In May 2016, Dominion Energy Gas sold 0.65% of the noncontrolling partnership interest in Iroquois to TransCanada for approximately $7 million, which resulted in a $5 million ($3 million after-tax) gain, included in other income in Dominion Energy Gas’ Consolidated Statements of Income.

DOMINION ENERGY

ATLANTIC COAST PIPELINE

In September 2014, Dominion Energy, along with Duke and Southern Company Gas, announced the formation of Atlantic Coast Pipeline. The Atlantic Coast Pipeline partnership agreement includes provisions to allow Dominion Energy an option to purchase additional ownership interest in Atlantic Coast Pipeline to maintain a leading ownership percentage. In October 2016, Dominion Energy purchased an additional 3% membership interest in Atlantic Coast Pipeline from Duke for $14 million. As of December 31, 2018, the members hold the following membership interests: Dominion Energy, 48%; Duke, 47%; and Southern Company Gas, 5%.

Atlantic Coast Pipeline is focused on constructing an approximately 600-mile natural gas pipeline running from West Virginia through Virginia to North Carolina. Subsidiaries and affiliates of all three members plan to be customers of the pipeline under 20-year contracts. Atlantic Coast Pipeline is considered an equity method investment as Dominion Energy has the ability to exercise significant influence, but not control, over the investee. See Note 15 for more information.

DETI provides services to Atlantic Coast Pipeline which totaled $203 million, $129 million and $95 million in 2018, 2017 and 2016, respectively, included in operating revenue in Dominion Energy and Dominion Energy Gas’ Consolidated Statements of Income. Amounts receivable related to these services were $13 million and $12 million at December 31, 2018 and 2017, respectively, composed entirely of accrued unbilled revenue, included in other receivables in Dominion Energy and Dominion Energy Gas’ Consolidated Balance Sheets.

In October 2017, Dominion Energy entered into a guarantee agreement to support a portion of Atlantic Coast Pipeline’s obligation under its credit facility. See Note 22 for more information.

Dominion Energy contributed $414 million, $310 million and $184 million during 2018, 2017 and 2016, respectively, to Atlantic Coast Pipeline.

Dominion Energy received distributions of $36 million and $270 million during 2018 and 2017, respectively, from Atlantic Coast Pipeline. No distributions were received in 2016.


140

During the third and fourth quarters of 2018, a FERC stop work order together with delays in obtaining permits necessary for construction along with construction delays due to judicial actions impacted the cost and schedule for the project. As a result project cost estimates have increased from between $6.0 billion to $6.5 billion to between $7.0 billion to $7.5 billion, excluding financing costs. Atlantic Coast Pipeline expects to achieve a late 2020 in-service date for at least key segments of the project, while the remainder may extend into early 2021. Alternatively, if it takes longer to resolve the judicial issues, such as through appeal to the Supreme Court of the U.S., full in-service could extend to the end of 2021 with total project cost estimated to increase an additional $250 million, resulting in total project cost estimates of $7.25 billion to $7.75 billion excluding financing costs. Abnormal weather, work delays (including due to judicial or regulatory action) and other conditions may result in further cost or schedule modifications in the future, which could result in a material impact to Dominion Energy’s cash flows, financial position and/or results of operations.

BLUE RACER

In December 2012, Dominion Energy formed a joint venture with Caiman to provide midstream services to natural gas producers operating in the Utica Shale region in Ohio and portions of Pennsylvania. Blue Racer was an equal partnership between Dominion Energy and Caiman, with Dominion Energy contributing midstream assets and Caiman contributing private equity capital.

In December 2016, Dominion Energy Gas repurchased a portion of the Western System from Blue Racer for $10 million.

In December 2018, Dominion Energy sold its 50% limited partnership interest in Blue Racer for up-front cash consideration of $1.05 billion and additional consideration of $150 million, subject to increase for interest costs effective March 2019, payable upon the purchaser’s availability of cash. The additional consideration was recorded at a fair value of $150 million on the date of sale following a discounted cash flow model and is included within other receivables in the Consolidated Balance Sheets at December 31, 2018. The valuation is considered a Level 3 fair value measurement due to the use of judgment and unobservable inputs, including projected timing and amount of future cash flows and a discount rate reflecting risks inherent in the future cash flows. As a result of the sale, Dominion Energy recognized a gain of $546 million ($390 million after-tax), included in other income in its Consolidated Statements of Income. Also, the purchaser agreed to pay additional consideration contingent upon the achievement of certain financial performance milestones of Blue Racer from 2019 through 2021. Pursuant to the purchase agreement, the aggregate will not exceed $300 million, which represents a gain contingency, and, as a result, Dominion Energy will not recognize any additional gain unless such consideration is realizable.

FOWLER RIDGE & NEDPOWER

In the fourth quarter of 2017, Dominion Energy recorded a charge of $126 million ($76 million after-tax) in other income in

its Consolidated Statements of Income reflecting its share of a long-lived asset impairment of property, plant and equipment recorded by NedPower, which resulted in losses in excess of Dominion Energy’s investment balance. Dominion Energy recorded the excess losses due to its commitment to provide further financial support for NedPower, resulting in a liability of $17 million at December 31, 2017, recorded to other deferred credits and other liabilities, on the Consolidated Balance Sheets.

As a result of the impairment recorded by NedPower, Dominion Energy evaluated its equity method investment in Fowler Ridge, a similar wind-powered merchant generation facility, determined its fair value was other than-temporarily impaired and recorded an impairment charge of $32 million ($20 million after-tax) in other income in its Consolidated Statements of Income. The fair value of $81 million was estimated using a discounted cash flow method and is considered a Level 3 fair value measurement due to the use of significant unobservable inputs related to the timing and amount of future equity distributions based on the investee’s future wind generation and operating costs.

OTHER – CATALYST OLD RIVER HYDROELECTRIC LIMITED PARTNERSHIP

In September 2018, Dominion Energy completed the sale of its 25% limited partnership interest in Catalyst Old River Hydroelectric Limited Partnership and received proceeds of $91 million. The sale resulted in a gain of $87 million ($63 million after-tax), which is included in other income in Dominion Energy’s Consolidated Statement of Income.

NOTE 10. PROPERTY, PLANT AND EQUIPMENT

Major classes of property, plant and equipment and their respective balances for the Companies are as follows:


At December 31,	2018		2017
(millions)

Dominion Energy
Utility:
Generation	$	19,250	$	17,602
Transmission		16,669		15,335
Distribution		18,549		17,408
Storage		2,905		2,887
Nuclear fuel		1,626		1,599
Gas gathering and processing		307		219
Oil and gas		1,763		1,720
General and other		1,476		1,514
Plant under construction		2,385		7,765
Total utility		64,930		66,049
Nonutility:
Merchant generation-nuclear		1,550		1,452
Merchant generation-other		3,802		4,992
Nuclear fuel		1,025		968
Gas gathering and processing		185		630
LNG facility		3,977		—
Other-including plant under construction		1,109		732
Total nonutility		11,648		8,774
Total property, plant and equipment	$	76,578	$	74,823


				141

Combined Notes to Consolidated Financial Statements, Continued


At December 31,	2018		2017
(millions)

Virginia Power
Utility:
Generation	$	19,250	$	17,602
Transmission		9,392		8,332
Distribution		11,785		11,151
Nuclear fuel		1,626		1,599
General and other		821		794
Plant under construction		1,639		2,840
Total utility		44,513		42,318
Nonutility-other		11		11
Total property, plant and equipment	$	44,524	$	42,329

Dominion Energy Gas
Utility:
Transmission	$	4,758	$	4,732
Distribution		3,527		3,267
Storage		1,691		1,688
Gas gathering and processing		210		202
General and other		233		216
Plant under construction		494		293
Total utility		10,913		10,398
Nonutility:
Gas gathering and processing		185		630
Other-including plant under construction		140		145
Total nonutility		325		775
Total property, plant and equipment	$	11,238	$	11,173

Jointly-Owned Power Stations

Dominion Energy and Virginia Power’s proportionate share of jointly-owned power stations at December 31, 2018 is as follows:


	Bath County Pumped Storage Station(1)			North Anna Units 1 and 2(1)			Clover Power Station(1)			Millstone Unit 3(2)
(millions, except percentages)
Ownership interest		60	%		88.4	%		50	%		93.5	%
Plant in service		1,058			2,560			590			1,231
Accumulated depreciation		(639	)		(1,305	)		(240	)		(400	)
Nuclear fuel		—			721			—			571
Accumulated amortization of nuclear fuel		—			(608	)		—			(423	)
Plant under construction		6			103			9			66

(1)	Units jointly owned by Virginia Power.

(2)	Unit jointly owned by Dominion Energy.

The co-owners are obligated to pay their share of all future construction expenditures and operating costs of the jointly-owned facilities in the same proportion as their respective ownership interest. Dominion Energy and Virginia Power report their share of operating costs in the appropriate operating expense (electric fuel and other energy-related purchases, other operations and maintenance, depreciation, depletion and amortization and other taxes, etc.) in the Consolidated Statements of Income.

Sale of Certain Retail Energy Marketing Assets

In October 2017, Dominion Energy entered into an agreement to sell certain assets associated with its nonregulated retail energy

marketing operations for total consideration of $143 million, subject to customary approvals and certain adjustments. In December 2017, the first phase of the agreement closed for $79 million, which resulted in the recognition of a $78 million ($48 million after-tax) benefit, included in gains on sales of assets in Dominion Energy’s Consolidated Statements of Income. In October 2018, the second phase of the agreement closed for $63 million, which resulted in the recognition of a $65 million ($49 million after-tax) benefit included in gains on sales of assets in Dominion Energy’s Consolidated Statements of Income. Pursuant to the agreement, Dominion Energy entered into a commission agreement with the buyer upon the first closing in December 2017 under which the buyer will pay a commission in connection with the right to use Dominion Energy’s brand in marketing materials and other services over a ten-year term.

Sale of Certain Merchant Generation Facilities

In December 2018, Dominion Energy completed the sale of Fairless and Manchester for total consideration of $1.2 billion, subject to customary closing adjustments. Dominion Energy recognized a gain of $210 million ($198 million after-tax) included in gains on sales of assets in Dominion Energy’s Consolidated Statements of Income. The after-tax gain reflects Dominion Energy’s assessment and more-likely-than-not conclusion that the utilization of state tax incentives will reduce the income tax expense associated with the sale of these facilities.

Acquisition of Solar Projects

In September 2017, Virginia Power entered into agreements to acquire two solar development projects in North Carolina. The first acquisition closed in October 2018. The facility commenced commercial operations in December 2018 at a cost of $140 million, including the initial acquisition cost. The second acquisition is expected to close prior to the project commencing commercial operations, which is expected by the end of 2019, and cost approximately $140 million once constructed, including the initial acquisition cost. The projects are expected to generate approximately 155 MW combined. Virginia Power anticipates claiming federal investment tax credits on these solar projects.

In February 2019, Virginia Power completed the acquisition of a solar development project in Virginia. The project is expected to commence commercial operations in the first quarter 2019, and cost approximately $37 million once constructed, including the initial acquisition cost. The project is expected to generate approximately 20 MW. Virginia Power anticipates claiming federal investment tax credits on this solar project.

In August 2018, Virginia Power entered into agreements to acquire two solar development projects in North Carolina and Virginia. The first acquisition is expected to close prior to the project commencing commercial operations, which is expected by the end of 2019, and cost approximately $120 million once constructed, including the initial acquisition cost. The second acquisition is expected to close prior to the project commencing commercial operations, which is expected by the end of 2020, and cost approximately $130 million, including the initial acquisition cost. The projects are expected to generate approximately 155 MW combined. Virginia Power anticipates claiming federal investment tax credits on these solar projects.


142

Assignment of Tower Rental Portfolio

Virginia Power rents space on certain of its electric transmission towers to various wireless carriers for communications antennas and other equipment. In March 2017, Virginia Power sold its rental portfolio to Vertical Bridge Towers II, LLC for $91 million in cash. The proceeds are subject to Virginia Power’s FERC-regulated tariff, under which it is required to return half of the proceeds to customers. Virginia Power recorded $6 million in operating revenue and $11 million in other income during 2018 and 2017, respectively, with $29 million remaining to be recognized ratably through 2023.

Assignments of Shale Development Rights

In December 2013, Dominion Energy Gas closed on agreements with two natural gas producers to convey over time approximately 100,000 acres of Marcellus Shale development rights underneath several of its natural gas storage fields. The agreements provided for payments to Dominion Energy Gas, subject to customary adjustments, of approximately $200 million over a period of nine years, and an overriding royalty interest in gas produced from the acreage. In 2013, Dominion Energy Gas received approximately $100 million in cash proceeds. In 2014, Dominion Energy Gas received $16 million in additional cash proceeds resulting from post-closing adjustments. In March 2015, Dominion Energy Gas and one of the natural gas producers closed on an amendment to the agreement, which included the immediate conveyance of approximately 9,000 acres of Marcellus Shale development rights and a two-year extension of the term of the original agreement. The conveyance of development rights resulted in the recognition of $43 million ($27 million after-tax) of previously deferred revenue to operations and maintenance expense in Dominion Energy Gas’ Consolidated Statements of Income. In April 2016, Dominion Energy Gas and the natural gas producer closed on an amendment to the agreement, which included the immediate conveyance of a 32% partial interest in the remaining approximately 70,000 acres. This conveyance resulted in the recognition of the remaining $35 million ($21 million after-tax) of previously deferred revenue to gains on sales of assets in Dominion Energy Gas’ Consolidated Statements of Income. In August 2017, Dominion Energy Gas and the natural gas producer signed an amendment to the agreement, which included the finalization of contractual matters on previous conveyances, the conveyance of Dominion Energy Gas’ remaining 68% interest in approximately 70,000 acres and the elimination of Dominion Energy Gas’ overriding royalty interest in gas produced from all acreage. Dominion Energy Gas received total consideration of $130 million, with $65 million received in 2017 and $65 million received in September 2018 in connection with the final conveyance. As a result of this amendment, in 2017, Dominion Energy Gas recognized a $56 million ($33 million after-tax) gain included in gains on sales of assets in Dominion Energy Gas’ Consolidated Statements of Income associated with the finalization of the contractual matters on previous conveyances, a $9 million ($5 million after-tax) gain included in gains on sales of assets in Dominion Energy Gas’ Consolidated Statements of Income associated with the elimination of its overriding royalty interest and in 2018, a

$65 million ($47 million after-tax) gain included in gains on sales of assets in Dominion Energy Gas’ Consolidated Statements of Income associated with the final conveyance of acreage.

In November 2014, Dominion Energy Gas closed an agreement with a natural gas producer to convey over time approximately 24,000 acres of Marcellus Shale development rights underneath one of its natural gas storage fields. The agreement provided for payments to Dominion Energy Gas, subject to customary adjustments, of approximately $120 million over a period of four years, and an overriding royalty interest in gas produced from the acreage. In November 2014, Dominion Energy Gas closed on the agreement and received proceeds of $60 million associated with an initial conveyance of approximately 12,000 acres. In connection with that agreement, in 2016, Dominion Energy Gas conveyed a 50% interest in approximately 4,000 acres of Marcellus Shale development rights and received proceeds of $10 million and an overriding royalty interest in gas produced from the acreage. These transactions resulted in a $10 million ($6 million after-tax) gain. In July 2017, in connection with the existing agreement, Dominion Energy Gas conveyed an additional 50% interest in approximately 2,000 acres of Marcellus Shale development rights and received proceeds of $5 million and an overriding royalty interest in gas produced from the acreage. This transaction resulted in a $5 million ($3 million after-tax) gain. The gains are included in gains on sales of assets in Dominion Energy Gas’ Consolidated Statements of Income. In January 2018, Dominion Energy Gas and the natural gas producer closed on an amendment to the agreement, which included the conveyance of Dominion Energy Gas’ remaining 50% interest in approximately 18,000 acres and the elimination of Dominion Energy Gas’ overriding royalty interest in gas produced from all acreage. Dominion Energy Gas received proceeds of $28 million, resulting in an approximately $28 million ($20 million after-tax) gain recorded in gains on sales of assets in Dominion Energy Gas’ Consolidated Statements of Income.

In March 2018, Dominion Energy Gas closed an agreement with a natural gas producer to convey approximately 11,000 acres of Utica and Point Pleasant Shale development rights underneath one of its natural gas storage fields. The agreement provided for a payment to Dominion Energy Gas, subject to customary adjustments, of $16 million. In March 2018, Dominion Energy Gas received cash proceeds of $16 million associated with the conveyance of the acreage, resulting in a $16 million ($12 million after-tax) gain recorded in gains on sales of assets in Dominion Energy Gas’ Consolidated Statements of Income.

In June 2018, Dominion Energy Gas closed an amendment to an agreement with a natural gas producer for the elimination of Dominion Energy Gas’ overriding royalty interest in gas produced from approximately 9,000 acres of Marcellus Shale development rights underneath one of its natural gas storage fields previously conveyed in December 2013. In June 2018, Dominion Energy Gas received proceeds of $6 million associated with the transaction, resulting in a $6 million ($4 million after-tax) gain recorded in gains on sales of assets in Dominion Energy Gas’ Consolidated Statements of Income.


				143

Combined Notes to Consolidated Financial Statements, Continued

NOTE 11. GOODWILL AND INTANGIBLE ASSETS

Goodwill

The changes in Dominion Energy and Dominion Energy Gas’ carrying amount and segment allocation of goodwill are presented below:


	Power Generation		Gas Infrastructure			Power Delivery		Corporate and Other(1)		Total
(millions)

Dominion Energy
Balance at December 31, 2016(2)	$	1,422	$	4,051		$	926	$	—	$	6,399
Dominion Energy Questar Combination		—		6(3	)		—		—		6
Balance at December 31, 2017(2)	$	1,422	$	4,057		$	926	$	—	$	6,405
Purchase Accounting Adjustment		—		5			—		—		5
Balance at December 31, 2018(2)	$	1,422	$	4,062		$	926	$	—	$	6,410

Dominion Energy Gas
Balance at December 31, 2016(2)	$	—	$	542		$	—	$	—	$	542
No events affecting goodwill		—		—			—		—		—
Balance at December 31, 2017(2)	$	—	$	542		$	—	$	—	$	542
Purchase Accounting Adjustment		—		5			—		—		5
Balance at December 31, 2018(2)	$	—	$	547		$	—	$	—	$	547

(1)	Goodwill recorded at the Corporate and Other segment is allocated to the primary operating segments for goodwill impairment testing purposes.

(2)	Goodwill amounts do not contain any accumulated impairment losses.

(3)	See Note 3.

Other Intangible Assets

The Companies’ other intangible assets are subject to amortization over their estimated useful lives. Dominion Energy’s amortization expense for intangible assets was $82 million, $80 million and $73 million for 2018, 2017 and 2016, respectively. In 2018, Dominion Energy acquired $127 million of intangible assets, primarily representing software and right-of-use assets, with an estimated weighted-average amortization period of approximately 15 years. Amortization expense for Virginia Power’s intangible assets was $31 million for both 2018 and 2017 and $29 million for 2016. In 2018, Virginia Power acquired $49 million of intangible assets, primarily representing software, with an estimated weighted-average amortization period of 11 years. Dominion Energy Gas’ amortization expense for intangible assets was $14 million for both 2018 and 2017 and $6 million for 2016. In 2018, Dominion Energy Gas acquired $14 million of intangible assets, primarily representing software and right-of-use

assets, with an estimated weighted-average amortization period of approximately 10 years. The components of intangible assets are as follows:


	2018				2017
At December 31,	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
(millions)

Dominion Energy
Software, licenses and other	$	1,033	$	363	$	1,043	$	358

Virginia Power
Software, licenses and other	$	384	$	134	$	347	$	114

Dominion Energy Gas
Software, licenses and other	$	174	$	65	$	165	$	56

Annual amortization expense for these intangible assets is estimated to be as follows:


	2019		2020		2021		2022		2023
(millions)
Dominion Energy	$	67	$	56	$	44	$	34	$	23

Virginia Power	$	29	$	23	$	16	$	12	$	6

Dominion Energy Gas	$	14	$	13	$	12	$	8	$	7


144

NOTE 12. REGULATORY ASSETS AND LIABILITIES

Regulatory assets and liabilities include the following:


At December 31,	2018		2017
(millions)

Dominion Energy
Regulatory assets:
Deferred cost of fuel used in electric generation(1)	$	174	$	23
Deferred rate adjustment clause costs(2)		96		70
Deferred nuclear refueling outage costs(3)		69		54
Unrecovered gas costs(4)		14		38
Other		143		109
Regulatory assets-current		496		294
Unrecognized pension and other postretirement benefit costs(5)		1,497		1,336
Deferred rate adjustment clause costs(2)		329		401
Utility reform legislation(6)		204		147
PJM transmission rates(7)		192		222
Derivatives(8)		184		223
Deferred cost of fuel used in electric generation(1)		83		—
Other		187		151
Regulatory assets-noncurrent		2,676		2,480
Total regulatory assets	$	3,172	$	2,774
Regulatory liabilities:
Provision for future cost of removal and AROs(9)	$	117	$	101
Cost-of-service impact of 2017 Tax Reform Act(10)		104		—
Reserve for rate credits to electric utility customers(11)		71		—
Other		64		92
Regulatory liabilities-current(12)		356		193
Income taxes refundable through future rates(13)		4,071		4,058
Provision for future cost of removal and AROs(9)		1,409		1,384
Nuclear decommissioning trust(14)		1,070		1,121
Derivatives(8)		25		69
Other		265		284
Regulatory liabilities-noncurrent		6,840		6,916
Total regulatory liabilities	$	7,196	$	7,109

Virginia Power
Regulatory assets:
Deferred cost of fuel used in electric generation(1)	$	174	$	23
Deferred rate adjustment clause costs(2)		78		56
Deferred nuclear refueling outage costs(3)		69		54
Other		103		72
Regulatory assets-current		424		205
Deferred rate adjustment clause costs(2)		230		312
PJM transmission rates(7)		192		222
Derivatives(8)		151		190
Deferred cost of fuel used in electric generation(1)		83		—
Other		81		86
Regulatory assets-noncurrent		737		810
Total regulatory assets	$	1,161	$	1,015
Regulatory liabilities:
Cost-of-service impact of 2017 Tax Reform Act(10)	$	95	$	—
Provision for future cost of removal(9)		92		80
Reserve for rate credits to customers(11)		71		—
Other		41		47
Regulatory liabilities-current		299		127
Income taxes refundable through future rates(13)		2,579		2,581
Nuclear decommissioning trust(14)		1,070		1,121
Provision for future cost of removal(9)		940		915
Derivatives(8)		25		69
Other		33		74
Regulatory liabilities-noncurrent		4,647		4,760
Total regulatory liabilities	$	4,946	$	4,887


At December 31,	2018		2017
(millions)

Dominion Energy Gas
Regulatory assets:
Deferred rate adjustment clause costs(2)	$	18	$	14
Unrecovered gas costs(4)		9		8
Other		2		4
Regulatory assets-current(16)		29		26
Unrecognized pension and other postretirement benefit costs(5)		392		258
Utility reform legislation(6)		204		147
Deferred rate adjustment clause costs(2)		99		89
Other		32		17
Regulatory assets-noncurrent		727		511
Total regulatory assets	$	756	$	537
Regulatory liabilities:
Provision for future cost of removal and AROs(9)	$	14	$	13
PIPP(15)		3		20
Other		4		5
Regulatory liabilities-current(12)		21		38
Income taxes refundable through future rates(13)		1,011		998
Provision for future cost of removal and AROs(9)		158		160
Cost-of-service impact of 2017 Tax Reform Act(10)		19		—
Other		97		69
Regulatory liabilities-noncurrent		1,285		1,227
Total regulatory liabilities	$	1,306	$	1,265

(1)	Reflects deferred fuel expenses for the Virginia and North Carolina jurisdictions of Dominion Energy and Virginia Power’s generation operations. See Note 13 for more information.

(2)	Primarily reflects deferrals under the electric transmission FERC formula rate and the deferral of costs associated with certain current and prospective rider projects net of income taxes refundable from the 2017 Tax Reform Act for Virginia Power and deferrals of costs associated with certain current and prospective rider projects for Dominion Energy Gas. See Note 13 for more information.

(3)	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.

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

(5)	Represents unrecognized pension and other postretirement employee benefit costs expected to be recovered through future rates generally over the expected remaining service period of plan participants by certain of Dominion Energy and Dominion Energy Gas’ rate-regulated subsidiaries.

(6)

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.

(7)	Reflects amounts related to the PJM transmission cost allocation matter. See Note 13 for more information.

(8)	As discussed under Derivative Instruments in Note 2, 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.

(9)	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.

(10)	Balance refundable to customers related to the decrease in revenue requirements for recovery of income taxes at the Companies’ regulated electric generation and electric and natural gas distribution operations. See Note 13 for more information.


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(11)	Charge associated with Virginia legislation enacted in March 2018 that requires one-time rate credits of certain amounts to utility customers. See Note 13 for more information.

(12)	Current regulatory liabilities are presented in other current liabilities in Dominion Energy and Dominion Energy Gas’ Consolidated Balance Sheets.

(13)

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

(14)	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.

(15)	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 rider according to East Ohio tariff provisions. See Note 13 for more information.

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

At December 31, 2018, $396 million of Dominion Energy’s, $300 million of Virginia Power’s and $12 million of Dominion Energy Gas’ regulatory assets represented past expenditures on which they do not currently earn a return. With the exception of the PJM transmission cost allocation matter, the majority of these expenditures are expected to be recovered within the next two years.

NOTE 13. REGULATORY MATTERS

Regulatory Matters Involving Potential Loss Contingencies

As a result of issues generated in the ordinary course of business, the Companies are involved in various regulatory matters. Certain regulatory matters may ultimately result in a loss; however, as such matters are in an initial procedural phase, involve uncertainty as to the outcome of pending reviews or orders, and/or involve significant factual issues that need to be resolved, it is not possible for the Companies to estimate a range of possible loss. For regulatory matters that the Companies cannot estimate, a statement to this effect is made in the description of the matter. Other matters may have progressed sufficiently through the regulatory process such that the Companies are able to estimate a range of possible loss. For regulatory matters that the Companies are able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. Any estimated range is based on currently 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 util-

ities. Virginia Power purchases and sells electricity in the PJM wholesale market and sells electricity to wholesale purchasers in Virginia and North Carolina. Dominion Energy’s merchant generators sell electricity in the PJM, 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 sell as a qualified facility. In addition, Virginia Power has FERC approval 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 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 projected costs, allows Virginia Power to earn a current return on its investment in electric transmission infrastructure.

In March 2010, ODEC 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. In November 2017, Virginia Power, North Carolina Electric Membership Corporation and the wholesale transmission customers filed petitions for rehearing. In July


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2018, FERC denied the rehearing requests related to the October 2017 order determining the calculation of the undergrounding costs. Several parties have appealed FERC’s decision to the U.S. Court of Appeals for the D.C. Circuit. This matter is pending. While Virginia Power cannot predict the outcome of the matter, it is not expected to have a material effect on results of operations.

In January 2019, FERC issued an order denying PJM’s request to waive certain provisions of the PJM Tariff regarding the liquidation of a portfolio of FTRs owned by GreenHat who had defaulted on its financial obligations. As a result of FERC’s order, PJM is required to use the existing tariff provisions to liquidate GreenHat’s FTR portfolio and allocate the resulting costs to PJM members. In February 2019, PJM filed a request for clarification and rehearing with FERC. While the impacts of this order could be material to 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.

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. In May 2018, FERC issued an order accepting the settlement agreement and directed PJM to make a compliance filing with revised tariff records. As a result, in August 2018, Virginia Power began to make payments to PJM, to continue for the next 10 years totaling $276 million, under the terms of revised tariff records, which was partially offset by a $265 million regulatory asset for the amount that will be recovered through retail rates in Virginia. At December 31, 2018, Virginia Power’s Consolidated Balance Sheet includes $126 million in other current liabilities and $50 million included in other

deferred credits and other liabilities for amounts owed to PJM.

FERC—GAS

In July 2017, FERC audit staff communicated to DETI that it had substantially completed an audit of DETI’s compliance with the accounting and reporting requirements of FERC’s Uniform System of Accounts and provided a description of matters and preliminary recommendations. In November 2017, the FERC audit staff issued its audit report which could have the potential to result in adjustments which could be material to Dominion Energy and Dominion Energy Gas’ results of operations. In December 2017, DETI provided its response to the audit report. DETI requested FERC review of contested findings and submitted its plan for compliance with the uncontested portions of the report. In connection with one uncontested issue, DETI recognized a charge of $15 million ($9 million after-tax) recorded within impairment of assets and related charges in Dominion Energy and Dominion Energy Gas’ Consolidated Statements of Income during 2017 to write-off the balance of a regulatory asset, originally established in 2008, that is no longer considered probable of recovery. DETI recognized a charge of $129 million ($94 million after-tax) recorded primarily within impairment of assets and related charges in Dominion Energy and Dominion Energy Gas’ Consolidated Statements of Income during 2018 for a disallowance of plant, originally established beginning in 2012, for the resolution of one matter with FERC. Pending final resolution of the audit process and a determination by FERC, management is unable to estimate the potential impact of the remaining finding and no amounts have been recognized.

2017 TAX REFORM ACT

Subsequent to the enactment of the 2017 Tax Reform Act, the Companies’ state regulators issued orders requesting that public utilities evaluate the total tax impact on the entity’s cost of service and accrue a regulatory liability attributable to the benefits of the reduction in the corporate income tax rate. Certain of the orders requested that the public utilities submit a response to the state regulatory commissions detailing the total tax impact on the utility’s cost of service.

The Companies began to reserve the impacts of the cost-of-service reduction as regulatory liabilities in January 2018 and will continue until rates are reset pursuant to state regulators’ approvals. The Companies have recorded a reasonable estimate of net income taxes refundable through future rates in the jurisdictions in which they operate and are currently assessing these actions and decisions, which could have a material impact on the Companies’ results of operations, financial condition and/or cash flows.

In September 2018, the Virginia Commission issued an order directing Virginia Power to submit a filing quantifying the impacts of the 2017 Tax Reform Act in advance of the April 1, 2019 implementation as required by legislation. In October 2018, Virginia Power filed testimony with the Virginia Commission to implement adjustments in its base rates reflecting actual annual reductions in corporate income taxes resulting from the 2017 Tax Reform Act, which included a proposed annual revenue reduction of approximately $151 million effective April 2019. In December 2018, the Staff of the Virginia Commission proposed an annual revenue reduction of approximately $190 million. In January 2019, Virginia Power filed updated testimony with a proposed


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annual revenue reduction of approximately $171 million. Additionally, Virginia Power proposed to issue a one-time bill credit to customers within 90 days of this effective date, to true-up the difference between the final revenue reduction for the period January 1, 2018 through March 31, 2019 and the $125 million interim rate reduction implemented on July 1, 2018. Based on Virginia Power’s current proposed annual revenue reduction, this one-time bill credit is expected to total approximately $120 million. The actual credit will be based on actual billing data and customer usage during that 15-month period. This matter is pending.

In August 2018, Virginia Power filed with FERC to waive protocols and begin reflecting projected tax reform benefits of approximately $100 million through the transmission formula rate prior to the normal formula rate process. FERC granted the waiver and the amounts began being reflected in customer billings in November 2018 reflecting the adjustment effective January 1, 2018.

In October 2018, the North Carolina Commission issued an order requesting companies file to reduce base rates expeditiously. Virginia Power made its compliance filing in October 2018 and submitted an annual base rate revenue decrease of approximately $14 million effective in early 2019. Virginia Power also proposed to issue a one-time bill credit in early 2019 for its 2018 tax savings collected provisionally from customers, which is estimated to be approximately $13 million. The order allowed for the disposition of excess deferred income taxes to be deferred for consideration until the utilities’ next base rate case, but no longer than 3 years, and initiated a quarterly reporting requirement for such deferred amounts. This matter is pending.

In May 2018, the Utah Commission approved a stipulation submitted by Questar Gas proposing the cost-of-service component of customer rates be reduced by $15 million annually beginning in June 2018. In July 2018, the Utah Commission approved Questar Gas’ request to return an additional $9 million to Utah customers representing the amounts related to the corporate income tax reduction that had been deferred from January 1, 2018 to May 31, 2018. This additional reduction began amortizing on August 1, 2018 and will be amortized over a one-year period. In October 2018, the Wyoming Commission approved Questar Gas’ request to return deferred amounts through a surcredit beginning November 1, 2018. The surcredit will remain in effect until rates become effective in the next Wyoming general rate case. The impact of excess deferred income taxes resulting from the 2017 Tax Reform Act on rates charged to customers will be reported to the Utah and Wyoming Commissions by the first quarter of 2019.

In October 2018, the Ohio Commission issued an order requiring rate-regulated utilities to file an application reflecting the impact of the 2017 Tax Reform Act on current rates by January 1, 2019. In December 2018, East Ohio filed its application proposing an approach to establishing rates and charges by and through which to return tax reform benefits to its customers. This case is pending.

As directed by the West Virginia Commission, Hope is utilizing regulatory accounting to track the effects of the 2017 Tax Reform Act beginning in January 2018 and submitted testimony in July 2018 detailing such effects. In August 2018, the West Virginia Commission approved a settlement implementing base

rate reductions effective September 1, 2018. In November 2018, the West Virginia Commission issued an order requiring Hope to file a calculation of prospective tax reform savings based on 2017 financial statements, using federal income tax rates reduced for consolidated tax savings, and to record as a regulatory liability the difference between the amount calculated based on 2017 financial statements and the amount included in the voluntary base rate reduction effective September 1, 2018. In December 2018, Hope filed the required calculation setting forth an annual regulatory liability deferral amount of $0.4 million. The disposition of the additional regulatory liability will be determined in a future rate proceeding. These reductions are not expected to have a material impact on Hope’s financial condition.

In March 2018, FERC announced actions to address the income tax allowance component of regulated entities’ cost-of-service rates as a result of the 2017 Tax Reform Act. FERC required all interstate natural gas pipelines to make a one-time informational filing with FERC to provide financial information to allow FERC and other interested parties to analyze the impacts of the changes in tax law. The actions also included the reversal of FERC’s policy allowing master limited partnerships to recover an income tax allowance in cost-of-service rates and requiring other pass-through entities to justify the inclusion of an income tax allowance.

In July 2018, FERC issued a final rule adopting and modifying the procedures for determining whether jurisdictional natural gas pipelines may be collecting unjust and unreasonable rates in light of the reduction in the corporate income tax rate. Specifically, this final rule does not require master limited partnerships to eliminate their income tax allowances when completing the informational filing and allows entities that are wholly-owned by corporations to include an income tax allowance.

During 2018, Dominion Energy’s FERC-regulated pipelines, including those accounted for as equity method investments, filed the required informational reports with FERC. Dominion Energy Overthrust Pipeline, LLC, White River Hub, Dominion Energy Questar Pipeline and Cove Point have reached resolution through settlement, which did not result in a material impact to results of operations, financial condition and/or cash flows of Dominion Energy, waiver or FERC terminating the 501-G proceeding. In January 2019, Iroquois reached a settlement in principle with its customers, which if approved would not have a material impact to Dominion Energy or Dominion Energy Gas, and expects to file a settlement agreement with FERC in the first quarter of 2019. The FERC dockets for DETI and DECG remain open. While the informational filings for these two pipelines indicated that no changes to current rates charged to customers were necessary, given the associated uncertainty, Dominion Energy and Dominion Energy Gas are currently unable to predict the outcome of these matters; however, any change in rates permitted to be charged to customers could have a material impact on results of operations, financial condition and/or cash flows.

Other Regulatory Matters

VIRGINIA REGULATION

The Regulation Act enacted in 2007 instituted a cost-of-service rate model, ending Virginia’s planned transition to retail competition for electric supply service to most classes of customers.


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The Regulation Act authorizes stand-alone rate adjustment clauses for recovery of costs for new generation projects, FERC-approved transmission costs, underground distribution lines, environmental compliance, conservation and energy efficiency programs, renewable energy programs and nuclear license renewals, and also contains statutory provisions directing Virginia Power to file annual fuel cost recovery cases with the Virginia Commission. As amended, it provides for enhanced returns on capital expenditures on specific newly-proposed generation projects.

If the Virginia Commission’s future rate decisions, including actions relating to Virginia Power’s rate adjustment clause filings, differ materially from Virginia Power’s expectations, it may adversely affect its results of operations, financial condition and cash flows.

Grid Transformation and Security Act of 2018

In March 2018, the GTSA reinstated base rate reviews on a triennial basis, other than the first review which will be a quadrennial review, occurring for Virginia Power in 2021 for the four successive 12-month test periods beginning January 1, 2017 and ending December 31, 2020. This review for Virginia Power will occur one year earlier than under the Regulation Act legislation enacted in February 2015.

In the triennial review proceedings, earnings that are more than 70 basis points above the utility’s authorized return on equity that might have been refunded to customers and served as the basis for a reduction in future rates, may be reduced by approved investment amounts in qualifying solar or wind generation facilities or electric distribution grid transformation projects that Virginia Power elects to include in a customer credit reinvestment offset. The legislation declares that electric distribution grid transformation projects are in the public interest and provides that the costs of such projects may be recovered through a rate adjustment clause if not the subject of a customer credit reinvestment offset. Any costs that are the subject of a customer credit reinvestment offset may not be recovered in base rates for the service life of the projects and may not be included in base rates in future triennial review proceedings. In any triennial review in which the Virginia Commission determines that the utility’s earnings are more than 70 basis points above its authorized return on equity, base rates are subject to reduction prospectively and customer refunds would be due unless the total customer credit reinvestment offset elected by the utility equals or exceeds the amount of earnings in excess of the 70 basis points. In the 2021 review, any such rate reduction is limited to $50 million.

The legislation also includes provisions requiring Virginia Power to provide current customers one-time rate credits totaling $200 million and to reduce base rates to reflect reductions in income tax expense resulting from the 2017 Tax Reform Act. As a result, Virginia Power incurred a $215 million ($160 million after-tax) charge in connection with this legislation, including the impact on certain non-jurisdictional customers which follow Virginia Power’s jurisdictional customer rate methodology. In July 2018 and January 2019, Virginia Power credited $138 million and $77 million, respectively, to current customers’ bills.

In addition, Virginia Power reduced base rates on an annual basis by $125 million effective July 2018, to reflect the estimated effect of the 2017 Tax Reform Act, which is subject to adjustment

effective April 2019. In May and June 2018, Virginia Power submitted filings detailing the implementation plan for interim reductions in rates for generation and distribution services pursuant to the GTSA.

In July 2018, Virginia Power filed a petition with the Virginia Commission for approval of the first three years of its ten-year plan for electric distribution grid transformation projects as authorized by the GTSA. During the first three years of the plan, Virginia Power proposes to focus on the following seven foundational components of the overall grid transformation plan: (i) smart meters; (ii) customer information platform; (iii) reliability and resilience; (iv) telecommunications infrastructure; (v) cyber and physical security; (vi) predictive analytics; and (vii) emerging technology. The total estimated capital investment during 2019-2021 is $816 million and the proposed operations and maintenance expenses are $102 million. In January 2019, the Virginia Commission issued its final order approving capital spending for the first three years of the plan-totaling $68 million on cyber and physical security and related telecommunications infrastructure. The Virginia Commission declined to approve the remainder of the proposed components for the first three years of the plan, the proposed spending for which was not found reasonable and prudent based on the record in the proceeding. Virginia Power intends to file a revised plan in mid-2019 that will address the elements needed for a comprehensive plan, as outlined by the Virginia Commission in its order.

Virginia Fuel Expenses

In May 2018, Virginia Power filed its annual fuel factor with the Virginia Commission to recover an estimated $1.5 billion in Virginia jurisdictional projected fuel expenses for the rate year beginning July 1, 2018. Virginia Power’s proposed fuel rate represented a fuel revenue increase of $222 million when applied to projected kilowatt-hour sales for the period July 1, 2018 to June 30, 2019. In August 2018, the Virginia Commission approved Virginia Power’s fuel rate with an increase of $209 million.

Solar Facility Projects

In July 2018, Virginia Power filed an application with the Virginia Commission for CPCNs to construct two solar facilities. Colonial Trail West and Spring Grove 1 are estimated to cost approximately $410 million, excluding financing costs. Colonial Trail West and Spring Grove 1 are expected to commence commercial operations, subject to regulatory approvals associated with the projects, in the fourth quarter of 2019 and the fourth quarter of 2020, respectively. Virginia Power also applied for approval of Rider US-3 associated with these projects with a proposed $10 million total revenue requirement for the rate year beginning March 1, 2019. In January 2019, the Virginia Commission issued a final order granting CPCNs to construct the solar facilities, subject to a 20-year performance guarantee of the facilities at a 25% solar capacity factor when normalized for force majeure events. The matter regarding Rider US-3 is pending.

Rate Adjustment Clauses

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

•		The Virginia Commission previously approved Rider T1 concerning transmission rates. In May 2018, Virginia Power proposed a $755 million total revenue requirement consisting of $468 million for the transmission component of Virginia


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		Power’s base rates and $287 million for Rider T1. This total revenue requirement represents a $146 million increase versus the revenues to be produced during the rate year under current rates. In August 2018, the Virginia Commission approved a total revenue requirement of $630 million, including Rider T1, subject to true-up, for the rate year beginning September 1, 2018. The Virginia Commission’s order required an adjustment to Rider T1 to begin providing projected benefits associated with the 2017 Tax Reform Act to customers in rates effective September 1, 2018. Such projected benefits were not included in the underlying transmission formula rates approved by FERC. Also in August 2018, Virginia Power filed a petition with the Virginia Commission seeking limited reconsideration and rehearing of this approval to adjust the total revenue requirement to $636 million. In November 2018, the Virginia Commission denied the petition for limited reconsideration and rehearing and adjusted the total revenue requirement to $628 million.

•		The Virginia Commission previously approved Rider U in conjunction with cost recovery to move certain electric distribution facilities underground as authorized by Virginia legislation. In March 2018, Virginia Power requested approval of its third phase of conversions totaling $179 million and a balance of $65 million in second phase conversions not previously approved for recovery through Rider U. Virginia Power also proposed a total $73 million revenue requirement for the rate year beginning February 1, 2019 for continuing recovery of the previously approved first and second phase conversions and the proposed second and third phase conversions. In December 2018, the Virginia Commission approved a total $70 million annual revenue requirement effective February 1, 2019, a total capital investment of $179 million for third phase conversions and a balance of $64 million for second phase conversions not previously approved for recovery through Rider U.

•		The Virginia Commission previously approved Riders C1A and C2A in connection with cost recovery for DSM programs. In October 2018, Virginia Power requested approval to implement ten new energy efficiency programs and one new demand-response DSM program for five years, subject to future extensions, with a $262 million cost cap, and proposed a total $49 million revenue requirement for the rate year beginning July 1, 2019, which represents an $18 million increase over the previous year. This matter is pending.

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


Rider Name	Application Date	Approval Date	Rate Year Beginning	Total Revenue Requirement (millions)		Increase (Decrease) Over Previous Year (millions)
Rider S	June 2018	February 2019	April 2019	$	215	$	(3	)
Rider GV	June 2018	February 2019	April 2019		120		38
Rider W	June 2018	February 2019	April 2019		105		(4	)
Rider R	June 2018	February 2019	April 2019		57		(9	)
Rider B	June 2018	February 2019	April 2019		38		(9	)
Rider BW	October 2018	Pending	September 2019		123		7
Rider US-2	October 2018	Pending	September 2019		16		3
Rider E	December 2018	Pending	November 2019		114		N/A

Coastal Virginia Offshore Wind Project

In November 2018, Virginia Power received approval from the Virginia Commission for its petition seeking a prudency determination as provided in the GTSA with respect to the proposed Coastal Virginia Offshore Wind project consisting of two 6 MW wind turbine generators located approximately 27 miles off the coast of Virginia Beach, Virginia in federal waters, and for a CPCN, for the generation tie line connecting the generators to shore. This project is expected to cost approximately $300 million and to be placed into service by the end of 2020.

Electric Transmission Projects

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 December 31, 2017, Virginia Power had made $90 million of such payments. 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. In May 2018, the District Court granted summary judgment in favor of the U.S. Army Corps of Engineers and Virginia Power and dismissed both lawsuits. In June 2018, the National Parks Conservation Association and the National Trust for Historic Preservation and Preservation Virginia appealed that decision to the U.S. Court of Appeals for the D.C. Circuit. The appeal is pending. Also in June 2018, the National Parks Conservation Association filed requests with the U.S. District Court for the District of Columbia and the U.S. Court of Appeals for the D.C. Circuit for an injunction against the permit pending appeal. The U.S. District Court for the District of Columbia denied the injunction request in June 2018 and the U.S. Court of Appeals for the D.C. Circuit similarly denied the request in July 2018.

In November 2015, Virginia Power filed an application with the Virginia Commission for a CPCN to convert an existing transmission line to 230 kV in Prince William County, Virginia, and Loudoun County, Virginia, and to construct and operate a new approximately five mile overhead 230 kV double circuit transmission line between a tap point near the Gainesville substation and a new to-be-constructed Haymarket substation. The


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total estimated cost of the project is approximately $180 million. In April 2017, the Virginia Commission issued an interim order instructing Virginia Power to construct and operate the project along an approved route if Virginia Power could obtain all necessary rights-of-way. Otherwise, the Virginia Commission ruled that Virginia Power can construct and operate the project along an approved alternative route. In June 2017, the Virginia Commission issued a final order approving the alternative route for the project, and granted the necessary CPCN. In July 2017, the Virginia Commission retained jurisdiction over the case to evaluate two requests to reconsider its decisions. Also in July 2017, Virginia Power requested that the Virginia Commission stay the proceeding while Virginia Power discusses the proposed route with leaders of Prince William County. In December 2017, the Virginia Commission granted in part the two motions for reconsideration, retained jurisdiction for further proceedings in the case and stayed the effectiveness of its final order. In March 2018, Virginia Power and the two parties seeking reconsideration entered into a stipulation settlement filed with the Virginia Commission agreeing that the project should be placed into an underground pilot program created by the GTSA. In July 2018, Virginia Power filed a request with the Virginia Commission to allow the project to participate in the underground pilot program. Subsequently, in July 2018, the Virginia Commission issued a final order granting the CPCN for the project and allowing the project to participate in the underground pilot program.

In June 2018, Virginia Power filed an application with the Virginia Commission for a CPCN to rebuild and operate in King and Queen, King William, and New Kent Counties, Virginia four separate segments of 230 kV transmission line between Lanexa and the Northern Neck in Virginia. In February 2019, Virginia Power withdrew two of the segments from the application. As a result, the total estimated cost of the project is approximately $30 million. This matter is pending.

Additional significant Virginia Power electric transmission projects approved and applied for in 2018 are as follows:


Description and Location of Project	Application Date	Approval Date	Type of Line		Miles of Lines		Cost Estimate (millions)
Rebuild and operate existing 115 kV transmission lines between the Possum Point Switching Station and Northern Virginia Electric Cooperative’s Smoketown delivery point	June 2017	February 2018		230 kV		9	$	20
Rebuild and operate between the Dooms substation and the Valley substation, along with associated substation work	September 2017	September 2018		500 kV		18		65
Build and operate between the Idylwood and Tysons substations, along with associated substation work	November 2017	September 2018		230 kV		4		125
Rebuild and operate between the Chesterfield and Hopewell substations, along with associated substation work	May 2018	November 2018		230 kV		8		30
Rebuild and operate between the Chesterfield and Lakeside substations, along with associated substation work	May 2018	December 2018		230 kV		21		35
Rebuild and operate between the Landstown and Thrasher substations, along with associated substation work	June 2018	December 2018		230 kV		8.5		20
Partial rebuild of overhead transmission lines in Alleghany County, Virginia and Covington, Virginia	August 2018	Pending		138 kV		5		15
Build a new substation and connect three existing transmission lines thereto in Fluvanna County, Virginia	October 2018	Pending		230 kV		<1		30

NORTH CAROLINA REGULATION

In August 2018, Virginia Power submitted its annual filing to the North Carolina Commission to adjust the fuel component of its electric rates. Virginia Power proposed a total $24 million increase to the fuel component of its electric rates for the rate year beginning February 1, 2019. As a mitigation alternative, Virginia Power proposed recovering 50% in the February 1, 2019 to the January 31, 2020 rate period and the remaining 50% in the following rate period. In January 2019, the North Carolina Commission approved Virginia Power’s full proposed fuel charge adjustment of $24 million.

OHIO REGULATION

PIR Program

In 2008, East Ohio began PIR, aimed at replacing approximately 25% of its pipeline system. In March 2015, East Ohio filed an application with the Ohio Commission requesting approval to extend the PIR program for an additional five years and to increase the annual capital investment, with corresponding increases in the annual rate-increase caps. In September 2016, the Ohio Commission approved a stipulation filed jointly by East Ohio and the Staff of the Ohio Commission to settle East Ohio’s pending application. As requested, the PIR program and associated cost recovery will continue for another five-year term, calendar years 2017 through 2021, and East Ohio will be permit-

ted to increase its annual capital expenditures to $200 million by 2018 and 3% per year thereafter subject to the cost recovery rate increase caps proposed by East Ohio.

In April 2018, the Ohio Commission approved East Ohio’s application to adjust the PIR cost recovery rates for 2017 costs. The filing reflects gross plant investment for 2017 of $204 million, cumulative gross plant investment of $1.4 billion and a revenue requirement of $165 million.

AMR Program

In 2007, East Ohio began installing automated meter reading technology for its 1.2 million customers in Ohio. The AMR program approved by the Ohio Commission was completed in 2012. Although no further capital investment will be added, East Ohio is approved to recover depreciation, property taxes, carrying charges and a return until East Ohio has another rate case.

In April 2018, the Ohio Commission approved East Ohio’s application to adjust its AMR cost recovery rate for 2017 costs. The filing reflects a revenue requirement of approximately $5 million.

PIPP Plus Program

Under the Ohio PIPP Plus Program, eligible customers can make reduced payments based on their ability to pay their bill. The difference between the customer’s total bill and the PIPP amount is deferred and collected under the PIPP rider in accordance with


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Combined Notes to Consolidated Financial Statements, Continued

the rules of the Ohio Commission. In May 2018, East Ohio filed its annual update of the PIPP rider with the Ohio Commission. In July 2018, East Ohio’s annual update of the PIPP rider was automatically approved by the Ohio Commission after a 45-day waiting period from the date of the filing. The revised rider rate reflects recovery over the twelve-month period from July 2018 through June 2019 of projected deferred program costs of approximately $10 million from April 2018 through June 2019, net of a refund for over-recovery of accumulated arrearages of approximately $4 million as of March 31, 2018.

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 2018, 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 $11 million as of March 31, 2018, and recovery of prospective net bad debt expense projected to total $16 million for the twelve-month period from April 2018 to March 2019.

DSM Rider

East Ohio has approval for a DSM rider through which it recovers expenditures related to its DSM programs. In November 2018, East Ohio filed an application with the Ohio Commission seeking approval of an adjustment to the DSM rider to recover a total of $4 million, which includes an over-recovery of costs during the preceding 12-month period. This application was approved by the Ohio Commission in January 2019.

WEST VIRGINIA REGULATION

In May 2018, Hope filed a PREP application with the West Virginia Commission requesting approval to recover PREP costs related to $31 million and $36 million of projected capital investment for 2018 and 2019, respectively. The application also includes a true-up of PREP costs related to the 2017 actual capital investment of $28 million and sets forth $8 million of annual PREP costs to be recovered in proposed rates effective November 2018. In October 2018, the West Virginia Commission approved PREP rates effective November 2018. Approved rates recover $7 million of annual PREP costs related to actual cumulative PREP investment through December 31, 2017 of $48 million and projected PREP investment for calendar years 2018 and 2019 of $31 million and $29 million, respectively.

UTAH AND WYOMING REGULATION

Fuel Deferral

In May 2018, Questar Gas submitted filings with both the Utah Commission and the Wyoming Commission for an approximately $86 million gas cost decrease reflecting forecasted decreases in commodity costs. The Utah Commission and the Wyoming Commission both approved the filings in May 2018 with rates effective June 2018.

In October 2018, Questar Gas submitted filings with both the Utah Commission and the Wyoming Commission for an approximately $48 million gas cost decrease reflecting forecasted decreases in commodity costs. The Utah Commission and the

Wyoming Commission both approved the filings in October 2018 with rates effective November 2018.

In October 2018, the Utah Commission denied Questar Gas’ request for pre-approval to construct an LNG peaking storage facility with a liquefaction rate of 8.2 million cubic feet per day. Questar Gas is reviewing the order and assessing its options, which include filing supplemental information with the Utah Commission for reconsideration.

Infrastructure Replacement Tracker

During 2018, Questar Gas filed applications with the Utah Commission to increase its infrastructure replacement surcharge to collect an additional $11 million in revenue in 2019 related to $85 million in 2018 capital investment. The Utah Commission approved the applications in the fourth quarter of 2018.

FERC—GAS

Cove Point

In March 2018, Cove Point submitted its annual electric power cost adjustment to FERC requesting approval to recover $30 million. FERC approved the adjustment in March 2018.

In June 2015, Cove Point executed two binding precedent agreements for the approximately $150 million Eastern Market Access Project. In January 2018, Cove Point received FERC authorization to construct and operate the project facilities, which are expected to be placed in service in the second half of 2019. In October 2018, Cove Point announced it is evaluating alternatives to a proposed Charles County, Maryland compressor station that was initially part of this project and in December 2018, after working with project customers for alternative solutions, decided not to pursue further construction at this location resulting in a revised project estimate of approximately $45 million and a write-off of $37 million pre-tax ($28 million after-tax) recorded within impairment of assets and related charges in Dominion Energy’s Consolidated Statements of Income.

DETI

In September 2018, DETI submitted its annual transportation cost rate adjustment to FERC requesting approval to recover $37 million. Also in September 2018, DETI submitted its annual electric power cost adjustment to FERC requesting approval to recover $7 million. In October 2018, FERC approved these adjustments.

In August 2018, DETI executed a binding precedent agreement with a customer for the West Loop project. The project is expected to cost approximately $95 million and provide 150,000 Dth per day of firm transportation service from Pennsylvania to Ohio for delivery to a proposed combined-cycle, natural gas-fired electric power generation facility to be located in Columbiana County, Ohio. In December 2018, DETI filed an application to request FERC authorization to construct, operate and maintain the project facilities, which are expected to be in service by the end of 2021.

NOTE 14. ASSET RETIREMENT OBLIGATIONS

AROs represent obligations that result from laws, statutes, contracts and regulations related to the eventual retirement of certain of the Companies’ long-lived assets. Dominion Energy and Virginia Power’s AROs are primarily associated with the decom-


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missioning of their nuclear generation facilities and ash pond and landfill closures. Dominion Energy Gas’ AROs primarily include plugging and abandonment of gas and oil wells and the interim retirement of natural gas gathering, transmission, distribution and storage pipeline components.

The Companies have also identified, but not recognized, AROs related to the retirement of Dominion Energy’s LNG facility, Dominion Energy and Dominion Energy Gas’ storage wells in their underground natural gas storage network, certain Virginia Power electric transmission and distribution assets located on property with easements, rights of way, franchises and lease agreements, Virginia Power’s hydroelectric generation facilities and the abatement of certain asbestos not expected to be disturbed in Dominion Energy and Virginia Power’s generation facilities. The Companies currently do not have sufficient information to estimate a reasonable range of expected retirement dates for any of these assets since the economic lives of these assets can be extended indefinitely through regular repair and maintenance and they currently have no plans to retire or dispose of any of these assets. As a result, a settlement date is not determinable for these assets and AROs for these assets will not be reflected in the Consolidated Financial Statements until sufficient information becomes available to determine a reasonable estimate of the fair value of the activities to be performed. The Companies continue to monitor operational and strategic developments to identify if sufficient information exists to reasonably estimate a retirement date for these assets. The changes to AROs during 2017 and 2018 were as follows:


	Amount
(millions)
Dominion Energy
AROs at December 31, 2016	$	2,485
Obligations incurred during the period		37
Obligations settled during the period		(214	)
Revisions in estimated cash flows		7
Accretion		117
AROs at December 31, 2017(1)	$	2,432
Obligations incurred during the period		20
Obligations settled during the period		(159	)
Revisions in estimated cash flows(2)		120
Accretion		119
AROs at December 31, 2018(1)	$	2,532
Virginia Power
AROs at December 31, 2016	$	1,443
Obligations incurred during the period		11
Obligations settled during the period		(152	)
Revisions in estimated cash flows		(1	)
Accretion		64
AROs at December 31, 2017	$	1,365
Obligations incurred during the period		14
Obligations settled during the period		(119	)
Revisions in estimated cash flows(2)		120
Accretion		65
AROs at December 31, 2018	$	1,445
Dominion Energy Gas
AROs at December 31, 2016	$	156
Obligations incurred during the period		2
Obligations settled during the period		(7	)
Accretion		9
AROs at December 31, 2017(3)	$	160
Obligations incurred during the period		4
Obligations settled during the period		(6	)
Accretion		9
AROs at December 31, 2018(3)	$	167

(1)	Includes $263 million and $282 million reported in other current liabilities at December 31, 2017, and 2018, respectively.

(2)	Reflects future ash pond and landfill closure costs at certain utility generation facilities. See Note 22 for further information.

(3)	Includes $146 million and $153 million reported in other deferred credits and other liabilities, with the remainder recorded in other current liabilities, at December 31, 2017 and 2018, respectively.

Dominion Energy and Virginia Power have established trusts dedicated to funding the future decommissioning of their nuclear plants. At December 31, 2018 and 2017, the aggregate fair value of Dominion Energy’s trusts, consisting primarily of equity and debt securities, totaled $4.9 billion and $5.1 billion, respectively. At December 31, 2018 and 2017, the aggregate fair value of Virginia Power’s trusts, consisting primarily of debt and equity securities, totaled $2.4 billion for both periods.

NOTE 15. VARIABLE INTEREST ENTITIES

The primary beneficiary of a VIE is required to consolidate the VIE and to disclose certain information about its significant variable interests in the VIE. The primary beneficiary of a VIE is the entity that has both 1) the power to direct the activities that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses or receive benefits from the entity that could potentially be significant to the VIE.

DOMINION ENERGY

At December 31, 2018, Dominion Energy owned the general partner, 60.9% of the common and subordinated units and 37.5% of the convertible preferred interests in Dominion Energy Midstream, which owned a preferred equity interest and the general partner interest in Cove Point. In January 2019, Dominion Energy acquired all outstanding partnership interests not owned by Dominion Energy and Dominion Energy Midstream became a wholly-owned subsidiary of Dominion Energy. Dominion Energy previously concluded that Dominion Energy Midstream was a VIE due to the limited partners lacking the characteristics of a controlling financial interest. Dominion Energy was the primary beneficiary of Dominion Energy Midstream and Dominion Energy Midstream was the primary beneficiary of Cove Point as they had the power to direct the activities that most significantly impact their economic performance as well as to absorb losses and benefits which could be significant to them.

At December 31, 2018, Dominion Energy owns the manager and 67% of the membership interest in certain merchant solar facilities, as discussed in Note 2. Dominion Energy has concluded that these entities are VIEs due to the members lacking the characteristics of a controlling financial interest. In addition, in 2016 Dominion Energy created a wholly owned subsidiary, SBL Holdco, as a holding company of its interest in the VIE merchant solar facilities and accordingly SBL Holdco is a VIE. Dominion Energy is the primary beneficiary of SBL Holdco and the merchant solar facilities, as it has the power to direct the activities that most significantly impact their economic performance as well as the obligation to absorb losses and benefits which could be significant to them. Dominion Energy’s securities due within one year and long-term debt include $31 million and $299 million, respectively, of debt issued by SBL Holdco net of issuance costs that is nonrecourse to Dominion Energy and is secured by SBL Holdco’s interest in certain merchant solar facilities.

Dominion Energy owns a 48% membership interest in Atlantic Coast Pipeline. See Note 9 for more details regarding the


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Combined Notes to Consolidated Financial Statements, Continued

nature of this entity. Dominion Energy concluded that Atlantic Coast Pipeline is a VIE because it has insufficient equity to finance its activities without additional subordinated financial support. Dominion Energy has concluded that it is not the primary beneficiary of Atlantic Coast Pipeline as it does not have the power to direct the activities of Atlantic Coast Pipeline that most significantly impact its economic performance, as the power to direct is shared among multiple unrelated parties. Dominion Energy is obligated to provide capital contributions based on its ownership percentage. Dominion Energy’s maximum exposure to loss is limited to its current and future investment as well as any obligations under a guarantee provided. See Note 22 for more information.

DOMINION ENERGY AND VIRGINIA POWER

Dominion Energy and Virginia Power’s nuclear decommissioning trust funds and Dominion Energy’s rabbi trusts hold investments in limited partnerships or similar type entities (see Note 9 for further details). Dominion Energy and Virginia Power concluded that these partnership investments are VIEs due to the limited partners lacking the characteristics of a controlling financial interest. Dominion Energy and Virginia Power have concluded neither is the primary beneficiary as they do not have the power to direct the activities that most significantly impact these VIEs’ economic performance. Dominion Energy and Virginia Power are obligated to provide capital contributions to the partnerships as required by each partnership agreement based on their ownership percentages. Dominion Energy and Virginia Power’s maximum exposure to loss is limited to their current and future investments.

DOMINION ENERGY AND DOMINION ENERGY GAS

Dominion Energy previously concluded that Iroquois was a VIE because a non-affiliated Iroquois equity holder had the ability during a limited period of time to transfer its ownership interests to another Iroquois equity holder or its affiliate. At the end of the first quarter 2016, such right no longer existed and, as a result, Dominion Energy concluded that Iroquois is no longer a VIE.

VIRGINIA POWER

Virginia Power had long-term power and capacity contracts with three non-utility generators, which contain certain variable pricing mechanisms in the form of partial fuel reimbursement that Virginia Power considers to be variable interests. Contracts with two of these non-utility generators expired during 2017, leaving a remaining aggregate summer generation capacity of approximately 218 MW. After an evaluation of the information provided by these entities, Virginia Power was unable to determine whether they were VIEs. However, the information they provided, as well as Virginia Power’s knowledge of generation facilities in Virginia, enabled Virginia Power to conclude that, if they were VIEs, it would not be the primary beneficiary. This conclusion reflects Virginia Power’s determination that its variable interests do not convey the power to direct the most significant activities that impact the economic performance of the remaining entity during the remaining terms of Virginia Power’s contract and for the years the entity is expected to operate after its contractual relationship expires. The remaining contract expires in 2021. Virginia Power is not subject to any risk of loss from this potential VIE other than its remaining purchase commitments which totaled $150 million as of December 31, 2018. Virginia

Power paid $50 million, $86 million, and $144 million for electric capacity to non-utility generators and $18 million, $24 million, and $31 million for electric energy to non-utility generators for the years ended December 31, 2018, 2017 and 2016, respectively.

DOMINION ENERGY GAS

DETI has been engaged to oversee the construction of, and to subsequently operate and maintain, the projects undertaken by Atlantic Coast Pipeline based on the overall direction and oversight of Atlantic Coast Pipeline’s members. An affiliate of DETI holds a membership interest in Atlantic Coast Pipeline, therefore DETI is considered to have a variable interest in Atlantic Coast Pipeline. The members of Atlantic Coast Pipeline hold the power to direct the construction, operations and maintenance activities of the entity. DETI has concluded it is not the primary beneficiary of Atlantic Coast Pipeline as it does not have the power to direct the activities of Atlantic Coast Pipeline that most significantly impact its economic performance. DETI has no obligation to absorb any losses of the VIE. See Note 24 for information about associated related party receivable balances.

VIRGINIA POWER AND DOMINION ENERGY GAS

Virginia Power and Dominion Energy Gas purchased shared services from DES, an affiliated VIE, of $335 million and $126 million, $340 million and $126 million, and $346 million and $123 million for the years ended December 31, 2018, 2017 and 2016, respectively. Virginia Power and Dominion Energy Gas’ Consolidated Balance Sheets included amounts due to DES of $107 million and $46 million, respectively, at December 31, 2018, and $36 million and $14 million, respectively, at December 31, 2017, recorded in payables to affiliates in the Consolidated Balance Sheets. Virginia Power and Dominion Energy Gas determined that neither is the primary beneficiary of DES as neither has both the power to direct the activities that most significantly impact its economic performance as well as the obligation to absorb losses and benefits which could be significant to it. DES provides accounting, legal, finance and certain administrative and technical services to all Dominion Energy subsidiaries, including Virginia Power and Dominion Energy Gas. Virginia Power and Dominion Energy Gas have no obligation to absorb more than their allocated shares of DES costs.

NOTE 16. SHORT-TERM DEBT AND CREDIT AGREEMENTS

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.


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DOMINION ENERGY

In March 2018, Dominion Energy replaced its two existing joint revolving credit facilities with a $6.0 billion joint revolving credit facility. Commercial paper and letters of credit outstanding, as well as capacity available under credit facilities were as follows:


	Facility Limit		Outstanding Commercial Paper(1)		Outstanding Letters of Credit		Facility Capacity Available
(millions)
At December 31, 2018
Joint revolving credit facility(2)	$	6,000		$ 324		$88	$	5,588
At December 31, 2017
Joint revolving credit facility(3)	$	5,000		$3,298		$—	$	1,702
Joint revolving credit facility(3)		500		—		76		424
Total	$	5,500		$3,298		$76	$	2,126

(1)	The weighted-average interest rates of the outstanding commercial paper supported by Dominion Energy’s credit facilities were 2.93% and 1.61% at December 31, 2018 and 2017, respectively.

(2)	This credit facility matures in March 2023 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.

(3)	These credit facilities were replaced in March 2018 with a $6.0 billion joint revolving credit facility. The facilities were scheduled to mature in April 2020 and were used to support bank borrowings and the issuance of commercial paper, as well as to support up to a combined $2.0 billion of letters of credit.

In connection with the SCANA Combination, Dominion Energy intends to terminate SCANA, SCE&G and PSNC’s existing credit facilities and add SCE&G as a co-borrower to its $6.0 billion joint revolving credit facility in the first quarter of 2019 once certain regulatory approvals are obtained. In January 2019, Virginia Power and SCE&G, as co-borrowers, filed with the Virginia Commission and the South Carolina Commission, respectively, for approval. In February 2019, the Virginia Commission approved the request.

Questar Gas’ short-term financing is supported through its access as co-borrower to the joint revolving credit facility discussed above with Dominion Energy, Virginia Power and Dominion Energy Gas. At December 31, 2018, the 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 had an original stated maturity date of December 2017 with automatic one-year renewals through the maturity of the SBL Holdco term loan agreement in 2023. Dominion Solar Projects III, Inc. has $25 million of credit facilities which had an original stated maturity date of May 2018 with automatic one-year renewals through the maturity of the Dominion Solar Projects III, Inc. term loan agreement in 2024. At December 31, 2018, no amounts were outstanding under either of these facilities.

In February and June 2018, Dominion Energy borrowed $950 million and $500 million, respectively, under 364-Day

Term Loan Agreements that bore interest at a variable rate. In September 2018, the principal outstanding plus accrued interest for both borrowings was repaid.

In March 2018, Dominion Energy Midstream entered into a $500 million revolving credit facility. The credit facility was scheduled to mature in March 2021, bore interest at a variable rate, and was used to support bank borrowings and the issuance of commercial paper, as well as to support up to $250 million of letters of credit. At December 31, 2018, Dominion Energy Midstream had $73 million outstanding under this credit facility. In February 2019, Dominion Energy Midstream terminated the facility subsequent to repaying the outstanding balance, plus accrued interest.

In October 2018, Dominion Energy entered into a credit agreement, which allows Dominion Energy to issue up to approximately $21 million in letters of credit. The facility terminates in June 2020. At December 31, 2018, Dominion Energy had $21 million in letters of credit outstanding under this agreement.

VIRGINIA POWER

In March 2018, Dominion Energy replaced its two existing joint revolving credit facilities with a $6.0 billion joint revolving credit facility. Virginia Power’s short-term financing is supported through its access as co-borrower to the joint revolving credit facility. The credit facility can be used for working capital, as support for the combined commercial paper programs of the Companies and for other general corporate purposes.

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		Outstanding Commercial Paper(1)		Outstanding Letters of Credit
(millions)
At December 31, 2018
Joint revolving credit facility(2)		$6,000		$314		$16
At December 31, 2017
Joint revolving credit facility(3)		$5,000		$542		$—
Joint revolving credit facility(3)		500		—		—
Total		$5,500		$542		$—

(1)	The weighted-average interest rates of the outstanding commercial paper supported by these credit facilities were 2.94% and 1.65% at December 31, 2018 and 2017, respectively.

(2)

The full amount of the facility is available to Virginia Power, less any amounts outstanding to co-borrowers Dominion Energy, Dominion Energy Gas and Questar Gas. The sub-limit for Virginia Power is set within the facility limit but can be changed at the option of the Companies multiple times per year. At December 31, 2018, the sub-limit for Virginia Power was $1.5 billion. If Virginia Power has liquidity needs in excess of its sub-limit, the sub-limit may be changed or such needs may be satisfied through short-term intercompany borrowings from Dominion Energy. This credit facility matures in March 2023 and can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $2.0 billion (or the sub-limit, whichever is less) of letters of credit.

(3)

These facilities were replaced in March 2018 with a $6.0 billion joint revolving credit facility. The full amount of the facilities was available to Virginia Power, less any amounts outstanding to co-borrowers Dominion Energy, Dominion Energy Gas and Questar Gas. These facilities were scheduled to mature in April 2020 and were 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.


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Combined Notes to Consolidated Financial Statements, Continued

In addition to the credit facility commitments mentioned above, Virginia Power also had a $100 million credit facility with a maturity date of April 2020. In March 2018, Virginia Power redeemed its variable rate tax-exempt financings supported by this credit facility and terminated the facility.

DOMINION ENERGY GAS

In March 2018, Dominion Energy replaced its two existing joint revolving credit facilities with a $6.0 billion joint revolving credit facility. Dominion Energy Gas’ short-term financing is supported by its access as co-borrower to the joint revolving credit facility. The credit facility can be used for working capital, as support for the combined commercial paper programs of the Companies and for other general corporate purposes.

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		Outstanding Commercial Paper(1)		Outstanding Letters of Credit
(millions)
At December 31, 2018
Joint revolving credit facility(2)		$1,500		$ 10		$—
At December 31, 2017
Joint revolving credit facility(3)		$1,000		$629		$—
Joint revolving credit facility(3)		500		—		—
Total		$1,500		$629		$—

(1)	The weighted-average interest rates of the outstanding commercial paper supported by these credit facilities were 2.58% and 1.57% at December 31, 2018 and 2017, respectively.

(2)

A maximum of $1.5 billion of the facility is available to Dominion Energy Gas, assuming adequate capacity is available after giving effect to uses by co-borrowers Dominion Energy, Virginia Power and Questar Gas. The sub-limit for Dominion Energy Gas is set within the facility limit but can be changed at the option of the Companies multiple times per year. At December 31, 2018, the sub-limit for Dominion Energy Gas was $750 million. If Dominion Energy Gas has liquidity needs in excess of its sub-limit, the sub-limit may be changed or such needs may be satisfied through short-term intercompany borrowings from Dominion Energy. This credit facility matures in March 2023 and can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion (or the sub-limit, whichever is less) of letters of credit.

(3)

These facilities were replaced in March 2018 with a $6.0 billion joint revolving credit facility. A maximum of a combined $1.5 billion of the facilities was available to Dominion Energy Gas, assuming adequate capacity was available after giving effect to uses by co-borrowers Dominion Energy, Virginia Power and Questar Gas. These credit facilities were scheduled to mature in April 2020 and were 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.


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NOTE 17. LONG-TERM DEBT


At December 31,	2018 Weighted- average Coupon(1)			2018			2017
(millions, except percentages)
Dominion Energy Gas Holdings, LLC:
Unsecured Senior Notes:
Variable rate, due 2021		3.39	%	$	500		$	—
2.5% to 3.55%, due 2019 to 2023		2.90	%		1,800			1,800
3.317% to 4.8%, due 2024 to 2044(2)		4.12	%		1,787			1,800
Dominion Energy Gas Holdings, LLC total principal				$	4,087		$	3,600
Securities due within one year		2.50	%		(449	)		—
Unamortized discount and debt issuance costs					(29	)		(30	)
Dominion Energy Gas Holdings, LLC total long-term debt				$	3,609		$	3,570
Virginia Electric and Power Company:
Unsecured Senior Notes:
1.2% to 5.4%, due 2018 to 2023		3.35	%	$	1,800		$	2,650
2.95% to 8.875%, due 2024 to 2048		4.61	%		9,290			7,990
Tax-Exempt Financings(3):
Variable rates, due 2024 to 2027					—			100
1.75% to 5.6%, due 2023 to 2041		2.18	%		664			678
Virginia Electric and Power Company total principal				$	11,754		$	11,418
Securities due within one year		5.00	%		(350	)		(850	)
Unamortized discount, premium and debt issuances costs, net					(83	)		(72	)
Virginia Electric and Power Company total long-term debt				$	11,321		$	10,496
Dominion Energy, Inc.:
Unsecured Senior Notes(4):
Variable rates, due 2019 and 2020		3.23	%	$	800		$	800
1.5% to 6.4%, due 2018 to 2022		2.75	%		2,550			5,800
2.85% to 7.0%, due 2024 to 2044		4.81	%		4,849			5,049
Unsecured Junior Subordinated Notes:
2.579% to 4.104%, due 2019 to 2021		3.08	%		2,100			2,100
Payable to Affiliated Trust, 8.4%, due 2031		8.40	%		10			10
Enhanced Junior Subordinated Notes:
5.25% and 5.75%, due 2054 and 2076		5.48	%		1,485			1,485
Variable rates, due 2066		5.26	%		422			422
Remarketable Subordinated Notes, 2.0%, due 2021 and 2024		2.00	%		1,400			1,400
Unsecured Debentures and Senior Notes(5):
6.8% and 6.875%, due 2026 and 2027		6.81	%		89			89
Unsecured Senior and Medium-Term Notes(6):
5.31% and 6.3%, due 2018					—			120
2.98% to 7.20%, due 2024 to 2051		4.25	%		750			600
Secured Senior Notes, 4.82%, due 2042(7)		4.82	%		362			—
Term Loans, variable rates, due 2023 and 2024(8)		4.85	%		582			638
Tax-Exempt Financing, 1.55%, due 2033(9)		1.55	%		27			27
Capital leases, 4.14% to 6.04%, due 2019 to 2029		5.99	%		39			—
Dominion Energy Midstream Partners, LP:
Term Loans, variable rates, due 2019 and 2021(10)(11)		4.13	%		3,300			300
Revolving Credit Agreement, variable rates, due 2021(11)		3.55	%		73			—
Unsecured Senior and Medium-Term Notes, 5.83% and 6.48%, due 2018(12)					—			255
Unsecured Senior Notes, 3.53% to 4.875%, due 2028 to 2041(12)		4.23	%		430			180
Dominion Energy Gas Holdings, LLC total principal (from above)					4,087			3,600
Virginia Electric and Power Company total principal (from above)					11,754			11,418
Dominion Energy, Inc. total principal				$	35,109		$	34,293
Fair value hedge valuation(13)					(20	)		(22	)
Securities due within one year(14)(15)		3.23	%		(3,624	)		(3,078	)
Credit facility borrowings(11)		3.55	%		(73	)		—
Unamortized discount, premium and debt issuance costs, net					(248	)		(245	)
Dominion Energy, Inc. total long-term debt				$	31,144		$	30,948

(1)	Represents weighted-average coupon rates for debt outstanding as of December 31, 2018.


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Combined Notes to Consolidated Financial Statements, Continued

(2)	Amount includes foreign currency remeasurement adjustments.

(3)

These financings relate to certain pollution control equipment at Virginia Power’s generating facilities. In March 2018, Virginia Power redeemed certain variable rate tax-exempt financings supported by its $100 million credit facility and terminated the facility. In December 2018, Virginia Power redeemed its $14 million Economic Development Authority of the County of Chesterfield Solid Waste and Sewage Disposal Revenue Bonds due in 2031.

(4)	In November and December 2018, Dominion Energy redeemed certain senior notes prior to their stated maturity. See below for a discussion of the senior note redemptions.

(5)	Represents debt assumed by Dominion Energy from the merger of its former CNG subsidiary.

(6)	Represents debt obligations of Questar Gas. See Note 3 for more information.

(7)	Represents debt obligations of Eagle Solar. The debt is nonrecourse to Dominion Energy and is secured by Eagle Solar’s interest in certain merchant solar facilities.

(8)	Represents debt associated with SBL Holdco and Dominion Solar Projects III, Inc. The debt is nonrecourse to Dominion Energy and is secured by SBL Holdco and Dominion Solar Projects III, Inc.’s interest in certain merchant solar facilities.

(9)	Represents debt obligations of a DGI subsidiary.

(10)	Includes debt obligations of Cove Point that are secured by Dominion Energy’s common equity interest in Cove Point.

(11)	In February 2019, Dominion Energy Midstream repaid its $300 million variable rate term loan due in December 2019 and terminated the credit facility due in March 2021 subsequent to repaying the $73 million outstanding balance. As such, credit facility borrowings are presented within current liabilities in Dominion Energy’s Consolidated Balance Sheets at December 31, 2018.

(12)	Represents debt obligations of Dominion Energy Questar Pipeline. See Note 3 for more information.

(13)	Represents the valuation of certain fair value hedges associated with Dominion Energy’s fixed rate debt.

(14)	2017 excludes $250 million of Dominion Energy Questar Pipeline’s senior notes that matured in February 2018 using proceeds from the January 2018 issuance, through private placements, of $100 million and $150 million of senior notes that mature in 2028 and 2038, respectively.

(15)	Includes $20 million of estimated mandatory prepayments due within one year based on estimated cash flows in excess of debt service at SBL Holdco and Dominion Solar Projects III, Inc.

Based on stated maturity dates rather than early redemption dates that could be elected by instrument holders, the scheduled principal payments of long-term debt at December 31, 2018, were as follows:


	2019			2020			2021			2022			2023			Thereafter			Total
(millions, except percentages)
Dominion Energy Gas	$	450		$	700		$	500		$	—		$	650		$	1,787		$	4,087
Weighted-average Coupon		2.50	%		2.80	%		3.39	%					3.29	%		4.12	%
Virginia Power
Unsecured Senior Notes	$	350		$	—		$	—		$	750		$	700		$	9,290		$	11,090
Tax-Exempt Financings		—			—			—			—			40			624			664
Total	$	350		$	—		$	—		$	750		$	740		$	9,914		$	11,754
Weighted-average Coupon		5.00	%								3.15	%		2.87	%		4.45	%
Dominion Energy
Term Loans(1)(2)	$	336		$	35		$	3,035		$	34		$	273		$	169		$	3,882
Credit Facility Borrowings(2)		—			—			73			—			—			—			73
Unsecured Senior Notes		2,700			1,000			900			1,500			1,350			17,195			24,645
Secured Senior Notes		17			15			17			19			16			278			362
Tax-Exempt Financings		—			—			—			—			40			651			691
Unsecured Junior Subordinated Notes Payable to Affiliated Trusts		—			—			—			—			—			10			10
Unsecured Junior Subordinated Notes		550			1,000			550			—			—			—			2,100
Enhanced Junior Subordinated Notes		—			—			—			—			—			1,907			1,907
Remarketable Subordinated Notes		—			—			700			—			—			700			1,400
Capital leases		4			4			4			3			3			21			39
Total	$	3,607		$	2,054		$	5,279		$	1,556		$	1,682		$	20,931		$	35,109
Weighted-average Coupon		3.23	%		2.80	%		3.64	%		3.02	%		3.41	%		4.51	%

(1)	Excludes mandatory prepayments associated with SBL Holdco and Dominion Solar Projects III, Inc. based on cash flows in excess of debt service. At December 31, 2018, $20 million of estimated mandatory prepayments due within one year were included in securities due within one year in Dominion Energy’s Consolidated Balance Sheets.

(2)	In February 2019, Dominion Energy Midstream repaid its $300 million variable rate term loan due in December 2019 and terminated the credit facility due in March 2021 subsequent to repaying the $73 million outstanding balance. As such, credit facility borrowings are presented within current liabilities in Dominion Energy’s Consolidated Balance Sheets at December 31, 2018.

The Companies’ short-term credit facility and long-term debt agreements contain customary covenants and default provisions. As of December 31, 2018, there were no events of default under these covenants.

Senior Note Redemptions

In November 2018 and December 2018, Dominion Energy redeemed the following outstanding series of senior notes: 2011 Series A 4.45% Senior Notes due 2021, 2014 Series B 2.50%

Senior Notes due 2019, 2014 Series C 3.625% Senior Notes due 2024 and 2018 Series A Floating Rate Senior Notes due 2020 with an aggregate outstanding principal of $2.2 billion. The aggregate redemption price paid was $2.2 billion and represents the principal amount outstanding, accrued and unpaid interest and the applicable make-whole premium of $34 million. Total charges of $69 million, including the make-whole premium, were recognized and recorded in interest expense in Dominion Energy’s Consolidated Statements of Income.


158

Enhanced Junior Subordinated Notes

In June 2006 and September 2006, Dominion Energy issued $300 million of June 2006 hybrids and $500 million of September 2006 hybrids, respectively. The June 2006 hybrids bear interest at three-month LIBOR plus 2.825%, reset quarterly. Previously, interest was fixed at 7.5% per year. The September 2006 hybrids bear interest at the three-month LIBOR plus 2.3%, reset quarterly.

In October 2014, Dominion Energy issued $685 million of October 2014 hybrids that will bear interest at 5.75% per year until October 1, 2024. Thereafter, they will bear interest at the three-month LIBOR plus 3.057%, reset quarterly.

Dominion Energy may defer interest payments on the hybrids on one or more occasions for up to 10 consecutive years. If the interest payments on the hybrids are deferred, Dominion Energy may not make distributions related to its capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments during the deferral period. Also, during the deferral period, Dominion Energy may not make any payments on or redeem or repurchase any debt securities that are equal in right of payment with, or subordinated to, the hybrids.

Dominion Energy executed RCCs in connection with its issuance of the June 2006 hybrids and the September 2006 hybrids. Under the terms of the RCCs, Dominion Energy covenants to and for the benefit of designated covered debtholders, as may be designated from time to time, that Dominion Energy shall not redeem, repurchase, or defease all or any part of the hybrids, and shall not cause its majority owned subsidiaries to purchase all or any part of the hybrids, on or before their applicable RCC termination date, unless, subject to certain limitations, during the 180 days prior to such activity, Dominion Energy has received a specified amount of proceeds as set forth in the RCCs from the sale of qualifying securities that have equity-like characteristics that are the same as, or more equity-like than the applicable characteristics of the hybrids at that time, as more fully described in the RCCs. In September 2011, Dominion Energy amended the RCCs of the June 2006 hybrids and September 2006 hybrids to expand the measurement period for consideration of proceeds from the sale of common stock issuances from 180 days to 365 days. The proceeds Dominion Energy receives from the replacement offering, adjusted by a predetermined factor, must equal or exceed the redemption or repurchase price.

In the first quarter of 2016, Dominion Energy purchased and cancelled $38 million and $4 million of the June 2006 hybrids and the September 2006 hybrids, respectively. In July 2016, Dominion Energy launched a tender offer to purchase up to $200 million in aggregate of additional June 2006 hybrids and September 2006 hybrids, which expired on August 1, 2016. In connection with the tender offer, Dominion Energy purchased and cancelled $125 million and $74 million of the June 2006 hybrids and the September 2006 hybrids, respectively. All purchases were conducted in compliance with the applicable RCC. Also in July 2016, Dominion Energy issued $800 million of 5.25% July 2016 hybrids. The proceeds were used for general corporate purposes, including to finance the tender offer. The July 2016 hybrids are listed on the NYSE under the symbol DRUA.

Remarketable Subordinated Notes

In June 2013, Dominion Energy issued $550 million of 2013 Series A 6.125% Equity Units and $550 million of 2013 Series B 6.0% Equity Units, initially in the form of Corporate Units. In July 2014, Dominion Energy issued $1.0 billion of 2014 Series A 6.375% Equity Units, initially in the form of Corporate Units. The Corporate Units were listed on the NYSE under the symbols DCUA, DCUB and DCUC respectively.

Each Corporate Unit consisted of a stock purchase contract and 1/20 interest in a RSN issued by Dominion Energy. The stock purchase contracts obligated the holders to purchase shares of Dominion Energy common stock at a future settlement date prior to the relevant RSN maturity date. The purchase price paid under the stock purchase contracts was $50 per Corporate Unit and the number of shares purchased was determined under a formula based upon the average closing price of Dominion Energy common stock near the settlement date. The RSNs were pledged as collateral to secure the purchase of common stock under the related stock purchase contracts.

In May 2017, Dominion Energy successfully remarketed the $1.0 billion 2014 Series A 1.50% RSNs due 2020 pursuant to the terms of the related 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. In March 2016 and May 2016, Dominion Energy successfully remarketed the $550 million 2013 Series A 1.07% RSNs due 2021 and the $550 million 2013 Series B 1.18% RSNs due 2019, respectively, pursuant to the terms of the related 2013 Equity Units. In connection with the remarketings, the interest rate on the Series A and Series B junior subordinated notes was reset to 4.104% and 2.962%, respectively, 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 December 31, 2018, the securities are included in junior subordinated notes in Dominion Energy’s Consolidated Balance Sheets. Dominion Energy did not receive any proceeds from the remarketings. Remarketing proceeds belonged to the investors holding the related equity units and were temporarily used to purchase a portfolio of treasury securities. Upon maturity of each portfolio, the proceeds were applied on behalf of investors on the related stock purchase contract settlement date to pay the purchase price to Dominion Energy for issuance of 12.5 million shares of its common stock in July 2017 and 8.5 million shares of its common stock in both April 2016 and July 2016. See Issuance of Common Stock below for a description of common stock issued by Dominion Energy under the stock purchase contracts.

In August 2016, Dominion Energy issued $1.4 billion of 2016 Series A 6.75% Equity Units, initially in the form of Corporate Units. The Corporate Units are listed on the NYSE under the symbol DCUD. The net proceeds from the 2016 Equity Units were used to finance the Dominion Energy Questar Combination. See Note 3 for more information.

Each 2016 Series A Corporate Unit consists of a stock purchase contract, a 1/40 interest in a 2016 Series A-1 RSN issued by Dominion Energy and a 1/40 interest in a 2016 Series A-2 RSN issued by Dominion Energy. The stock purchase contracts obli-


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Combined Notes to Consolidated Financial Statements, Continued

gate the holders to purchase shares of Dominion Energy common stock at a future settlement date prior to the relevant RSN maturity date. The purchase price to be paid under the stock purchase contracts is $50 per Corporate Unit and the number of shares to be purchased will be determined under a formula based upon the average closing price of Dominion Energy common stock near the settlement date. The RSNs are pledged as collateral to secure the purchase of common stock under the related stock purchase contracts.

Dominion Energy makes quarterly interest payments on the RSNs and quarterly contract adjustment payments on the stock purchase contracts, at the rates described below. Dominion Energy may defer payments on the stock purchase contracts and the RSNs for one or more consecutive periods but generally not beyond the purchase contract settlement date. If payments are deferred, Dominion Energy may not make any cash distributions related to its capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments. Also, during the deferral period, Dominion Energy may not make any payments on or redeem or repurchase any debt securities that are equal in right of payment with, or subordinated to, the RSNs.

Dominion Energy has recorded the present value of the stock purchase contract payments as a liability offset by a charge to

equity. Interest payments on the RSNs are recorded as interest expense and stock purchase contract payments are charged against the liability. Accretion of the stock purchase contract liability is recorded as imputed interest expense. In calculating diluted EPS, Dominion Energy applies the treasury stock method to the equity units.

Pursuant to the terms of the 2016 Equity Units, Dominion Energy expects to remarket both the 2016 Series A-1 and 2016 Series A-2 RSNs during the second or third quarter of 2019. Following a successful remarketing, the interest rate on the RSNs will be reset, interest will be payable on a semi-annual basis and Dominion Energy will cease to have the ability to redeem the RSNs at its option or defer interest payments. Proceeds of each remarketing will belong to the investors in the related equity units and will be held and applied on their behalf at the settlement date of the related stock purchase contracts to pay the purchase price to Dominion Energy for issuance of its common stock.

Under the terms of the stock purchase contracts, assuming no anti-dilution or other adjustments, Dominion Energy will issue between 15.1 million and 18.9 million shares in August 2019. A total of 23.1 million shares of Dominion Energy’s common stock has been reserved for issuance in connection with the stock purchase contracts.

Selected information about Dominion Energy’s equity units is presented below:


Issuance Date	Units Issued		Total Net Proceeds		Total Long-term Debt		RSN Annual Interest Rate			Stock Purchase Contract Annual Rate			Stock Purchase Contract Liability(1)		Stock Purchase Settlement Date
(millions, except interest rates)
8/15/2016(2)		28	$	1,374.8		$1,400.0		2.000	%(3)		4.750	%		$190.6		8/15/2019

(1)	Payments of $64 million and $101 million were made in 2018 and 2017, respectively, including payments for the remarketed 2014 Series A notes. The stock purchase contract liability was $47 million and $111 million at December 31, 2018 and 2017, respectively.

(2)	The maturity dates of the $700 million Series A-1 RSNs and $700 million Series A-2 RSNs are August 15, 2021 and August 15, 2024, respectively.

(3)	Annual interest rate applies to each of the Series A-1 RSNs and Series A-2 RSNs.


160

NOTE 18. PREFERRED STOCK

Dominion Energy is authorized to issue up to 20 million shares of preferred stock; however, none were issued and outstanding at December 31, 2018 or 2017.

Virginia Power is authorized to issue up to 10 million shares of preferred stock, $100 liquidation preference; however, none were issued and outstanding at December 31, 2018 or 2017.

NOTE 19. EQUITY

Issuance of Common Stock

DOMINION ENERGY

Dominion Energy maintains Dominion Energy Direct® and a number of employee savings plans through which contributions may be invested in Dominion Energy’s common stock. These shares may either be newly issued or purchased on the open market with proceeds contributed to these plans. Currently, Dominion Energy is issuing new shares of common stock for these direct stock purchase plans.

During 2018, Dominion Energy received cash proceeds, net of fees and commissions, of $2.5 billion from the issuance of approximately 36 million shares of common stock through various programs including the forward sale agreements described below resulting in approximately 681 million shares of common stock outstanding at December 31, 2018. These proceeds include cash of $315 million received from the issuance of 4.5 million of such shares through Dominion Energy Direct® and employee savings plans.

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 and received proceeds of $1.0 billion.

In both April 2016 and July 2016, Dominion Energy issued 8.5 million shares under the related stock purchase contracts entered into as part of Dominion Energy’s 2013 Equity Units and received $1.1 billion of total proceeds. Additionally, Dominion Energy completed a market issuance of equity in April 2016 of 10.2 million shares and received proceeds of $756 million through a registered underwritten public offering. A portion of the net proceeds was used to finance the Dominion Energy Questar Combination. See Note 3 for more information.

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 NYSE 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. In January 2018, Dominion Energy provided sales instructions to one of the sales agents and issued 6.6 million shares through at-the-market issuances and received cash proceeds of $495 million, net of fees and commissions paid of $5 million. Following these issuances, Dominion Energy had no remaining ability to issue stock under

the 2017 sales agency agreements and completed the program. In February 2018, Dominion Energy entered into six separate sales agency agreements to effect sales under a new at-the-market program pursuant to which it may offer from time to time up to $1.0 billion aggregate amount of its common stock. These agreements replaced the sales agency agreements entered into by Dominion Energy in June 2017. Sales of common stock can be made by means of private negotiated transactions, as transactions on the NYSE 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. In the fourth quarter of 2018, Dominion Energy provided sales instructions to two of the sales agents and issued 2.7 million shares through at-the-market issuances and received cash proceeds of $197 million, net of fees and commissions paid of $2 million. Following these issuances, Dominion Energy has $801 million of remaining ability to issue stock under the sales agency agreements.

Dominion Energy entered in March 2018, and closed in April 2018, separate forward sale agreements with Goldman Sachs & Co. LLC and Credit Suisse Capital LLC, as forward purchasers, and an underwriting agreement with Credit Suisse Securities (USA) LLC and Goldman Sachs & Co. LLC, as representatives of the several underwriters named therein, relating to an aggregate of 20 million shares of Dominion Energy common stock. The underwriting agreement granted the underwriters a 30-day option to purchase up to an additional three million shares of Dominion Energy common stock, which the underwriters exercised with respect to approximately 2.1 million shares in April 2018. Dominion Energy entered into separate forward sale agreements with the forward purchasers with respect to the additional shares. In December 2018, Dominion Energy received proceeds of $1.4 billion (after deducting underwriting discounts, but before deducting expenses, and subject to forward price adjustments under the forward sale agreements) upon the physical settlement of 22.1 million shares.

See Note 3 to the Consolidated Financial Statements for information on the issuance of Dominion Energy common stock in January 2019 in connection with the SCANA Combination. Also in January 2019, Dominion Energy acquired all outstanding partnership interests of Dominion Energy Midstream not owned by Dominion Energy through the issuance of common stock as noted below.

VIRGINIA POWER

In 2018, 2017 and 2016, Virginia Power did not issue any shares of its common stock to Dominion Energy.

Shares Reserved for Issuance

Dominion Energy has approximately 76 million shares reserved and available for issuance for Dominion Energy Direct®, employee stock awards, employee savings plans, director stock compensation plans and issuances in connection with stock purchase contracts and the at-the-market program. See Note 17 for more information.

Repurchase of Common Stock

Dominion Energy did not repurchase any shares in 2018 or 2017 and does not plan to repurchase shares during 2019, except for shares tendered by employees to satisfy tax withholding obliga-


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Combined Notes to Consolidated Financial Statements, Continued

tions on vested restricted stock, which do not count against its stock repurchase authorization.

Purchase of Dominion Energy Midstream Units

In September 2015, Dominion Energy initiated a program to purchase from the market up to $50 million of common units representing limited partner interests in Dominion Energy Midstream, which expired in September 2016. Dominion Energy purchased approximately 658,000 common units for $17 million for the year ended December 31, 2016.

In January 2019, Dominion Energy acquired all outstanding partnership interests of Dominion Energy Midstream not owned by Dominion Energy through the issuance of 22.5 million shares of common stock valued at $1.6 billion. The merger was accounted for by Dominion Energy following the guidance for a change in a parent company’s ownership interest in a consolidated subsidiary. Because Dominion Energy controls Dominion Energy Midstream both before and after the merger, the changes in Dominion Energy’s ownership interest in Dominion Energy Midstream were accounted for as an equity transaction and no gain or loss will be recognized. The tax effect of the merger will be presented in common stock.

Issuance of Dominion Energy Midstream Units

In 2017, Dominion Energy Midstream received $18 million of proceeds from the issuance of common units through its at-the-market program.

In 2016, Dominion Energy Midstream received $482 million of proceeds from the issuance of common units and $490 million of proceeds from the issuance of convertible preferred units. The net proceeds were primarily used to finance a portion of the acquisition of Dominion Energy Questar Pipeline from Dominion Energy. See Note 3 for more information.

The holders of the convertible preferred units were entitled to receive cumulative quarterly distributions payable in cash or additional convertible preferred units, subject to certain conditions. The units were convertible into Dominion Energy Midstream common units on a one-for-one basis, subject to certain adjustments, (i) in whole or in part at the option of the unitholders any time after December 1, 2018 or, (ii) in whole or in part at Dominion Energy Midstream’s option, subject to certain conditions, any time after December 1, 2019. Immediately prior to the closing of Dominion Energy’s acquisition of the outstanding interest in Dominion Energy Midstream noted above, each convertible preferred unit was converted into common units representing limited partner interests in Dominion Energy Midstream in accordance with the terms of Dominion Energy Midstream’s partnership agreement.

In May 2018, all of the subordinated units of Dominion Energy Midstream held by Dominion Energy were converted into common units on a 1:1 ratio following the payment of Dominion Energy Midstream’s distribution for the first quarter of 2018. In June 2018, Dominion Energy, as general partner, exercised an incentive distribution right reset as defined in Dominion Energy Midstream’s partnership agreement and received 26.7 million common units representing limited partner interests in Dominion Energy Midstream. As a result of the increase in its ownership interest in Dominion Energy Midstream, Dominion Energy recorded a decrease in noncontrolling interest, and a correspond-

ing increase in shareholders’ equity, of $375 million reflecting the change in the carrying value of the interest in the net assets of Dominion Energy Midstream held by others.

Accumulated Other Comprehensive Income (Loss)

Presented in the table below is a summary of AOCI by component:


At December 31,	2018			2017
(millions)
Dominion Energy
Net deferred losses on derivatives-hedging activities, net of $79 and $188 tax	$	(234	)	$	(301	)
Net unrealized gains on nuclear decommissioning trust funds, net of $— and $(419) tax		2			747
Net unrecognized pension and other postretirement benefit costs, net of $519 and $692 tax		(1,465	)		(1,101	)
Other comprehensive loss from equity method investees, net of $— and $2 tax		(2	)		(3	)
Total AOCI, including noncontrolling interest	$	(1,699	)	$	(658	)
Less other comprehensive income attributable to noncontrolling interest		1			1
Total AOCI, excluding noncontrolling interest	$	(1,700	)	$	(659	)
Virginia Power
Net deferred losses on derivatives-hedging activities, net of $4 and $8 tax	$	(13	)	$	(12	)
Net unrealized gains on nuclear decommissioning trust funds, net of $— and $(47) tax		1			74
Total AOCI	$	(12	)	$	62
Dominion Energy Gas
Net deferred losses on derivatives-hedging activities, net of $8 and $15 tax	$	(25	)	$	(23	)
Net unrecognized pension costs, net of $56 and $59 tax		(144	)		(75	)
Total AOCI	$	(169	)	$	(98	)


162

DOMINION ENERGY

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


	Deferred gains and losses on derivatives- hedging activities			Unrealized gains and losses on investment securities			Unrecognized pension and other postretirement benefit costs			Other comprehensive loss from equity method investees			Total
(millions)
Year Ended December 31, 2018
Beginning balance		$(302	)		$ 747			$(1,101	)		$(3	)		$(659	)
Other comprehensive income before reclassifications: gains (losses)		30			(18	)		(215	)		1			(202	)
Amounts reclassified from AOCI: (gains) losses(1)		102			5			78			—			185
Net current period other comprehensive income (loss)		132			(13)			(137	)		1			(17	)
Cumulative-effect of changes in accounting principle		(64	)		(732)			(227	)		—			(1,023	)
Less other comprehensive income (loss) attributable to noncontrolling interest		1			—			—			—			1
Ending balance		$(235	)		$2			$(1,465	)		$(2	)		$(1,700	)
Year Ended December 31, 2017
Beginning balance		$(280	)		$ 569			$(1,082	)		$(6	)		$ (799	)
Other comprehensive income before reclassifications: gains (losses)		8			215			(69	)		3			157
Amounts reclassified from AOCI: (gains) losses(1)		(29	)		(37	)		50			—			(16	)
Net current period other comprehensive income (loss)		(21	)		178			(19	)		3			141
Less other comprehensive income (loss) attributable to noncontrolling interest		1			—			—			—			1
Ending balance		$(302	)		$ 747			$(1,101	)		$(3	)		$ (659	)

(1)	See table below for details about these reclassifications.

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


Details about AOCI components	Amounts reclassified from AOCI			Affected line item in the Consolidated Statements of Income
(millions)
Year Ended December 31, 2018
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts		$90			Operating revenue
		(14	)		Electric fuel and other energy-related purchases
Interest rate contracts		48			Interest and related charges
Foreign currency contracts		13			Other Income
Total		137
Tax		(35	)		Income tax expense
Total, net of tax		$102
Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities		$7			Other income
Total		7
Tax		(2	)		Income tax expense
Total, net of tax		$5
Unrecognized pension and other postretirement benefit costs:
Amortization of prior-service costs (credits)		$(21	)		Other income
Amortization of actuarial losses		120			Other income
Total		99
Tax		(21	)		Income tax expense
Total, net of tax		$78
Year Ended December 31, 2017
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts		$(81	)		Operating revenue
		2			Purchased gas
Interest rate contracts		52			Interest and related charges
Foreign currency contracts		(20	)		Other Income
Total		(47	)
Tax		18			Income tax expense
Total, net of tax		$(29	)
Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities		$(81	)		Other income
Impairment		23			Other income
Total		(58	)
Tax		21			Income tax expense
Total, net of tax		$(37	)
Unrecognized pension and other postretirement benefit costs:
Prior-service costs (credits)		$(21	)		Other income
Actuarial losses		103			Other income
Total		82
Tax		(32	)		Income tax expense
Total, net of tax		$50


				163

Combined Notes to Consolidated Financial Statements, Continued

VIRGINIA POWER

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


	Deferred gains and losses on derivatives- hedging activities			Unrealized gains and losses on investment securities			Total
(millions)

Year Ended December 31, 2018
Beginning balance	$	(12)		$	74			$ 62
Other comprehensive income before reclassifications: gains (losses)		1			—			1
Amounts reclassified from AOCI: (gains) losses(1)		1			—			1
Net current period other comprehensive income (loss)		2			—			2
Cumulative-effect of changes in accounting principle		(3	)		(73	)		(76	)
Ending balance	$	(13	)	$	1			$(12	)
Year Ended December 31, 2017
Beginning balance	$	(8	)	$	54			$ 46
Other comprehensive income before reclassifications: gains (losses)		(5	)		24			19
Amounts reclassified from AOCI: gains (losses)(1)		1			(4	)		(3	)
Net current period other comprehensive income (loss)		(4	)		20			16
Ending balance	$	(12	)	$	74			$ 62

(1)	See table below for details about these reclassifications.

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


Details about AOCI components	Amounts reclassified from AOCI			Affected line item in the Consolidated Statements of Income
(millions)

Year Ended December 31, 2018
(Gains) losses on cash flow hedges:
Interest rate contracts		$ 1			Interest and related charges
Total		1
Tax		—			Income tax expense
Total, net of tax		$ 1
Year Ended December 31, 2017
(Gains) losses on cash flow hedges:
Interest rate contracts		$ 1			Interest and related charges
Total		1
Tax		—			Income tax expense
Total, net of tax		$ 1
Unrealized (gains) and losses on investment securities:
Realized (gain) loss on sale of securities		$(9	)		Other income
Impairment		2			Other income
Total		(7	)
Tax		3			Income tax expense
Total, net of tax		$(4	)

DOMINION ENERGY GAS

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


	Deferred gains and losses on derivatives- hedging activities			Unrecognized pension and other postretirement benefit costs			Total
(millions)

Year Ended December 31, 2018
Beginning balance		$(23	)		$ (75	)	$	(98	)
Other comprehensive income before reclassifications: gains (losses)		(17	)		(52	)		(69	)
Amounts reclassified from AOCI: (gains) losses(1)		20			4			24
Net current period other comprehensive income (loss)		3			(48	)		(45	)
Cumulative-effect of changes in accounting principle		(5	)		(21	)		(26	)
Ending balance		$(25	)		$(144	)	$	(169	)
Year Ended December 31, 2017
Beginning balance		$(24	)		$ (99	)	$	(123	)
Other comprehensive income before reclassifications: gains (losses)		5			20			25
Amounts reclassified from AOCI: gains (losses)(1)		(4	)		4			—
Net current period other comprehensive income (loss)		1			24			25
Ending balance		$(23	)		$ (75	)	$	(98	)

(1)	See table below for details about these reclassifications.


164

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


Details about AOCI components	Amounts reclassified from AOCI			Affected line item in the Consolidated Statements of Income
(millions)

Year Ended December 31, 2018
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts		$ 8		Operating revenue
Interest rate contracts		6		Interest and related charges
Foreign currency contracts		13		Other income
Total		27
Tax		(7	)	Income tax expense
Total, net of tax		$ 20
Unrecognized pension costs:
Actuarial losses		$ 6		Other income
Total		6
Tax		(2	)	Income tax expense
Total, net of tax		$ 4
Year Ended December 31, 2017
Deferred (gains) and losses on derivatives-hedging activities:
Commodity contracts		$ 8		Operating revenue
Interest rate contracts		5		Interest and related charges
Foreign currency contracts		(20	)	Other income
Total		(7	)
Tax		3		Income tax expense
Total, net of tax		$ (4	)
Unrecognized pension costs:
Actuarial losses		$ 6		Other income
Total		6
Tax		(2	)	Income tax expense
Total, net of tax		$ 4

Stock-Based Awards

The 2005 and 2014 Incentive Compensation Plans permit stock-based awards that include restricted stock, performance grants, goal-based stock, stock options, and stock appreciation rights. The Non-Employee Directors Compensation Plan permits grants of restricted stock and stock options. Under provisions of these plans, employees and non-employee directors may be granted options to purchase common stock at a price not less than its fair market value at the date of grant with a maximum term of eight years. Option terms are set at the discretion of the CGN Committee of the Board of Directors or the Board of Directors itself, as provided under each plan. No options are outstanding under either plan. At December 31, 2018, approximately 22 million shares were available for future grants under these plans.

Goal-based stock awards are granted in lieu of cash-based performance grants to certain officers who have not achieved a certain targeted level of share ownership. As of December 31, 2018, unrecognized compensation cost related to nonvested goal-based stock awards was immaterial.

Dominion Energy measures and recognizes compensation expense relating to share-based payment transactions over the

vesting period based on the fair value of the equity or liability instruments issued. Dominion Energy’s results for the years ended December 31, 2018, 2017 and 2016 include $48 million, $45 million, and $33 million, respectively, of compensation costs and $12 million, $16 million, and $11 million, respectively of income tax benefits related to Dominion Energy’s stock-based compensation arrangements. Stock-based compensation cost is reported in other operations and maintenance expense in Dominion Energy’s Consolidated Statements of Income. Excess Tax Benefits are classified as a financing cash flow.

RESTRICTED STOCK

Restricted stock grants are made to officers under Dominion Energy’s LTIP and may also be granted to certain key non-officer employees. The fair value of Dominion Energy’s restricted stock awards is equal to the closing price of Dominion Energy’s stock on the date of grant. New shares are issued for restricted stock awards on the date of grant and generally vest over a three-year service period. The following table provides a summary of restricted stock activity for the years ended December 31, 2018, 2017 and 2016:


	Shares			Weighted —average Grant Date Fair Value
	(thousands)
Nonvested at December 31, 2015		855			$66.16
Granted		372			71.67
Vested		(301	)		56.83
Cancelled and forfeited		(40	)		71.75
Nonvested at December 31, 2016		886			$71.40
Granted		454			74.24
Vested		(287	)		68.90
Cancelled and forfeited		(10	)		72.37
Nonvested at December 31, 2017		1,043			$73.32
Granted		534			72.92
Vested		(316	)		73.59
Cancelled and forfeited		(53	)		74.25
Nonvested at December 31, 2018		1,208			$73.03

As of December 31, 2018, unrecognized compensation cost related to nonvested restricted stock awards totaled $49 million and is expected to be recognized over a weighted-average period of 2.1 years. The fair value of restricted stock awards that vested was $23 million, $21 million, and $21 million in 2018, 2017 and 2016, respectively. Employees may elect to have shares of restricted stock withheld upon vesting to satisfy tax withholding obligations. The number of shares withheld will vary for each employee depending on the vesting date fair market value of Dominion Energy stock and the applicable federal, state and local tax withholding rates.

CASH-BASED PERFORMANCE GRANTS

Cash-based performance grants are made to Dominion Energy’s officers under Dominion Energy’s LTIP. The actual payout of cash-based performance grants will vary between zero and 200% of the targeted amount based on the level of performance metrics achieved.

In February 2016, a cash-based performance grant was made to officers. Payout of the performance grant occurred in January 2018 based on the achievement of two performance metrics during 2016 and 2017: TSR relative to that of companies listed as members of the Philadelphia Utility Index as of the end of the performance period and ROIC. The total of the payout under the grant was $12 million.


				165

Combined Notes to Consolidated Financial Statements, Continued

In February 2017, two cash-based performance grants were made to officers as Dominion Energy transitioned from a two-year performance period to a three-year performance period. Payout of the two-year grant occurred in January 2019 based on the achievement of two performance metrics during 2017 and 2018: TSR relative to that of companies that are members of Dominion Energy’s compensation peer group and ROIC with an additional partial payout based on Dominion Energy’s price-earnings ratio relative to that of the members of Dominion Energy’s compensation peer group. The total of the payout under the two-year grant was $13 million and a liability of $13 million had been accrued for this award. Payout of the three-year cash-based performance grant is expected to occur by March 15, 2020 based on the achievement of two performance metrics during 2017, 2018 and 2019: TSR relative to that of companies that are members of Dominion Energy’s compensation peer group and ROIC. There are additional opportunities to earn a portion of the awards based on Dominion Energy’s absolute TSR or relative price-earnings ratio performance. At December 31, 2018, the targeted amount of the three-year grant was $14 million and a liability of $10 million had been accrued for the award.

In February 2018, a cash-based performance grant was made to officers. Payout of the three-year cash-based performance grant is expected to occur by March 15, 2021 based on the achievement of two performance metrics during 2018, 2019 and 2020: TSR relative to that of companies that are members of Dominion Energy’s compensation peer group and ROIC. There are additional opportunities to earn a portion of the awards based on Dominion Energy’s absolute TSR or relative price-earnings ratio performance. At December 31, 2018, the targeted amount of the three-year grant was $16 million and a liability of $5 million had been accrued for this award.

NOTE 20. DIVIDEND RESTRICTIONS

The Virginia Commission may prohibit any public service company, including Virginia Power, from declaring or paying a dividend to an affiliate if found to be detrimental to the public interest. At December 31, 2018, the Virginia Commission had not restricted the payment of dividends by Virginia Power.

The North Carolina Commission, in its order approving the SCANA Combination, limited cumulative dividends payable to Dominion Energy by Virginia Power and PSNC to (i) the amount of retained earnings at closing of the SCANA Combination plus (ii) any future earnings recorded by Virginia Power and PSNC after such date. In addition, notice to the North Carolina Commission is required if payment of dividends causes the equity component of Virginia Power and PSNC’s capital structure to fall below 45%.

The Ohio Commission may prohibit any public service company, including East Ohio, from declaring or paying a dividend to an affiliate if found to be detrimental to the public interest. At December 31, 2018, the Ohio Commission had not restricted the payment of dividends by East Ohio.

Pursuant to the SCANA Merger Approval Order, the amount of any SCE&G dividends paid must be reasonable and consistent with the long-term payout ratio of the electric utility industry and gas distribution industry. There is no specific restriction on the payment of dividends by SCE&G.

The Utah Commission may prohibit any public service company, including Questar Gas, from declaring or paying a dividend to an affiliate if found to be detrimental to the public interest. At December 31, 2018, the Utah Commission had not restricted the payment of dividends by Questar Gas.

Certain agreements associated with the Companies’ credit facility contains restrictions on the ratio of debt to total capitalization. These limitations did not restrict the Companies’ ability to pay dividends or receive dividends from their subsidiaries at December 31, 2018.

In connection with the SCANA Combination, under the terms of the merger agreement, Dominion Energy could not declare, set aside or pay any dividends on, or make any other distributions (whether in cash, stock or property) in respect of, any of its capital stock, other than regular quarterly cash dividends from January 2018 through January 2019.

As part of the merger agreement with Dominion Energy Midstream from November 2018 through January 2019, Dominion Energy could not declare, set aside or pay any dividends on, or make any other distributions (whether in cash, stock or property) in respect of, any of its capital stock, other than regular quarterly cash dividends.

See Note 17 for a description of potential restrictions on dividend payments by Dominion Energy in connection with the deferral of interest payments on certain junior subordinated notes and equity units, initially in the form of corporate units.

NOTE 21. EMPLOYEE BENEFIT PLANS

Dominion Energy and Dominion Energy Gas—Defined Benefit Plans

Dominion Energy provides certain retirement benefits to eligible active employees, retirees and qualifying dependents. Dominion Energy Gas participates in a number of the Dominion Energy-sponsored retirement plans. Under the terms of its benefit plans, Dominion Energy reserves the right to change, modify or terminate the plans. From time to time in the past, benefits have changed, and some of these changes have reduced benefits.

Dominion Energy maintains qualified noncontributory defined benefit pension plans covering virtually all employees. Retirement benefits are based primarily on years of service, age and the employee’s compensation. Dominion Energy’s funding policy is to contribute annually an amount that is in accordance with the provisions of ERISA. The pension programs also provide benefits to certain retired executives under company-sponsored nonqualified employee benefit plans. The nonqualified plans are funded through contributions to grantor trusts. Dominion Energy also provides retiree healthcare and life insurance benefits with annual employee premiums based on several factors such as age, retirement date and years of service.

Pension benefits for Dominion Energy Gas employees not represented by collective bargaining units are covered by the Dominion Energy Pension Plan, a defined benefit pension plan sponsored by Dominion Energy that provides benefits to multiple Dominion Energy subsidiaries. Pension benefits for Dominion Energy Gas employees represented by collective bargaining units are covered by separate pension plans for East Ohio and, for DETI, a plan that provides benefits to employees of both DETI and Hope. Employee compensation is the basis for allocating


166

pension costs and obligations between DETI and Hope and determining East Ohio’s share of total pension costs.

Retiree healthcare and life insurance benefits for Dominion Energy Gas employees not represented by collective bargaining units are covered by the Dominion Energy Retiree Health and Welfare Plan, a plan sponsored by Dominion Energy that provides certain retiree healthcare and life insurance benefits to multiple Dominion Energy subsidiaries. Retiree healthcare and life insurance benefits for Dominion Energy Gas employees represented by collective bargaining units are covered by separate other postretirement benefit plans for East Ohio and, for DETI, a plan that provides benefits to both DETI and Hope. Employee headcount is the basis for allocating other postretirement benefit costs and obligations between DETI and Hope and determining East Ohio’s share of total other postretirement benefit costs.

Pension and other postretirement benefit costs are affected by employee demographics (including age, compensation levels and years of service), the level of contributions made to the plans and earnings on plan assets. These costs may also be affected by changes in key assumptions, including expected long-term rates of return on plan assets, discount rates, healthcare cost trend rates, mortality rates and the rate of compensation increases.

Dominion Energy uses December 31 as the measurement date for all of its employee benefit plans, including those in which Dominion Energy Gas participates. Dominion Energy uses the market-related value of pension plan assets to determine the expected return on plan assets, a component of net periodic pension cost, for all pension plans, including those in which Dominion Energy Gas participates. The market-related value recognizes changes in fair value on a straight-line basis over a four-year period, which reduces year-to-year volatility. Changes in fair value are measured as the difference between the expected and actual plan asset returns, including dividends, interest and realized and unrealized investment gains and losses. Since the market-related value recognizes changes in fair value over a four-year period, the future market-related value of pension plan assets will be impacted as previously unrecognized changes in fair value are recognized.

Dominion Energy’s pension and other postretirement benefit plans hold investments in trusts to fund employee benefit payments. Dominion Energy’s pension and other postretirement plan assets experienced aggregate actual returns (losses) of $(605) million and $1.6 billion in 2018 and 2017, respectively, versus expected returns of $806 million and $767 million, respectively. Dominion Energy Gas’ pension and other postretirement plan assets for employees represented by collective bargaining units experienced aggregate actual returns (losses) of $(129) million and $335 million in 2018 and 2017, respectively, versus expected returns of $178 million and $165 million, respectively. 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 such employee benefit plans and will be included in the determination of the amount of cash to be contributed to the employee benefit plans.

During 2016, Dominion Energy and Dominion Energy Gas (for employees represented by collective bargaining units) engaged their actuary to conduct an experience study of their employees demographics over a five-year period as compared to significant assumptions that were being used to determine pension and other

postretirement benefit obligations and periodic costs. These assumptions primarily included mortality, retirement rates, termination rates, and salary increase rates. The changes in assumptions implemented as a result of the experience study resulted in increases of $290 million and $38 million in the pension and other postretirement benefits obligations, respectively, at December 31, 2016 for Dominion Energy and $24 million and $9 million in the pension and other postretirement benefits obligations, respectively, at December 31, 2016 for Dominion Energy Gas. In addition, these changes increased net periodic benefit costs $42 million for Dominion Energy during 2017. The increase in net periodic benefit costs for Dominion Energy Gas during 2017 was immaterial.

PLAN AMENDMENTS AND REMEASUREMENTS

In the fourth quarter of 2017, Dominion Energy remeasured its pension and other postretirement benefit plans as a result of voluntary and involuntary separation programs at Dominion Energy Questar. The settlement and related remeasurement resulted in a reduction in the pension benefit obligation of approximately $75 million and an increase in the accumulated postretirement benefit obligation of approximately $2 million. The discount rates used for the 2017 pension cost and related settlement were 4.46% as of December 31, 2016, 4.51% as of January 31, 2017 and 4.05% as of June 30 and September 30, 2017. All other assumptions used were consistent with the measurement as of December 31, 2016.

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 and Dominion Energy Gas’ accumulated postretirement benefit obligation of $73 million and $61 million, respectively. As a result of regulatory accounting, the remeasurement had 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 consistent with the measurement as of December 31, 2016.

Also during the first quarter of 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 other operations and maintenance expense in their Consolidated Statements of Income.

In the third quarter of 2016, Dominion Energy 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 50 retirees effective April 1, 2017. The remeasurement resulted in a decrease in Dominion Energy’s accumulated postretirement benefit obligation of $37 million. The impact of the remeasurement on net periodic benefit credit was recognized prospectively from the remeasurement date and increased the net periodic benefit credit for 2016 by $9 million. The discount rate used for the remeasurement was 3.71% and the demographic and mortality assumptions were updated using plan-specific studies and mortality improvement scales. The expected long-term rate of return used was consistent with the measurement as of December 31, 2015.


				167

Combined Notes to Consolidated Financial Statements, Continued

FUNDED STATUS

The following table summarizes the changes in pension plan and other postretirement benefit plan obligations and plan assets and includes a statement of the plans’ funded status for Dominion Energy and Dominion Energy Gas (for employees represented by collective bargaining units):


	Pension Benefits						Other Postretirement Benefits
Year Ended December 31,	2018			2017			2018			2017
(millions, except percentages)
Dominion Energy
Changes in benefit obligation:
Benefit obligation at beginning of year	$	9,052		$	8,132		$	1,529		$	1,478
Service cost		157			138			27			26
Interest cost		337			345			56			60
Benefits paid		(358	)		(323	)		(87	)		(83	)
Actuarial (gains) losses during the year		(688	)		830			(158	)		119
Plan amendments(1)		—			5			(4	)		(73	)
Settlements and curtailments(2)		—			(75	)		—			2
Benefit obligation at end of year	$	8,500		$	9,052		$	1,363		$	1,529
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year	$	8,062		$	7,016		$	1,729		$	1,512
Actual return (loss) on plan assets		(513	)		1,327			(92	)		236
Employer contributions		6			118			12			13
Benefits paid		(358	)		(323	)		(68	)		(32	)
Settlements(2)		—			(76	)		—			—
Fair value of plan assets at end of year	$	7,197		$	8,062		$	1,581		$	1,729
Funded status at end of year	$	(1,303	)	$	(990	)	$	218		$	200
Amounts recognized in the Consolidated Balance Sheets at December 31:
Noncurrent pension and other postretirement benefit assets	$	1,003		$	1,117		$	276		$	261
Other current liabilities		(34	)		(8	)		(2	)		—
Noncurrent pension and other postretirement benefit liabilities		(2,272	)		(2,099	)		(56	)		(61	)
Net amount recognized	$	(1,303	)	$	(990	)	$	218		$	200
Significant assumptions used to determine benefit obligations as of December 31:
Discount rate		4.42%–4.43%			3.80%–3.81%			4.37%–4.38%			3.76%
Weighted average rate of increase for compensation		4.32%			4.09%			4.30%-4.55%			3.95%-4.11%
Dominion Energy Gas
Changes in benefit obligation:
Benefit obligation at beginning of year	$	773		$	683		$	290		$	320
Service cost		18			15			4			4
Interest cost		29			30			11			12
Benefits paid		(34	)		(33	)		(18	)		(19	)
Actuarial (gains) losses during the year		(56	)		78			(27	)		34
Plan amendments(1)		—			—			(4	)		(61	)
Benefit obligation at end of year	$	730		$	773		$	256		$	290
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year	$	1,803		$	1,542		$	333		$	299
Actual return (loss) on plan assets		(113	)		294			(16	)		41
Employer contributions		—			—			12			12
Benefits paid		(34	)		(33	)		(18	)		(19	)
Fair value of plan assets at end of year	$	1,656		$	1,803		$	311		$	333
Funded status at end of year	$	926		$	1,030		$	55		$	43
Amounts recognized in the Consolidated Balance Sheets at December 31:
Noncurrent pension and other postretirement benefit assets	$	926		$	1,030		$	63		$	57
Noncurrent pension and other postretirement benefit liabilities(3)		—			—			(8	)		(14	)
Net amount recognized	$	926		$	1,030		$	55		$	43
Significant assumptions used to determine benefit obligations as of December 31:
Discount rate		4.42	%		3.81	%		4.37	%		3.76	%
Weighted average rate of increase for compensation		4.55	%		4.11	%		n/a			n/a

(1)	2017 amounts relate primarily to a plan amendment that changed post-65 retiree medical coverage for certain current and future Local 69 retirees effective July 1, 2017.

(2)	2017 amount relates primarily to settlement and curtailment as a result of the voluntary and involuntary separation programs at Dominion Energy Questar.

(3)	Reflected in other deferred credits and other liabilities in Dominion Energy Gas’ Consolidated Balance Sheets.


168

The ABO for all of Dominion Energy’s defined benefit pension plans was $7.8 billion and $8.2 billion at December 31, 2018 and 2017, respectively. The ABO for the defined benefit pension plans covering Dominion Energy Gas employees represented by collective bargaining units was $689 million and $724 million at December 31, 2018 and 2017, respectively.

Under its funding policies, Dominion Energy evaluates plan funding requirements annually, usually in the fourth quarter after receiving updated plan information from its actuary. Based on the funded status of each plan and other factors, Dominion Energy determines the amount of contributions for the current year, if any, at that time. During 2018, Dominion Energy and Dominion Energy Gas made no contributions to the qualified defined benefit pension plans. Dominion Energy expects to make $21 million of the minimum required contributions in 2019, and no contributions are currently expected in 2019 for Dominion Energy Gas.

Certain regulatory authorities have held that amounts recovered in utility customers’ rates for other postretirement benefits, in excess of benefits actually paid during the year, must be deposited in trust funds dedicated for the sole purpose of paying such benefits. Accordingly, certain of Dominion Energy’s subsidiaries, including Dominion Energy Gas, fund other postretirement benefit costs through VEBAs. Dominion Energy’s remaining subsidiaries do not prefund other postretirement benefit costs but instead pay claims as presented. Dominion Energy’s contributions to VEBAs, all of which pertained to Dominion Energy Gas employees, totaled $12 million for both 2018 and 2017, and Dominion Energy expects to contribute approximately $12 million to the Dominion Energy VEBAs in 2019, all of which pertains to Dominion Energy Gas employees.

Dominion Energy and Dominion Energy Gas do not expect any pension or other postretirement plan assets to be returned during 2019.

The following table provides information on the benefit obligations and fair value of plan assets for plans with a benefit obligation in excess of plan assets for Dominion Energy and Dominion Energy Gas (for employees represented by collective bargaining units):


	Pension Benefits				Other Postretirement Benefits
As of December 31,	2018		2017		2018		2017
(millions)
Dominion Energy
Benefit obligation	$	7,705	$	8,209		$164		$191
Fair value of plan assets		5,398		6,103		136		156
Dominion Energy Gas
Benefit obligation	$	—	$	—		$134		$157
Fair value of plan assets		—		—		126		143

The following table provides information on the ABO and fair value of plan assets for Dominion Energy’s pension plans with an ABO in excess of plan assets:


As of December 31,	2018		2017
(millions)
Accumulated benefit obligation	$	7,056	$	7,392
Fair value of plan assets		5,398		6,103

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid for Dominion Energy and Dominion Energy Gas’ (for employees represented by collective bargaining units) plans:


	Estimated Future Benefit Payments
	Pension Benefits		Other Postretirement Benefits
(millions)
Dominion Energy
2019		$407		$98
2020		405		99
2021		426		99
2022		442		99
2023		465		98
2024-2028	2,548		461
Dominion Energy Gas
2019		$37		$19
2020		39		19
2021		40		19
2022		42		19
2023		43		19
2024-2028		223		90

PLAN ASSETS

Dominion Energy’s overall objective for investing its pension and other postretirement plan assets is to achieve appropriate long-term rates of return commensurate with prudent levels of risk. As a participating employer in various pension plans sponsored by Dominion Energy, Dominion Energy Gas is subject to Dominion Energy’s investment policies for such plans. To minimize risk, funds are broadly diversified among asset classes, investment strategies and investment advisors. The strategic target asset allocations for Dominion Energy’s pension funds are 28% U.S. equity, 18% non-U.S. equity, 35% fixed income, 3% real estate and 16% other alternative investments. U.S. equity includes investments in large-cap, mid-cap and small-cap companies located in the U.S. Non-U.S. equity includes investments in large-cap and small-cap companies located outside of the U.S. including both developed and emerging markets. Fixed income includes corporate debt instruments of companies from diversified industries and U.S. Treasuries. The U.S. equity, non-U.S. equity and fixed income investments are in individual securities as well as mutual funds. Real estate includes equity real estate investment trusts and investments in partnerships. Other alternative investments include partnership investments in private equity, debt and hedge funds that follow several different strategies.

Dominion Energy also utilizes common/collective trust funds as an investment vehicle for its defined benefit plans. A common/collective trust fund is a pooled fund operated by a bank or trust company for investment of the assets of various organizations and individuals in a well-diversified portfolio. Common/collective trust funds are funds of grouped assets that follow various investment strategies.

Strategic investment policies are established for Dominion Energy’s prefunded benefit plans based upon periodic asset/liability studies. Factors considered in setting the investment policy include employee demographics, liability growth rates, future discount rates, the funded status of the plans and the expected long-term rate of return on plan assets. Deviations from


				169

Combined Notes to Consolidated Financial Statements, Continued

the plans’ strategic allocation are a function of Dominion Energy’s assessments regarding short-term risk and reward opportunities in the capital markets and/or short-term market movements which result in the plans’ actual asset allocations varying from the strategic target asset allocations. Through periodic rebalancing, actual allocations are brought back in line with the target. Future asset/liability studies will focus on strategies to fur-

ther reduce pension and other postretirement plan risk, while still achieving attractive levels of returns. Financial derivatives may be used to obtain or manage market exposures and to hedge assets and liabilities.

For fair value measurement policies and procedures related to pension and other postretirement benefit plan assets, see Note 6.

The fair values of Dominion Energy and Dominion Energy Gas’ (for employees represented by collective bargaining units) pension plan assets by asset category are as follows:


At December 31,	2018								2017
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
(millions)
Dominion Energy
Cash and cash equivalents	$	17	$	1		$—	$	18	$	18	$	—		$—	$	18
Common and preferred stocks:
U.S.		1,645		—		—		1,645		1,902		—		—		1,902
International		1,061		—		—		1,061		1,151		—		—		1,151
Insurance contracts		—		318		—		318		—		352		—		352
Corporate debt instruments		23		729		—		752		41		729		—		770
Government securities		25		605		—		630		9		676		—		685
Total recorded at fair value	$	2,771	$	1,653		$—	$	4,424	$	3,121	$	1,757		$—	$	4,878
Assets recorded at NAV(1):
Common/collective trust funds								1,849								2,272
Alternative investments:
Real estate funds								108								111
Private equity funds								633								606
Debt funds								155								161
Hedge funds								17								19
Total recorded at NAV							$	2,762							$	3,169
Total investments(2)							$	7,186							$	8,047
Dominion Energy Gas
Cash and cash equivalents	$	4	$	—		$—	$	4	$	4	$	—		$—	$	4
Common and preferred stocks:
U.S.		378		—		—		378		425		—		—		425
International		244		—		—		244		257		—		—		257
Insurance contracts		—		73		—		73		—		79		—		79
Corporate debt instruments		5		168		—		173		9		163		—		172
Government securities		6		139		—		145		2		151		—		153
Total recorded at fair value	$	637	$	380		$—	$	1,017	$	697	$	393		$—	$	1,090
Assets recorded at NAV(1):
Common/collective trust funds								425								509
Alternative investments:
Real estate funds								25								25
Private equity funds								146								135
Debt funds								36								36
Hedge funds								4								4
Total recorded at NAV							$	636							$	709
Total investments(3)							$	1,653							$	1,799

(1)	These investments that are measured at fair value using the NAV per share (or its equivalent) as a practical expedient which are not required to be categorized in the fair value hierarchy.

(2)

Excludes net assets related to pending sales of securities of $12 million, net accrued income of $21 million, and includes net assets related to pending purchases of securities of $22 million at December 31, 2018. Excludes net assets related to pending sales of securities of $11 million, net accrued income of $19 million, and includes net assets related to pending purchases of securities of $15 million at December 31, 2017.

(3)

Excludes net assets related to pending sales of securities of $3 million, net accrued income of $5 million, and includes net assets related to pending purchases of securities of $5 million at December 31, 2018. Excludes net assets related to pending sales of securities of $3 million, net accrued income of $4 million, and includes net assets related to pending purchases of securities of $3 million at December 31, 2017.


170

The fair values of Dominion Energy and Dominion Energy Gas’ (for employees represented by collective bargaining units) other postretirement plan assets by asset category are as follows:


At December 31,	2018								2017
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
(millions)
Dominion Energy
Cash and cash equivalents		$1		$1		$—	$	2		$1		$2		$—		$3
Common and preferred stocks:
U.S.		554		—		—		554		636		—		—		636
International		170		—		—		170		196		—		—		196
Insurance contracts		—		19		—		19		—		21		—		21
Corporate debt instruments		1		44		—		45		2		44		—		46
Government securities		2		37		—		39		1		41		—		42
Total recorded at fair value		$728		$101		$—	$	829		$836		$108		$—		$944
Assets recorded at NAV(1):
Common/collective trust funds								650								689
Alternative investments:
Real estate funds								10								9
Private equity funds								80								73
Debt funds								10								11
Hedge funds								1								1
Total recorded at NAV							$	751								$783
Total investments(2)							$	1,580								$1,727
Dominion Energy Gas
Common and preferred stocks:
U.S.		$113		$—		$—	$	113		$130		$—		$—		$130
International		30		—		—		30		33		—		—		33
Total recorded at fair value		$143		$—		$—	$	143		$163		$—		$—		$163
Assets recorded at NAV(1):
Common/collective trust funds								148								154
Alternative investments:
Real estate funds								2								1
Private equity funds								18								15
Debt funds								—								—
Total recorded at NAV							$	168								$170
Total investments							$	311								$333

(1)	These investments that are measured at fair value using the NAV per share (or its equivalent) as a practical expedient which are not required to be categorized in the fair value hierarchy.

(2)

Excludes net assets related to pending sales of securities of $1 million, net accrued income of $2 million, and includes net assets related to pending purchases of securities of $2 million at December 31, 2018. Excludes net assets related to pending sales of securities of $1 million, net accrued income of $2 million, and includes net assets related to pending purchases of securities of $1 million at December 31, 2017.


				171

Combined Notes to Consolidated Financial Statements, Continued

The Plan’s investments are determined based on the fair values of the investments and the underlying investments, which have been determined as follows:

	•		Cash and Cash Equivalents—Investments are held primarily in short-term notes and treasury bills, which are valued at cost plus accrued interest.

	•		Common and Preferred Stocks—Investments are valued at the closing price reported on the active market on which the individual securities are traded.

	•		Insurance Contracts—Investments in Group Annuity Contracts with John Hancock were entered into after 1992 and are stated at fair value based on the fair value of the underlying securities as provided by the managers and include investments in U.S. government securities, corporate debt instruments, state and municipal debt securities.

	•		Corporate Debt Instruments—Investments are valued using pricing models maximizing the use of observable inputs for similar securities. This includes basing value on yields currently available on comparable securities of issuers with similar credit ratings. When quoted prices are not available for identical or similar instruments, the instrument is valued under a discounted cash flows approach that maximizes observable inputs, such as current yields of similar instruments, but includes adjustments for certain risks that may not be observable, such as credit and liquidity risks or a broker quote, if available.

	•		Government Securities—Investments are valued using pricing models maximizing the use of observable inputs for similar securities.

	•		Common/Collective Trust Funds—Common/collective trust funds invest in debt and equity securities and other instruments with characteristics similar to those of the funds’ benchmarks. The primary objectives of the funds are to seek investment returns that approximate the overall performance of their benchmark indexes. These benchmarks are major equity indices, fixed income indices, and money market indices that focus on growth, income, and liquidity strategies, as applicable. Investments in common/collective trust funds are stated at the NAV as determined by the issuer of the common/collective trust funds and are based on the fair value of the underlying investments held by the fund less its liabilities. The NAV is used as a practical expedient to estimate fair value. The common/collective trust funds do not have any unfunded commitments, and do not have any applicable liquidation periods or defined terms/periods to be held. The majority of the common/collective trust funds have limited withdrawal or redemption rights during the term of the investment.

	•		Alternative Investments—Investments in real estate funds, private equity funds, debt funds and hedge funds are stated at fair value based on the NAV of the Plan’s proportionate share of the partnership, joint venture or other alternative investment’s fair value as determined by reference to audited financial statements or NAV statements provided by the investment manager. The NAV is used as a practical expedient to estimate fair value.


172

NET PERIODIC BENEFIT (CREDIT) COST

The service cost component and non-service cost components of net periodic benefit (credit) cost are reflected in other operations and maintenance expense and other income, respectively, in the Consolidated Statements of Income. The components of the provision for net periodic benefit (credit) cost and amounts recognized in other comprehensive income and regulatory assets and liabilities for Dominion Energy and Dominion Energy Gas’ (for employees represented by collective bargaining units) plans are as follows:


	Pension Benefits									Other Postretirement Benefits
Year Ended December 31,	2018			2017			2016			2018			2017			2016
(millions, except percentages)
Dominion Energy
Service cost	$	157		$	138		$	118		$	27		$	26		$	31
Interest cost		337			345			317			56			60			65
Expected return on plan assets		(663	)		(639	)		(573	)		(143	)		(128	)		(118	)
Amortization of prior service (credit) cost		1			1			1			(52	)		(51	)		(35	)
Amortization of net actuarial loss		193			162			111			11			13			8
Settlements and curtailments		—			—			1			—			—			—
Net periodic benefit (credit) cost	$	25		$	7		$	(25	)	$	(101	)	$	(80	)	$	(49	)
Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets and liabilities:
Current year net actuarial (gain) loss	$	490		$	142		$	931		$	78		$	12		$	178
Prior service (credit) cost		—			5			—			(4	)		(73	)		(216	)
Settlements and curtailments		—			1			(1	)		—			2			—
Less amounts included in net periodic benefit cost:
Amortization of net actuarial loss		(193	)		(162	)		(111	)		(11	)		(13	)		(8	)
Amortization of prior service credit (cost)		(1	)		(1	)		(1	)		52			51			35
Total recognized in other comprehensive income and regulatory assets and liabilities	$	296		$	(15	)	$	818		$	115		$	(21	)	$	(11	)
Significant assumptions used to determine periodic cost:
Discount rate		3.80%-3.8	1%		3.31%-4.5	0%		2.87%-4.9	9%		3.76%			3.92%-4.4	7%		3.56%-4.9	4%
Expected long-term rate of return on plan assets		8.75	%		8.75	%		8.75	%		8.50	%		8.50	%		8.50	%
Weighted average rate of increase for compensation		4.09	%		4.09	%		4.22	%		3.95%-4.1	1%		3.29	%		4.22	%
Healthcare cost trend rate(1)											7.00	%		7.00	%		7.00	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)(1)											5.00	%		5.00	%		5.00	%
Year that the rate reaches the ultimate trend rate(1)(2)											2022			2021			2020
Dominion Energy Gas
Service cost	$	18		$	15		$	13		$	4		$	4		$	5
Interest cost		29			30			30			11			12			14
Expected return on plan assets		(150	)		(141	)		(134	)		(28	)		(24	)		(23	)
Amortization of prior service (credit) cost		—			—			—			(4	)		(3	)		1
Amortization of net actuarial loss		19			16			13			3			2			1
Net periodic benefit (credit) cost	$	(84	)	$	(80	)	$	(78	)	$	(14	)	$	(9	)	$	(2	)
Changes in plan assets and benefit obligations recognized in other comprehensive income and regulatory assets and liabilities:
Current year net actuarial (gain) loss	$	207		$	(75	)	$	91		$	16		$	18		$	28
Prior service cost		—			—			—			(4	)		(61	)		—
Less amounts included in net periodic benefit cost:
Amortization of net actuarial loss		(19	)		(16	)		(13	)		(3	)		(2	)		(1	)
Amortization of prior service credit (cost)		—			—			—			4			3			(1	)
Total recognized in other comprehensive income and regulatory assets and liabilities	$	188		$	(91	)	$	78		$	13		$	(42	)	$	26
Significant assumptions used to determine periodic cost:
Discount rate		3.81	%		4.50	%		4.99	%		3.81	%		4.47	%		4.93	%
Expected long-term rate of return on plan assets		8.75	%		8.75	%		8.75	%		8.50	%		8.50	%		8.50	%
Weighted average rate of increase for compensation		4.11	%		4.11	%		3.93	%		4.55	%		4.11	%		3.93	%
Healthcare cost trend rate(1)											7.00	%		7.00	%		7.00	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)(1)											5.00	%		5.00	%		5.00	%
Year that the rate reaches the ultimate trend rate(1)											2022			2021			2020

(1)	Assumptions used to determine net periodic cost for the following year.

(2)	The Society of Actuaries model used to determine healthcare cost trend rates was updated in 2014. The new model converges to the ultimate trend rate much more quickly than previous models.


				173

Combined Notes to Consolidated Financial Statements, Continued

The components of AOCI and regulatory assets and liabilities for Dominion Energy and Dominion Energy Gas’ (for employees represented by collective bargaining units) plans that have not been recognized as components of net periodic benefit (credit) cost are as follows:


	Pension Benefits				Other Postretirement Benefits
At December 31,	2018		2017		2018			2017
(millions)
Dominion Energy
Net actuarial loss	$	3,477	$	3,181	$	350		$	283
Prior service (credit) cost		7		8		(393	)		(440	)
Total(1)	$	3,484	$	3,189	$	(43	)	$	(157	)
Dominion Energy Gas
Net actuarial loss	$	555	$	367	$	89		$	76
Prior service (credit) cost		—		—		(52	)		(52	)
Total(2)	$	555	$	367	$	37		$	24

(1)

As of December 31, 2018, of the $3.5 billion and $(43) million related to pension benefits and other postretirement benefits, $2.0 billion and $(41) million, respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities. As of December 31, 2017, of the $3.2 billion and $(157) million related to pension benefits and other postretirement benefits, $1.9 billion and $(87) million, respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities.

(2)

As of December 31, 2018, of the $555 million related to pension benefits, $200 million is included in AOCI, with the remainder included in regulatory assets and liabilities; the $37 million related to other postretirement benefits is included entirely in regulatory assets and liabilities. As of December 31, 2017, of the $367 million related to pension benefits, $134 million is included in AOCI, with the remainder included in regulatory assets and liabilities; the $24 million related to other postretirement benefits is included entirely in regulatory assets and liabilities.

The following table provides the components of AOCI and regulatory assets and liabilities for Dominion Energy and Dominion Energy Gas’ (for employees represented by collective bargaining units) plans as of December 31, 2018 that are expected to be amortized as components of net periodic benefit (credit) cost in 2019:


	Pension Benefits		Other Postretirement Benefits
(millions)
Dominion Energy
Net actuarial loss		$155	$	18
Prior service (credit) cost		1		(52)
Dominion Energy Gas
Net actuarial loss		$ 19	$	4
Prior service (credit) cost		—		(4	)

The expected long-term rates of return on plan assets, discount rates, healthcare cost trend rates and mortality are critical assumptions in determining net periodic benefit (credit) cost. Dominion Energy develops non-investment related assumptions, which are then compared to the forecasts of an independent investment advisor to ensure reasonableness. An internal committee selects the final assumptions used for Dominion Energy’s pension and other postretirement plans, including those in which Dominion Energy Gas participates, including discount rates, expected long-term rates of return, healthcare cost trend rates and mortality rates.

Dominion Energy determines the expected long-term rates of return on plan assets for its pension plans and other postretirement benefit plans, including those in which Dominion Energy Gas participates, by using a combination of:

	•		Expected inflation and risk-free interest rate assumptions;

	•		Historical return analysis to determine long term historic returns as well as historic risk premiums for various asset classes;

	•		Expected future risk premiums, asset classes’ volatilities and correlations;

	•		Forward-looking return expectations derived from the yield on long-term bonds and the expected long-term returns of major capital market assumptions; and

	•		Investment allocation of plan assets.

Dominion Energy determines discount rates from analyses of AA/Aa rated bonds with cash flows matching the expected payments to be made under its plans, including those in which Dominion Energy Gas participates.

Mortality rates are developed from actual and projected plan experience for postretirement benefit plans. Dominion Energy’s actuary conducts an experience study periodically as part of the process to select its best estimate of mortality. Dominion Energy considers both standard mortality tables and improvement factors as well as the plans’ actual experience when selecting a best estimate. During 2016, Dominion Energy conducted a new experience study as scheduled and, as a result, updated its mortality assumptions for all its plans, including those in which Dominion Energy Gas participates.

Assumed healthcare cost trend rates have a significant effect on the amounts reported for Dominion Energy’s retiree healthcare plans, including those in which Dominion Energy Gas participates. A one percentage point change in assumed healthcare cost trend rates would have had the following effects for Dominion Energy and Dominion Energy Gas’ (for employees represented by collective bargaining units) other postretirement benefit plans:


	Other Postretirement Benefits
	One percentage point increase		One percentage point decrease
(millions)
Dominion Energy
Effect on net periodic cost for 2019		$ 20		$ (16)
Effect on other postretirement benefit obligation at December 31, 2018		130		(110)
Dominion Energy Gas
Effect on net periodic cost for 2019		$ 4		$ (3)
Effect on other postretirement benefit obligation at December 31, 2018		25		(22)

Dominion Energy Gas (Employees Not Represented by Collective Bargaining Units) and Virginia Power—Participation in Defined Benefit Plans

Virginia Power employees and Dominion Energy Gas employees not represented by collective bargaining units are covered by the Dominion Energy Pension Plan described above. As participating employers, Virginia Power and Dominion Energy Gas are subject to Dominion Energy’s funding policy, which is to contribute annually an amount that is in accordance with ERISA. During 2018, Virginia Power and Dominion Energy Gas made no con-


174

tributions to the Dominion Energy Pension Plan, and no contributions to this plan are currently expected in 2019. Virginia Power’s net periodic pension cost related to this plan was $126 million, $110 million and $79 million in 2018, 2017 and 2016, respectively. Dominion Energy Gas’ net periodic pension credit related to this plan was $(38) million, $(37) million and $(45) million in 2018, 2017 and 2016, respectively. Net periodic pension (credit) cost is reflected in other operations and maintenance expense in their respective Consolidated Statements of Income. The funded status of various Dominion Energy subsidiary groups and employee compensation are the basis for determining the share of total pension costs for participating Dominion Energy subsidiaries. See Note 24 for Virginia Power and Dominion Energy Gas amounts due to/from Dominion Energy related to this plan.

Retiree healthcare and life insurance benefits, for Virginia Power employees and for Dominion Energy Gas employees not represented by collective bargaining units, are covered by the Dominion Energy Retiree Health and Welfare Plan described above. Virginia Power’s net periodic benefit (credit) cost related to this plan was $(51) million, $(42) million and $(29) million in 2018, 2017 and 2016, respectively. Dominion Energy Gas’ net periodic benefit (credit) cost related to this plan was $(7) million, $(5) million and $(4) million for 2018, 2017 and 2016, respectively. Net periodic benefit (credit) cost is reflected in other operations and maintenance expenses in their respective Consolidated Statements of Income. Employee headcount is the basis for determining the share of total other postretirement benefit costs for participating Dominion Energy subsidiaries. See Note 24 for Virginia Power and Dominion Energy Gas amounts due to/from Dominion Energy related to this plan.

Dominion Energy holds investments in trusts to fund employee benefit payments for the pension and other postretirement benefit plans in which Virginia Power and Dominion Energy Gas’ employees participate. Any investment-related declines in these trusts will result in future increases in the net periodic cost recognized for such employee benefit plans and will be included in the determination of the amount of cash that Virginia Power and Dominion Energy Gas will provide to Dominion Energy for their shares of employee benefit plan contributions.

Certain regulatory authorities have held that amounts recovered in rates for other postretirement benefits, in excess of benefits actually paid during the year, must be deposited in trust funds dedicated for the sole purpose of paying such benefits. Accordingly, Virginia Power and Dominion Energy Gas fund other postretirement benefit costs through VEBAs. During 2018 and 2017, Virginia Power made no contributions to the VEBA and does not expect to contribute to the VEBA in 2019. Dominion Energy Gas made no contributions to the VEBAs for employees not represented by collective bargaining units during 2018 and 2017 and does not expect to contribute in 2019.

Defined Contribution Plans

Dominion Energy also sponsors defined contribution employee savings plans that cover substantially all employees. During 2018, 2017 and 2016, Dominion Energy recognized $51 million, $45 million and $44 million, respectively, as employer matching contributions to these plans. Dominion Energy Gas participates in these employee savings plans, both specific to Dominion

Energy Gas and that cover multiple Dominion Energy subsidiaries. During 2018, 2017 and 2016, Dominion Energy Gas recognized $8 million, $7 million and $7 million, respectively, as employer matching contributions to these plans. Virginia Power also participates in these employee savings plans. During 2018, 2017 and 2016, Virginia Power recognized $20 million, $19 million and $19 million, respectively, as employer matching contributions to these plans.

Organizational Design Initiative

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. For the year ended December 31, 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.

NOTE 22. 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 that the Companies cannot estimate, a statement to this effect is made in the description of the matter. Other matters may have progressed sufficiently through the litigation or investigative processes such that the Companies are able to estimate a range of possible loss. For legal proceedings and governmental examinations that the Companies are able to reasonably estimate a range of possible losses, an estimated range of possible loss is provided, in excess of the accrued liability (if any) for such matters. Any 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 Companies’ financial position, liquidity or results of operations.


				175

Combined Notes to Consolidated Financial Statements, Continued

Environmental Matters

The Companies are 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.

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

The MATS rule requires coal- and oil-fired electric utility steam generating units to meet strict emission limits for mercury, particulate matter as a surrogate for toxic metals and hydrogen chloride as a surrogate for acid gases. Virginia Power ceased operating the coal units at Yorktown power station in April 2017 to comply with the rule.

In June 2017, the 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. Beginning in August 2017, PJM filed requests for 90-day renewals of the DOE order which the DOE has granted. The current renewal is effective until March 2019. The Sierra Club has challenged the DOE order and certain renewal requests, all of which have been denied by the DOE.

In December 2018, the EPA issued a proposed rule to reverse its previous finding that it is appropriate and necessary to regulate toxic emissions from power plants. However, the emissions standards and other requirements of the MATS rule would remain in place as the EPA is not proposing to remove coal and oil fired power plants from the list of sources that are regulated under MATS. Although litigation of the MATS rule and the outcome of the EPA’s rulemaking are still pending, the regulation remains in effect and Virginia Power is complying with the applicable requirements of the rule and 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 NOX Reasonable Available Control Technology analysis for Unit 5 at Possum Point power station. In December 2016, the VDEQ determined that NOX reductions are required on Unit 5. In October 2017, Virginia Power proposed to install NOX controls by mid-2019 with an expected cost in the range of $25 million to $35 million. In April 2018, Virginia Power submitted an application with the VDEQ containing an alternative plan for compliance in lieu of installing NOX controls on Unit 5 at Possum Point. The alter-

native plan includes operating restrictions during the ozone season through 2021 while allowing for continued operation to meet PJM capacity commitments and calls for the permanent retirement of the unit by 2021. In January 2019, the VDEQ issued a state operating permit that requires either the installation and operation of selective non-catalytic NOX reduction technology by June 2019 or for Virginia Power to enter into an agreement with the VDEQ by June 2019 committing to retiring the unit by June 2021 with ozone season operating restrictions in the interim. In addition, Virginia Power placed two natural gas-fired units at the facility into cold reserve in December 2018. Virginia Power is currently evaluating its options. Dominion Energy and Virginia Power are unable to estimate the expenditures associated with this matter, however, they could be material to Dominion Energy and Virginia Power’s results of operations, financial condition and/or cash flows.

The EPA published final non-attainment designations for the October 2015 ozone standard in June 2018. States have until August 2021 to develop plans to address the new standard. Until the states have developed implementation plans for the standard, the Companies are unable to predict whether or to what extent the new rules will ultimately require additional controls. The expenditures required to implement additional controls could have a material impact on the Companies’ results of operations and cash flows.

NOx and VOC Emissions

In April 2016, the Pennsylvania Department of Environmental Protection issued final regulations, with an effective date of January 2017, to reduce NOX and VOC emissions from combustion sources. To comply with the regulations, Dominion Energy Gas installed emission control systems on existing engines at several compressor stations in Pennsylvania, which was completed in December 2018. The compliance costs associated with engineering and installation of controls and compliance demonstration with the regulation was approximately $35 million.

Oil and Gas NSPS

In August 2012, the EPA issued an 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 new 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 October 2018, the EPA published a proposed rule reconsidering and amending portions of the 2016 rule, including but not limited to, the fugitive emissions requirements at well sites and compressor stations. Until the proposed rule is final, Dominion Energy and Dominion Energy Gas are implementing the 2016 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.


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GHG REGULATION

Carbon Regulations

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 addition, the EPA continues to evaluate its policy regarding the consideration of CO2 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. It is unclear how the final policy will affect Virginia Power’s Altavista, Hopewell and Southampton power stations which were converted from coal to biomass under the prior biomass deferral policy; however, the expenditures to comply with any new requirements could be material to Dominion Energy 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 joined the EPA as founding partners in the new Methane Challenge program and submitted implementation plans in September 2016. Wexpro, DECG and Dominion Energy Questar Pipeline joined the Methane Challenge in 2018. DECG joined the EPA’s voluntary Natural Gas STAR Program in July 2016 and submitted an implementation plan in September 2016 with Questar Gas and Dominion Energy Questar Pipeline joining in 2018. Dominion Energy and Dominion Energy Gas do not expect the costs related to these programs to have a material impact on their 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 13 and 11 facilities, respectively, that may be subject to the final regulations. Nine units at Virginia Power’s facilities that are subject to regulations under Section 316(b) of the CWA have been or will be placed into cold reserve. While in cold reserve, applicable requirements under Section 316(b) of the CWA continue to apply to these units. 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 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. 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 for certain waste streams regulations in the Effluent Limitations Guidelines final rule 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 and Virginia Power’s results of operations, financial condition and/or cash flows, the existing regulatory frameworks in South Carolina and Virginia provide rate recovery mechanisms that could substantially mitigate any such impacts for Dominion Energy and Virginia Power.

WASTE MANAGEMENT AND REMEDIATION

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


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Combined Notes to Consolidated Financial Statements, Continued

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. 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 22 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. In addition, a Virginia Power site has been accepted into a state-based voluntary remediation program. In June 2018, Virginia Power submitted a proposed remedial action plan to remove material from this site at an estimated cost of $18 million. Pending VDEQ approval, Virginia Power expects to begin remedial work at this site in mid-2019. As a result, in June 2018, Virginia recorded a charge of $16 million ($12 million after-tax) in other operations and maintenance expense in the Consolidated Statements of Income. The four sites Dominion Energy acquired in the SCANA Combination associated with SCE&G are in various states of investigation, remediation and monitoring under work plans approved by, or under review by, the SCDHEC or the EPA. Dominion Energy anticipates that activities at these sites will continue through 2020 at an estimated cost of $10 million. In September 2018, SCE&G submitted an updated remediation work plan at one site to SCDHEC, which if approved, would increase costs by approximately $8 million. SCE&G expects to recover costs arising from the remediation work at all four sites through rate recovery mechanisms. 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 2015, the contractor filed a complaint against DETI in U.S. District Court for the Western District of Pennsylvania. In March 2016, the Pennsylvania court granted DETI’s motion to transfer the case to the U.S. District Court for the Eastern District of Virginia. 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. In November 2017, DETI and the contractor entered into a partial settlement agreement for a release of certain claims. In August 2018, DETI paid $14 million in accordance with the terms of a settlement agreement reached between the parties, resolving this matter.

Gas Producers Litigation

In connection with the Appalachian Gateway project, Dominion Energy Field Services, Inc. entered into contracts for firm purchase rights with a group of small gas producers. In June 2016, 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. During the third quarter of 2016, Dominion Energy, DETI and Dominion Energy Field Services, Inc. were served with the complaint. Also 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. In January 2018, the court granted the motion to dismiss filed by the defendants on two counts. Claims are pending in the Business Court Division of West Virginia. 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 March 2015, the Sierra Club filed a lawsuit alleging 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


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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. 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. In September 2018, the U.S. Court of Appeals for the Fourth Circuit ruled that impacted groundwater associated with coal ash storage at the Chesapeake power station did not constitute point source pollution in violation of the CWA or the station’s water discharge permit. The Sierra Club subsequently filed a petition for rehearing with the U.S. Court of Appeals for the Fourth Circuit, which was denied.

In April 2015, the EPA enacted a final rule regulating CCR landfills, existing ash ponds that still receive and manage CCRs, and inactive ash ponds that do not receive, but still store, CCRs. Dominion Energy currently operates inactive ash ponds, existing ash ponds and CCR landfills subject to the final rule at 11 different facilities, eight of which are at Virginia Power. This rule created a legal obligation for Dominion Energy and 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 2015, Virginia Power recorded a $386 million ARO related to future ash pond and landfill closure costs. In 2016, Virginia Power recorded an increase to this ARO of $238 million, which resulted in a $197 million incremental charge recorded in other operations and maintenance expense in its Consolidated Statement of Income, a $17 million increase in property, plant and equipment and a $24 million increase in regulatory assets.

In December 2016, legislation was enacted that creates a framework for EPA- approved state CCR permit programs. 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. In March 2018, the EPA proposed certain changes to the CCR rule related to issues remanded as part of the pending litigation and other issues the EPA is reconsidering. Several of the proposed changes would allow states with approved CCR permit programs additional flexibilities in implementing their programs. In July 2018, the EPA promulgated the first phase of changes to the CCR rule. Until all phases of the CCR rule are promulgated, Dominion Energy and Virginia Power 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 August 2018, the U.S. Court of Appeals for the D.C. Circuit

issued its decision in the pending challenges of the CCR rule, vacating and remanding to the EPA three provisions of the rule. Dominion Energy and Virginia Power do not expect the scope of the U.S. Court of Appeals for the D.C. Circuit’s decision to impact their closure plans, but cannot forecast incremental impacts associated with any future changes to the CCR rule in connection with the court’s remand.

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 required 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. Virginia Power completed the assessments and provided the report on December 1, 2017. In April 2018, the Governor of Virginia signed legislation into law extending the existing permit moratorium until July 2019. The legislation also requires Virginia Power to solicit and compile by November 2018, information from third parties on the suitability, cost and market demand for beneficiation or recycling of coal ash from these units. The coal ash recycling business plan was submitted to the legislature in November 2018. The extended moratorium does not apply to a permit required for an impoundment where CCRs have already been removed and placed in another impoundment on-site, are being removed from an impoundment, or are being processed in connection with a recycling or beneficial use project. In connection with this legislation, in the second quarter of 2018 Virginia Power recorded an increase to its ARO and a related environmental liability related to future ash pond and landfill closure costs of $131 million, which resulted in an $81 million ($60 million after-tax) charge recorded in other operations and maintenance expense in its Consolidated Statement of Income, a $46 million increase in property, plant and equipment associated with asset retirement costs and a $4 million increase in regulatory assets. The actual AROs related to the CCR rule may vary substantially from the estimates used to record the obligation.

COVE POINT

In September 2014, FERC issued an order granting authorization for Cove Point to construct, modify and operate the Liquefaction Project at the Cove Point facility, which enables the facility to liquefy domestically-produced natural gas and export it as LNG. In March 2018, Cove Point received authorization from FERC to commence service of the Liquefaction Project, which commenced commercial operations in April 2018.

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. 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


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Combined Notes to Consolidated Financial Statements, Continued

existing import shipper. In October 2017, the party filed a request for rehearing of the FERC order on remand. In August 2018, FERC issued its rehearing order affirming and clarifying its previous orders. No appeals were filed and FERC’s orders are final and no longer subject to further review.

FERC

FERC staff in the Office of Enforcement, Division of Investigations, conducted 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 provided its response to FERC staff’s preliminary findings letter explaining why Virginia Power’s conduct was lawful and refuting any allegation of wrongdoing. This matter is pending. Virginia Power has recorded a liability of $14 million in its Consolidated Balance Sheet at December 31, 2018.

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. Reevalua-

tion of the seismic hazards was completed or in review with the NRC in 2018. Reevaluation of the external flooding hazards is expected to continue through 2019. 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.

Nuclear Operations

NUCLEAR DECOMMISSIONING—MINIMUM FINANCIAL ASSURANCE

The NRC requires nuclear power plant owners to annually update minimum financial assurance amounts for the future decommissioning of their nuclear facilities. Decommissioning involves the decontamination and removal of radioactive contaminants from a nuclear power station once operations have ceased, in accordance with standards established by the NRC. The 2018 calculation for the NRC minimum financial assurance amount, aggregated for Dominion Energy and Virginia Power’s nuclear units, excluding joint owners’ assurance amounts and Millstone Unit 1 and Kewaunee, as those units are in a decommissioning state, was $2.7 billion and $1.8 billion, respectively, and has been satisfied by a combination of the funds being collected and deposited in the nuclear decommissioning trusts and the real annual rate of return growth of the funds allowed by the NRC. The 2018 NRC minimum financial assurance amounts above were calculated using preliminary December 31, 2018 U.S. Bureau of Labor Statistics indices. Dominion Energy believes that the amounts currently available in its decommissioning trusts and their expected earnings will be sufficient to cover expected decommissioning costs for the Millstone and Kewaunee units. Virginia Power also believes that the decommissioning funds and their expected earnings for the Surry and North Anna units will be sufficient to cover decommissioning costs, particularly when combined with future ratepayer collections and contributions to these decommissioning trusts, if such future collections and contributions are required. This reflects a positive long-term outlook for trust fund investment returns as the decommissioning of the units will not be complete for decades. Dominion Energy and Virginia Power will continue to monitor these trusts to ensure they meet the NRC minimum financial assurance requirement, which may include, if needed, the use of parent company guarantees, surety bonding or other financial instruments recognized by the NRC. See Note 9 for additional information on nuclear decommissioning trust investments.

NUCLEAR INSURANCE

The Price-Anderson Amendments Act of 1988 provides the public with liability protection on a per site, per nuclear incident basis, via obligations required of owners of nuclear power plants, and allows for an inflationary provision adjustment every five years. During the second quarter of 2018, the total liability protection per nuclear incident available to all participants in the Secondary Financial Protection Program decreased from


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$13.4 billion to $13.1 billion. During the fourth quarter of 2018, this amount increased from $13.1 billion to $14.1 billion. Dominion Energy and Virginia Power have purchased $450 million of coverage from commercial insurance pools for Millstone, Surry and North Anna with the remainder provided through the mandatory industry retrospective rating plan. In the event of a nuclear incident at any licensed nuclear reactor in the U.S., Dominion Energy and Virginia Power could be assessed up to $138 million for each of their licensed reactors not to exceed $21 million per year per reactor. There is no limit to the number of incidents for which this retrospective premium can be assessed. The NRC granted an exemption in March 2015 to remove Kewaunee from the Secondary Financial Protection program. This same exemption permitted Dominion Energy to reduce Kewaunee’s required level of liability coverage to $100 million. This reduction was implemented in January 2018, following the removal and storage of the spent nuclear fuel from the spent fuel pool. The current levels of nuclear property insurance coverage for Dominion Energy and Virginia Power’s nuclear units are as follows:


	Coverage
(billions)
Dominion Energy
Millstone	$	1.70
Kewaunee		0.05
Virginia Power(1)
Surry	$	1.70
North Anna		1.70

(1)	Surry and North Anna share a blanket property limit of $200 million.

Dominion Energy and Virginia Power’s nuclear property insurance coverage for Millstone, Surry and North Anna exceeds the NRC minimum requirement for nuclear power plant licensees of $1.06 billion per reactor site. In March 2015, the NRC granted an exemption which allowed Kewaunee to reduce its property insurance limit to $50 million. This reduction was implemented in January 2018, following the removal and storage of the spent nuclear fuel from the spent fuel pool. This includes coverage for premature decommissioning and functional total loss. The NRC requires that the proceeds from this insurance be used first, to return the reactor to and maintain it in a safe and stable condition and second, to decontaminate the reactor and station site in accordance with a plan approved by the NRC. Nuclear property insurance is provided by NEIL, a mutual insurance company, and is subject to retrospective premium assessments in any policy year in which losses exceed the funds available to the insurance company. Dominion Energy and Virginia Power’s maximum retrospective premium assessment for the current policy period is $83 million and $51 million, respectively. Based on the severity of the incident, the Board of Directors of the nuclear insurer has the discretion to lower or eliminate the maximum retrospective premium assessment. Dominion Energy and Virginia Power have the financial responsibility for any losses that exceed the limits or for which insurance proceeds are not available because they must first be used for stabilization and decontamination.

Millstone and Virginia Power also purchase accidental outage insurance from NEIL to mitigate certain expenses, including replacement power costs, associated with the prolonged outage of a nuclear unit due to direct physical damage. Under this program,

Dominion Energy and Virginia Power are subject to a retrospective premium assessment for any policy year in which losses exceed funds available to NEIL. Dominion Energy and Virginia Power’s maximum retrospective premium assessment for the current policy period is $21 million and $10 million, respectively.

ODEC, a part owner of North Anna, and Massachusetts Municipal and Green Mountain, part owners of Millstone’s Unit 3, are responsible to Dominion Energy and Virginia Power for their share of the nuclear decommissioning obligation and insurance premiums on applicable units, including any retrospective premium assessments and any losses not covered by insurance.

SPENT NUCLEAR FUEL

Dominion Energy and Virginia Power entered into contracts with the DOE for the disposal of spent nuclear fuel under provisions of the Nuclear Waste Policy Act of 1982. The DOE failed to begin accepting the spent fuel on January 31, 1998, the date provided by the Nuclear Waste Policy Act and by Dominion Energy and Virginia Power’s contracts with the DOE. Dominion Energy and Virginia Power have previously received damages award payments and settlement payments related to these contracts.

By mutual agreement of the parties, the settlement agreements are extendable to provide for resolution of damages incurred after 2013. The settlement agreements for the Surry, North Anna and Millstone nuclear power stations have been extended to provide for periodic payments for damages incurred through December 31, 2019. In June 2018, a lawsuit for Kewaunee was filed in the U.S. Court of Federal Claims for recovery of spent nuclear fuel storage costs incurred for the period January 1, 2014 through December 31, 2017. This matter is pending.

In 2018, Virginia Power and Dominion Energy received payments of $16 million for resolution of claims incurred at North Anna and Surry for the period of January 1, 2016 through December 31, 2016, and $13 million for resolution of claims incurred at Millstone for the period of July 1, 2016 through June 30, 2017.

In 2017, Virginia Power and Dominion Energy received payments of $22 million for resolution of claims incurred at North Anna and Surry for the period of January 1, 2015 through December 31, 2015, and $14 million for resolution of claims incurred at Millstone for the period of July 1, 2015 through June 30, 2016.

In 2016, Virginia Power and Dominion Energy received payments of $30 million for resolution of claims incurred at North Anna and Surry for the period of January 1, 2014 through December 31, 2014, and $22 million for resolution of claims incurred at Millstone for the period of July 1, 2014 through June 30, 2015.

Dominion Energy and Virginia Power continue to recognize receivables for certain spent nuclear fuel-related costs that they believe are probable of recovery from the DOE. Dominion Energy’s receivables for spent nuclear fuel-related costs totaled $49 million and $46 million at December 31, 2018 and 2017, respectively. Virginia Power’s receivables for spent nuclear fuel-related costs totaled $30 million at both December 31, 2018 and 2017.

Dominion Energy and Virginia Power will continue to manage their spent fuel until it is accepted by the DOE.


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Combined Notes to Consolidated Financial Statements, Continued

Long-Term Purchase Agreements

At December 31, 2018, Virginia Power had the following long-term commitments that are noncancelable or are cancelable only under certain conditions, and that a third party has used to secure financing for the facility that will provide the contracted goods or services:


	2019			2020			2021			2022			2023			Thereafter			Total
(millions)

Purchased electric capacity(1)		$	60		$	52		$	46		$	—		$	—		$	—		$	158

(1)

Commitments represent estimated amounts payable for capacity under power purchase contracts with independent power producers, which end in 2021. Capacity payments under the contracts are generally based on fixed dollar amounts per month, subject to escalation using broad based economic indices. At December 31, 2018, the present value of Virginia Power’s total commitment for capacity payments is $142 million. Capacity payments totaled $50 million, $114 million and $248 million, and energy payments totaled $42 million, $72 million and $126 million for the years ended 2018, 2017 and 2016, respectively.

Lease Commitments

The Companies lease real estate, vehicles and equipment primarily under operating leases. Payments under certain leases are escalated based on an index such as the consumer price index. Future minimum lease payments under noncancelable operating leases that have initial or remaining lease terms in excess of one year as of December 31, 2018 are as follows:


	2019			2020			2021			2022			2023			Thereafter			Total
(millions)
Dominion Energy		$	64		$	61		$	55		$	47		$	38		$	384		$	649
Virginia Power			34			32			28			22			16			106			238
Dominion Energy Gas			12			11			9			7			4			3			46

Rental expense for Dominion Energy totaled $109 million, $113 million, and $104 million for 2018, 2017 and 2016, respectively. Rental expense for Virginia Power totaled $63 million, $57 million, and $52 million for 2018, 2017 and 2016, respectively. Rental expense for Dominion Energy Gas totaled $22 million, $34 million, and $37 million for 2018, 2017 and 2016, respectively. The majority of rental expense is reflected in other operations and maintenance expense in the Consolidated Statements of Income.

In July 2016, Dominion Energy signed an agreement with a lessor to construct and lease a new corporate office property in Richmond, Virginia. The lessor is providing equity and has obtained financing commitments from debt investors, totaling $365 million, to fund the estimated project costs. The project is expected to be completed by mid-2019. Dominion Energy has been appointed to act as the construction agent for the lessor, during which time Dominion Energy will request cash draws from the lessor and debt investors to fund all project costs, which totaled $281 million as of December 31, 2018. If the project is terminated under certain events of default, Dominion Energy could be required to pay up to 89.9% of the then funded amount. For specific full recourse events, Dominion Energy could be required to pay up to 100% of the then funded amount.

The five-year lease term will commence once construction is substantially complete and the facility is able to be occupied. At

the end of the initial lease term, Dominion Energy can (i) extend the term of the lease for an additional five years, subject to the approval of the participants, at current market terms, (ii) purchase the property for an amount equal to the project costs or, (iii) subject to certain terms and conditions, sell the property on behalf of the lessor to a third party using commercially reasonable efforts to obtain the highest cash purchase price for the property. If the project is sold and the proceeds from the sale are insufficient to repay the investors for the project costs, Dominion Energy may be required to make a payment to the lessor, up to 87% of project costs, for the difference between the project costs and sale proceeds.

Guarantees, Surety Bonds and Letters of Credit

In October 2017, Dominion Energy entered into a guarantee agreement to support a portion of Atlantic Coast Pipeline’s obligation under a $3.4 billion revolving credit facility, 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. As of December 31, 2018, Atlantic Coast Pipeline has borrowed $1.4 billion against the revolving credit facility and borrowed an additional $113 million in January and February 2019. Dominion Energy’s Consolidated Balance Sheet includes a liability of $21 million and $28 million associated with this guarantee agreement at December 31, 2018 and 2017, respectively.

In addition, at December 31, 2018, Dominion Energy had issued an additional $48 million of guarantees, primarily to support other equity method investees. No amounts related to the other guarantees have been recorded.

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 the Consolidated Financial Statements. Dominion Energy is not required 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 December 31, 2018, Dominion Energy had issued the following subsidiary guarantees:


	Maximum Exposure
(millions)
Commodity transactions(1)		$	2,186
Nuclear obligations(2)			179
Cove Point(3)			1,900
Solar(4)			659
Other(5)			420
Total(6)		$	5,344


182

(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. Cove Point has two guarantees that have no maximum limit and, therefore, are not included in this amount.

(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 worker’s 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 December 31, 2018, Dominion Energy’s maximum remaining cumulative exposure under these equity funding agreements is $4 million through 2019 and its maximum annual future contribution is approximately $4 million.

(6)	Excludes Dominion Energy’s guarantee for the construction of the new corporate office property discussed further within Lease Commitments above.

Additionally, at December 31, 2018, Dominion Energy had purchased $171 million of surety bonds, including $72 million at Virginia Power and $26 million at Dominion Energy Gas, and authorized the issuance of letters of credit by financial institutions of $88 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.

Indemnifications

As part of commercial contract negotiations in the normal course of business, the Companies may sometimes agree to make payments to compensate or indemnify other parties for possible future unfavorable financial consequences resulting from specified events. The specified events may involve an adverse judgment in a lawsuit or the imposition of additional taxes due to a change in tax law or interpretation of the tax law. The Companies are unable to develop an estimate of the maximum potential amount of any other future payments under these contracts because events that would obligate them have not yet occurred or, if any such event has occurred, they have not been notified of its occurrence. However, at December 31, 2018, the Companies believe any other future payments, if any, that could ultimately become payable under these contract provisions, would not have a material impact on their results of operations, cash flows or financial position.

NOTE 23. CREDIT RISK

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

The Companies maintain a provision for credit losses based on factors surrounding the credit risk of their customers, historical trends and other information. Management believes, based on credit policies and the December 31, 2018 provision for credit losses, that it is unlikely that a material adverse effect on financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.

General

DOMINION ENERGY

As a diversified energy company, Dominion Energy transacts primarily with major companies in the energy industry and with commercial and residential energy consumers. These transactions principally occur in the Northeast, mid-Atlantic, Midwest and Rocky Mountain and Southeast regions of the U.S. Dominion Energy does not believe that this geographic concentration contributes significantly to its overall exposure to credit risk. In addition, as a result of its large and diverse customer base, Dominion Energy is not exposed to a significant concentration of credit risk for receivables arising from electric and gas utility operations.

Dominion Energy’s exposure to credit risk is concentrated primarily within its energy marketing and price risk management activities, as Dominion Energy transacts with a smaller, less diverse group of counterparties and transactions may involve large notional volumes and potentially volatile commodity prices. Energy marketing and price risk management activities include marketing of merchant generation output, structured transactions and the use of financial contracts for enterprise-wide hedging purposes. Gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of any collateral. At December 31, 2018, Dominion Energy’s credit exposure totaled $145 million. Of this amount, investment grade counterparties, including those internally rated, represented 69%, and no single counterparty, whether investment grade or non-investment grade, exceeded $47 million of exposure.

VIRGINIA POWER

Virginia Power sells electricity and provides distribution and transmission services to customers in Virginia and northeastern North Carolina. Management believes that this geographic concentration risk is mitigated by the diversity of Virginia Power’s customer base, which includes residential, commercial and industrial customers, as well as rural electric cooperatives and municipalities. Credit risk associated with trade accounts receivable from energy consumers is limited due to the large number of customers. Virginia Power’s exposure to potential concentrations of credit risk results primarily from sales to wholesale customers. Virginia Power’s gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. At December 31, 2018, Virginia Power’s credit exposure totaled $10 million, of which no amounts were investment grade counterparties, and no single counterparty exceeded $9 million of exposure.


				183

Combined Notes to Consolidated Financial Statements, Continued

DOMINION ENERGY GAS

Dominion Energy Gas transacts mainly with major companies in the energy industry and with residential and commercial energy consumers. These transactions principally occur in the Northeast, mid-Atlantic and Midwest regions of the U.S. Dominion Energy Gas does not believe that this geographic concentration contributes to its overall exposure to credit risk. In addition, as a result of its large and diverse customer base, Dominion Energy Gas is not exposed to a significant concentration of credit risk for receivables arising from gas utility operations. Dominion Energy Gas’ gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. At December 31, 2018, Dominion Energy Gas’ credit exposure totaled $8 million. Of this amount, investment grade counterparties, including those internally rated, represented 93%, and no single counterparty, whether investment grade or non-investment grade, exceeded $5 million of exposure.

In 2018, DETI provided service to 307 customers with approximately 96% of its storage and transportation revenue being provided through firm services. The ten largest customers provided approximately 38% of the total storage and transportation revenue and the thirty largest provided approximately 71% of the total storage and transportation revenue.

East Ohio distributes natural gas to residential, commercial and industrial customers in Ohio using rates established by the Ohio Commission. Approximately 99% of East Ohio revenues are derived from its regulated gas distribution services. East Ohio’s bad debt risk is mitigated by the regulatory framework established by the Ohio Commission. See Note 13 for further information about Ohio’s PIPP and UEX Riders that mitigate East Ohio’s overall credit risk.

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 December 31, 2018 and 2017, Dominion Energy would have been required to post an additional $1 million and $62 million, respectively, of collateral to its counterparties. The collateral that would be required to be posted includes the impacts of any offsetting asset positions and any amounts already posted for derivatives, non-derivative contracts and derivatives elected under the normal purchases and normal sales exception, per contractual terms. Dominion Energy had posted no collateral at December 31, 2018 and 2017, related to derivatives with credit-related contingent provisions that are in a liability position and not fully collateralized with cash. 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 as of December 31, 2018 and 2017 was $1 million and $65 million, respectively, 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 December 31, 2018 and 2017. See Note 7 for further information about derivative instruments.

NOTE 24. RELATED-PARTY TRANSACTIONS

Virginia Power and Dominion Energy Gas engage in related party transactions primarily with other Dominion Energy subsidiaries (affiliates). Virginia Power 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 consolidated federal income tax return and, where applicable, combined income tax returns for Dominion Energy are filed in various states. See Note 2 for further information. Dominion Energy’s transactions with equity method investments are described in Note 9. A discussion of significant related party transactions follows.

VIRGINIA POWER

Transactions with Affiliates

Virginia Power transacts with affiliates for certain quantities of natural gas and other commodities in the ordinary course of business. Virginia Power also enters into certain commodity derivative contracts with affiliates. Virginia Power uses these contracts, which are principally comprised of forward commodity purchases, to manage commodity price risks associated with purchases of natural gas. See Notes 7 and 19 for more information. As of December 31, 2018, Virginia Power’s derivative assets and liabilities with affiliates were $26 million and $10 million, respectively. As of December 31, 2017, Virginia Power’s derivative assets and liabilities with affiliates were $11 million and $5 million, respectively.

Virginia Power participates in certain Dominion Energy benefit plans as described in Note 21. At December 31, 2018 and 2017, Virginia Power’s amounts due to Dominion Energy associated with the Dominion Energy Pension Plan and reflected in noncurrent pension and other postretirement benefit liabilities in the Consolidated Balance Sheets were $632 million and $505 million, respectively. At December 31, 2018 and 2017, Virginia Power’s amounts due from Dominion Energy associated with the Dominion Energy Retiree Health and Welfare Plan and reflected in noncurrent pension and other postretirement benefit assets in the Consolidated Balance Sheets were $254 million and $199 million, respectively.

DES and other affiliates provide accounting, legal, finance and certain administrative and technical services 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 serv-


184

ice. Management believes the assumptions and methodologies underlying the allocation of general corporate overhead expenses are reasonable.

Presented below are significant transactions with DES and other affiliates:


Year Ended December 31,	2018			2017			2016
(millions)
Commodity purchases from affiliates		$	930		$	674		$	571
Services provided by affiliates(1)			450			453			454
Services provided to affiliates			24			25			22

(1)	Includes capitalized expenditures of $145 million, $144 million and $144 million for the year ended December 31, 2018, 2017 and 2016, respectively.

Virginia Power has borrowed funds from Dominion Energy under short-term borrowing arrangements. There were $224 million and $33 million in short-term demand note borrowings from Dominion Energy as of December 31, 2018 and 2017, respectively. The weighted-average interest rate of these borrowings was 2.94% and 1.65% at December 31, 2018 and 2017, respectively. Virginia Power had no outstanding borrowings, net of repayments under the Dominion Energy money pool for its nonregulated subsidiaries as of December 31, 2018 and 2017. Interest charges related to Virginia Power’s borrowings from Dominion Energy were immaterial for the years ended December 31, 2018, 2017 and 2016.

There were no issuances of Virginia Power’s common stock to Dominion Energy in 2018, 2017 or 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, and related parties, including construction services, which are presented separately from contracts involving commodities or services. As of December 31, 2018 and 2017, all of Dominion Energy Gas’ commodity derivatives were with affiliates. See Notes 7 and 19 for more information. See Note 9 for information regarding transactions with an affiliate.

Dominion Energy Gas participates in certain Dominion Energy benefit plans as described in Note 21. At December 31, 2018 and 2017, Dominion Energy Gas’ amounts due from Dominion Energy associated with the Dominion Energy Pension Plan and reflected in noncurrent pension and other postretirement benefit assets in the Consolidated Balance Sheets were $772 million and $734 million, respectively. Dominion Energy Gas’ amounts due from Dominion Energy associated with the Dominion Energy Retiree Health and Welfare Plan and reflected in noncurrent pension and other postretirement benefit assets in the Consolidated Balance Sheets were $14 million and $7 million at December 31, 2018 and 2017, respectively.

DES and other affiliates provide accounting, legal, finance and certain administrative and technical services to Dominion Energy Gas. Dominion Energy Gas provides certain services to related parties, including technical services.

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:


Year Ended December 31,	2018			2017			2016
(millions)
Sales of natural gas and transportation and storage services to affiliates		$	58		$	70		$	69
Purchases of natural gas from affiliates			6			5			9
Services provided by related parties(1)			131			143			141
Services provided to related parties(2)			216			156			128

(1)	Includes capitalized expenditures of $37 million, $45 million and $49 million for the year ended December 31, 2018, 2017 and 2016, respectively.

(2)	Amounts primarily attributable to Atlantic Coast Pipeline, a related party VIE.

The following table presents affiliated and related party balances reflected in Dominion Energy Gas’ Consolidated Balance Sheets:


At December 31,	2018			2017
(millions)
Other receivables(1)		$	13		$	12
Customer receivables from related parties			1			1
Imbalances receivable from affiliates			1			1
Imbalances payable to affiliates(2)			13			—
Affiliated notes receivable(3)			16			20

(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 IRCA with Dominion Energy totaled $218 million and $18 million as of December 31, 2018 and 2017, respectively. The weighted-average interest rate of these borrowings was 2.78% and 1.60% at December 31, 2018 and 2017, respectively. Interest charges related to Dominion Energy Gas’ total borrowings from Dominion Energy were immaterial for 2018, 2017 and 2016.


				185

Combined Notes to Consolidated Financial Statements, Continued

NOTE 25. OPERATING SEGMENTS

The Companies are organized primarily on the basis of products and services sold in the U.S. 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 generation fleet	X	X
	Merchant electric generation fleet	X
Gas Infrastructure	Gas transmission and storage	X(1)		X
	Gas distribution and storage	X		X
	Gas gathering and processing	X		X
	LNG terminalling and storage	X
	Nonregulated retail energy marketing	X

(1)	Includes remaining producer services activities.

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). 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 2018, Dominion Energy reported after-tax net expenses of $608 million in the Corporate and Other segment, with $88 million of the net expenses attributable to specific items related to its operating segments.

The net expenses for specific items in 2018 primarily related to the impact of the following items:

•		A $219 million ($164 million after-tax) charge related to the impairment of certain gathering and processing assets attributable to Gas Infrastructure;

•		A $215 million ($160 million after-tax) charge associated with Virginia legislation enacted in March 2018 that requires one-time rate credits of certain amounts to utility customers, attributable to:

	•		Power Generation ($109 million after-tax); and

	•		Power Delivery ($51 million after-tax);

•		A $170 million ($134 million after-tax) net loss related to our investments in nuclear decommissioning trust funds attributable to Power Generation;

•		A $124 million ($88 million after-tax) charge for disallowance of FERC-regulated plant attributable to Gas Infrastructure;

•		An $81 million ($60 million after-tax) charge associated primarily with the asset retirement obligations for ash ponds and landfills at certain utility generation facilities in connection with the enactment of Virginia legislation in April 2018 attributable to Power Generation; and

•		A $70 million ($52 million after-tax) charge associated with major storm damage and service restoration attributable to Power Delivery; partially offset by

•		An $828 million ($619 million after-tax) benefit associated with the sale of certain merchant generation facilities and equity method investments attributable to:

	•		Power Generation ($229 million after-tax); and

	•		Gas Infrastructure ($390 million after-tax).

In 2017, Dominion Energy reported after-tax net benefits of $389 million in the Corporate and Other segment, with $861 million of the net benefits attributable to specific items related to its operating segments.

The net benefits for specific items in 2017 primarily related to the impact of the following items:

•		A $979 million tax benefit resulting from the remeasurement of deferred income taxes as a result of the 2017 Tax Reform Act, primarily attributable to:

	•		Gas Infrastructure ($324 million);

	•		Power Generation ($655 million); partially offset by

•		$158 million ($96 million after-tax) of charges associated with equity method investments in wind-powered generation facilities, attributable to Power Generation.

In 2016, Dominion Energy reported after-tax net expenses of $484 million in the Corporate and Other segment, with $180 million of these net expenses attributable to specific items related to its operating segments.

The net expenses for specific items in 2016 primarily related to the impact of the following items:

•		A $197 million ($122 million after-tax) charge related to future ash pond and landfill closure costs at certain utility generation facilities, attributable to Power Generation; and

•		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).


186

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


Year Ended December 31,	Power Delivery		Power Generation			Gas Infrastructure			Corporate and Other			Adjustments & Eliminations			Consolidated Total
(millions)
2018
Total revenue from external customers	$	2,206	$	7,104		$	4,221		$	(208	)	$	43		$	13,366
Intersegment revenue		23		11			27			674			(735	)		—
Total operating revenue		2,229		7,115			4,248			466			(692	)		13,366
Depreciation, depletion and amortization		625		746			615			14			—			2,000
Impairment of assets and related charges		—		1			8			394			—			403
Gains on sales of assets		—		6			(186	)		(200	)		—			(380	)
Equity in earnings of equity method investees		—		18			178			1			—			197
Interest income		—		90			64			126			(196	)		84
Interest and related charges		265		374			268			782			(196	)		1,493
Income tax expense (benefit)		160		294			330			(204	)		—			580
Net income (loss) attributable to Dominion Energy		587		1,254			1,214			(608	)		—			2,447
Investment in equity method investees		—		82			1,159			37			—			1,278
Capital expenditures		1,564		1,321			1,415			105			—			4,405
Total assets (billions)		17.8		28.2			31.5			11.2			(10.8	)		77.9
2017
Total revenue from external customers	$	2,206	$	6,676		$	2,832		$	16		$	856		$	12,586
Intersegment revenue		22		10			834			610			(1,476	)		—
Total operating revenue		2,228		6,686			3,666			626			(620	)		12,586
Depreciation, depletion and amortization		593		747			522			43			—			1,905
Impairment of assets and related charges		—		—			—			15			—			15
Gains on sales of assets		—		—			(147	)		—			—			(147	)
Equity in earnings of equity method investees		—		(181	)		159			4			—			(18	)
Interest income		4		92			45			96			(155	)		82
Interest and related charges		265		342			109			644			(155	)		1,205
Income tax expense (benefit)		334		373			487			(1,224	)		—			(30	)
Net income (loss) attributable to Dominion Energy		531		1,181			898			389			—			2,999
Investment in equity method investees		—		81			1,422			41			—			1,544
Capital expenditures		1,433		2,275			2,149			52			—			5,909
Total assets (billions)		16.7		29.0			28.0			12.0			(9.1	)		76.6
2016
Total revenue from external customers	$	2,210	$	6,747		$	2,069		$	(7	)	$	718		$	11,737
Intersegment revenue		23		10			697			609			(1,339	)		—
Total operating revenue		2,233		6,757			2,766			602			(621	)		11,737
Depreciation, depletion and amortization		537		662			330			30			—			1,559
Impairment of assets and related charges		—		—			—			4			—			4
Gains on sales of assets		—		4			(44	)		—			—			(40	)
Equity in earnings of equity method investees		—		(16	)		105			22			—			111
Interest income		—		74			34			36			(78	)		66
Interest and related charges		244		290			38			516			(78	)		1,010
Income tax expense (benefit)		308		279			431			(363	)		—			655
Net income (loss) attributable to Dominion Energy		484		1,397			726			(484	)		—			2,123
Capital expenditures		1,320		2,440			2,322			43			—			6,125

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 majority of Virginia Power’s revenue is provided through tariff rates. Generally, such revenue is allocated for management reporting based on an unbundled rate methodology among Virginia Power’s Power Delivery and Power Generation segments.

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 2018, Virginia Power reported an after-tax net expense of $312 million for specific items attributable to its operating segments in the Corporate and Other segment.

The net expenses for specific items in 2018 primarily related to the impact of the following items:

•		A $215 million ($160 million after-tax) charge associated with Virginia legislation enacted in March 2018 that requires one-time rate credits of certain amounts to utility customers, attributable to:

	•		Power Generation ($109 million after-tax); and

	•		Power Delivery ($51 million after-tax).

•		An $81 million ($60 million after-tax) charge associated primarily with the asset retirement obligations for ash ponds and landfills at certain utility generation facilities in connection with the enactment of Virginia legislation in April 2018 attributable to Power Generation.

•		A $70 million ($52 million after-tax) charge associated with major storm damage and service restoration attributable to Power Delivery.


				187

Combined Notes to Consolidated Financial Statements, Continued

In 2017, Virginia Power reported an after-tax net benefit of $74 million for specific items attributable to its operating segments in the Corporate and Other segment.

The net benefit for specific items in 2017 primarily related to the impact of the following item:

•		A $93 million tax benefit resulting from the remeasurement of deferred income taxes as a result of the 2017 Tax Reform Act, attributable to Power Generation.

In 2016, Virginia Power reported after-tax net expenses of $173 million for specific items attributable to its operating segments in the Corporate and Other segment.

The net expenses for specific items in 2016 primarily related to the impact of the following item:

•		A $197 million ($121 million after-tax) charge related to future ash pond and landfill closure costs at certain utility generation facilities, attributable to Power Generation.


188

The following table presents segment information pertaining to Virginia Power’s operations:


Year Ended December 31,	Power Delivery		Power Generation		Corporate and Other			Adjustments & Eliminations			Consolidated Total
(millions)
2018
Operating revenue	$	2,204	$	5,630	$	(215	)	$	—		$	7,619
Depreciation and amortization		624		533		(25	)		—			1,132
Interest income		—		9		5			(4	)		10
Interest and related charges		265		250		—			(4	)		511
Income tax expense (benefit)		158		220		(78	)		—			300
Net income (loss)		586		1,008		(312	)		—			1,282
Capital expenditures		1,539		1,003		—			—			2,542
Total assets (billions)		17.6		19.4		—			(0.1	)		36.9
2017
Operating revenue	$	2,212	$	5,344	$	—		$	—		$	7,556
Depreciation and amortization		594		547		—			—			1,141
Interest income		4		15		3			(3	)		19
Interest and related charges		265		232		—			(3	)		494
Income tax expense (benefit)		334		534		(94	)		—			774
Net income		527		939		74			—			1,540
Capital expenditures		1,439		1,290		—			—			2,729
Total assets (billions)		16.6		18.6		—			(0.1	)		35.1
2016
Operating revenue	$	2,217	$	5,390	$	(19	)	$	—		$	7,588
Depreciation and amortization		537		488		—			—			1,025
Interest income		—		—		—			—			—
Interest and related charges		244		219		—			(2	)		461
Income tax expense (benefit)		307		524		(104	)		—			727
Net income (loss)		482		909		(173	)		—			1,218
Capital expenditures		1,313		1,336		—			—			2,649

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 2018, Dominion Energy Gas reported after-tax net expenses of $251 million in its Corporate and Other segment, with $244 million of these net expenses attributable to its operating segment.

The net expenses for specific items in 2018 primarily related to the impact of the following items:

•		A $219 million ($165 million after-tax) charge related to the impairment of gathering and processing assets; and

•		A $124 million ($88 million after-tax) charge for disallowance of FERC-regulated plant.

In 2017, Dominion Energy Gas reported after-tax net benefit of $179 million in its Corporate and Other segment, with $174 million of these net expenses attributable to its operating segment.

The net benefit for specific items in 2017 primarily related to the impact of the following item:

•		A $185 million tax benefit resulting from the remeasurement of deferred income taxes as a result of the 2017 Tax Reform Act.

In 2016, Dominion Energy Gas reported after-tax net expenses of $3 million in its Corporate and Other segment, with $7 million of these net expenses attributable to its operating segment.

The net expense for specific items in 2016 primarily related to the impact of the following item:

•		An $8 million ($5 million after-tax) charge related to an organizational design initiative.


				189

Combined Notes to Consolidated Financial Statements, Continued

The following table presents segment information pertaining to Dominion Energy Gas’ operations:


Year Ended December 31,	Gas Infrastructure			Corporate and Other			Consolidated Total
(millions)
2018
Operating revenue	$	1,940		$	—		$	1,940
Depreciation and amortization		244			—			244
Impairment of assets and related charges		5			341			346
Gains on sales of assets		(119	)		—			(119	)
Equity in earnings of equity method investees		24			—			24
Interest income		2			—			2
Interest and related charges		104			1			105
Income tax expense (benefit)		188			(102	)		86
Net income (loss)		552			(251	)		301
Investment in equity method investees		91			—			91
Capital expenditures		772			—			772
Total assets (billions)		11.8			0.6			12.4
2017
Operating revenue	$	1,814		$	—		$	1,814
Depreciation and amortization		227			—			227
Impairment of assets and related charges		15			1			16
Gains on sales of assets		(70	)		—			(70	)
Equity in earnings of equity method investees		21			—			21
Interest income		2			—			2
Interest and related charges		97			—			97
Income tax expense (benefit)		256			(205	)		51
Net income		436			179			615
Investment in equity method investees		95			—			95
Capital expenditures		778			—			778
Total assets (billions)		11.3			0.6			11.9
2016
Operating revenue	$	1,638		$	—		$	1,638
Depreciation and amortization		214			(10	)		204
Gains on sales of assets		(45	)		—			(45	)
Equity in earnings of equity method investees		21			—			21
Interest income		1			—			1
Interest and related charges		92			2			94
Income tax expense (benefit)		237			(22	)		215
Net income (loss)		395			(3	)		392
Capital expenditures		854			—			854


190

NOTE 26. QUARTERLY FINANCIAL DATA (UNAUDITED)

A summary of the Companies’ quarterly results of operations for the years ended December 31, 2018 and 2017 follows. Amounts reflect all adjustments necessary in the opinion of management for a fair statement of the results for the interim periods. Results for interim periods may fluctuate as a result of weather conditions, changes in rates and other factors.

DOMINION ENERGY


	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
(millions)
2018
Operating revenue	$	3,466	$	3,088	$	3,451	$	3,361
Income from operations		875		742		1,150		834
Net income including noncontrolling interests		526		478		883		662
Net income attributable to Dominion Energy		503		449		854		641
Basic EPS:
Net income attributable to Dominion Energy		0.77		0.69		1.31		0.97
Diluted EPS:
Net income attributable to Dominion Energy		0.77		0.69		1.30		0.97
Dividends declared per common share		0.835		0.835		0.835		0.835
2017
Operating revenue	$	3,384	$	2,813	$	3,179	$	3,210
Income from operations		1,079		753		1,152		953
Net income including noncontrolling interests		674		417		696		1,333
Net income attributable to Dominion Energy		632		390		665		1,312
Basic EPS:
Net income attributable to Dominion Energy		1.01		0.62		1.03		2.04
Diluted EPS:
Net income attributable to Dominion Energy		1.01		0.62		1.03		2.04
Dividends declared per common share		0.755		0.755		0.770		0.770

Dominion Energy’s 2018 results include the impact of the following significant items:

•		Fourth quarter results include $536 million of after-tax gains from the sale of certain merchant generation facilities and equity method investments partially offset by a $164 million after-tax impairment charge for certain gathering and processing assets.

•		Second quarter results include an $89 million after-tax charge for disallowance of FERC-regulated plant.

•		First quarter results include a $160 million after-tax charge associated with Virginia legislation enacted in March 2018 that required one-time rate credits of certain amounts to utility customers.

Dominion Energy’s 2017 results include the impact of the following significant item:

•		Fourth quarter results include $851 million tax benefit resulting from the remeasurement of deferred income taxes as a result of the 2017 Tax Reform Act, partially offset by $96 million of after-tax charges associated with our equity method investments in wind-powered generation facilities.

VIRGINIA POWER

Virginia Power’s quarterly results of operations were as follows:


	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
(millions)

2018
Operating revenue	$	1,748	$	1,829	$	2,232	$	1,810
Income from operations		364		533		756		418
Net income		184		339		520		239
2017
Operating revenue	$	1,831	$	1,747	$	2,154	$	1,824
Income from operations		653		613		847		619
Net income		356		318		459		407

Virginia Power’s 2018 results include the impact of the following significant item:

•		First quarter results include a $160 million after-tax charge associated with Virginia legislation enacted in March 2018 that required one-time rate credits of certain amounts to utility customers.

Virginia Power’s 2017 results include the impact of the following significant item:

•		Fourth quarter results include a $93 million tax benefit resulting from the remeasurement of deferred income taxes as a result of the 2017 Tax Reform Act.

DOMINION ENERGY GAS

Dominion Energy Gas’ quarterly results of operations were as follows:


	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
(millions)
2018
Operating revenue		$526		$459		$423		$532
Income (loss) from operations		201		7		182		(55	)
Net income (loss)	166		15		136		(16)
2017
Operating revenue		$490		$422		$401		$501
Income from operations		156		116		185		181
Net income		108		77		117		313

Dominion Energy Gas’s 2018 results include the impact of the following significant items:

	•		Fourth quarter results include a $165 million after-tax impairment charge for certain gathering and processing assets.

	•		Second quarter results include an $89 million after-tax charge for disallowance of FERC-regulated plant.

Dominion Energy Gas’s 2017 results include the impact of the following significant item:

	•		Fourth quarter results include a $197 million tax benefit resulting from the remeasurement of deferred income taxes as a result of the 2017 Tax Reform Act.


				191

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