Edgar Filing: DOMINION RESOURCES INC /VA/

Three Months Ended
March 31,

(millions)

Operating revenue

Income before income taxes

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark one)

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2008

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 001-08489

LOGO

DOMINION RESOURCES, INC.

(Exact name of registrant as specified in its charter)

VIRGINIA

54-1229715

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

120 TREDEGAR STREET

RICHMOND, VIRGINIA

23219

(Address of principal executive offices)

(Zip Code)

(804) 819-2000

(Registrant’s telephone number)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer x

Accelerated filer ¨

Non-accelerated filer ¨

Smaller reporting company ¨

(Do not check if a smaller

reporting company)

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act). Yes ¨ No x

At March 31, 2008, the latest practicable date for determination, 577,996,257 shares of common stock, without par value, of the registrant were outstanding.

DOMINION RESOURCES, INC.

INDEX


		Page Number
	Glossary of Terms	3

	PART I. Financial Information

Item 1.	Consolidated Financial Statements

	Consolidated Statements of Income – Three Months Ended March 31, 2008 and 2007	4

	Consolidated Balance Sheets – March 31, 2008 and December 31, 2007	5

	Consolidated Statements of Cash Flows – Three Months Ended March 31, 2008 and 2007	7

	Notes to Consolidated Financial Statements	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	38

Item 4.	Controls and Procedures	39
	PART II. Other Information

Item 1.	Legal Proceedings	40

Item 1A.	Risk Factors	40

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	41

Item 6.	Exhibits	42

PAGE 2

GLOSSARY OF TERMS

The following abbreviations or acronyms used in this Form 10-Q are defined below:


Abbreviation or Acronym		Definition
AOCI		Accumulated other comprehensive income (loss)
bcf		Billion cubic feet
bcfe		Billion cubic feet equivalent
Brayton Point		Brayton Point power station
CDO		Collateralized debt obligation
CEO		Chief Executive Officer
CFO		Chief Financial Officer
DCI		Dominion Capital, Inc.
DD&A		Depreciation, depletion and amortization expense
DEI		Dominion Energy, Inc.
DEPI		Dominion Exploration & Production, Inc.
Dominion East Ohio		The East Ohio Gas Company
DTI		Dominion Transmission, Inc.
DVP		The Dominion Virginia Power operating segment
E&P		Exploration & production
EITF		Emerging Issues Task Force
EPA		The Environmental Protection Agency
EPS		Earnings per share
Equitable		Equitable Resources, Inc.
FASB		Financial Accounting Standards Board
FIN		FASB Interpretation No.
FSP		FASB Staff Position
FTRs		Financial transmission rights
GAAP		U.S. generally accepted accounting principles
Gichner		Gichner LLC
Hope		Hope Gas, Inc.
LNG		Liquefied natural gas
Local 69-II		The Utility Workers’ Union of America, United Gas Workers’ Local 69-II, AFL-CIO
mcf		Thousand cubic feet
mcfe		Thousand cubic feet equivalent
MD&A		Management’s Discussion and Analysis of Financial Condition and Results of Operations
Moody’s		Moody’s Investors Services
Mw		Megawatt
mwhrs		Megawatt hours
North Anna		North Anna power station
NRC		The Nuclear Regulatory Commission
ODEC		Old Dominion Electric Cooperative
Peaker facilities		Collectively, the three natural gas-fired merchant generation peaking facilities sold in March 2007
Peoples		The Peoples Natural Gas Company
PJM		PJM Interconnection, LLC
RTO		Regional transmission organization
SEC		The Securities and Exchange Commission
SFAS		Statement of Financial Accounting Standards
State Line		State Line power station
U.S.		The United States of America
VIEs		Variable interest entities
Virginia City Hybrid Energy Center		A 585 Mw (nominal) coal-fired electric generation facility to be located in Wise County, Virginia
Virginia Commission		The Virginia State Corporation Commission
Virginia Power		Virginia Electric and Power Company
VPEM		Virginia Power Energy Marketing, Inc.
West Virginia Commission		The Public Services Commission of West Virginia

PAGE 3

DOMINION RESOURCES, INC.

PART I. FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)


	Three Months Ended March 31,
	2008			2007
(millions, except per share amounts)
Operating Revenue	$	4,389		$	4,661
Operating Expenses
Electric fuel and energy purchases		806			918
Purchased electric capacity		107			119
Purchased gas		1,187			1,148
Other energy-related commodity purchases		13			56
Other operations and maintenance		809			828
Depreciation, depletion and amortization		254			409
Other taxes		154			183

Total operating expenses		3,330			3,661

Income from operations		1,059			1,000

Other income (loss)		(3	)		49
Interest and related charges:
Interest expense		188			220
Interest expense – junior subordinated notes payable⁽¹⁾		27			35
Subsidiary preferred dividends		4			4

Total interest and related charges		219			259

Income from continuing operations before income taxes and minority interest		837			790
Income tax expense		157			310
Minority interest		—			5

Income from continuing operations		680			475
Loss from discontinued operations		—			(22	)

Net Income	$	680		$	453

Earnings Per Common Share – Basic and Diluted
Income from continuing operations	$	1.18		$	0.68
Loss from discontinued operations		—			(0.03	)

Net income	$	1.18		$	0.65

Dividends paid per common share	$	0.395		$	0.355

(1)	Includes $13 million and $22 million incurred with affiliated trusts for the three months ended March 31, 2008 and 2007, respectively.

The accompanying notes are an integral part of our Consolidated Financial Statements.

PAGE 4

DOMINION RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)


	March 31, 2008			December 31, 2007 ⁽¹⁾
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	79		$	283
Customer receivables (less allowance for doubtful accounts of $29 and $37)		2,239			2,130
Other receivables (less allowance for doubtful accounts of $8 and $10)		217			226
Inventories		838			1,045
Derivative assets		795			775
Assets held for sale		1,182			1,160
Prepayments		204			387
Other		925			664

Total current assets		6,479			6,670

Investments
Nuclear decommissioning trust funds		2,739			2,888
Other		753			992

Total investments		3,492			3,880

Property, Plant and Equipment
Property, plant and equipment		33,844			33,331
Accumulated depreciation, depletion and amortization		(12,188	)		(11,979	)

Total property, plant and equipment, net		21,656			21,352

Deferred Charges and Other Assets
Goodwill		3,496			3,496
Pension and other postretirement benefit assets		1,572			1,565
Other		2,357			2,176

Total deferred charges and other assets		7,425			7,237

Total assets	$	39,052		$	39,139

(1)

Our Consolidated Balance Sheet at December 31, 2007 has been derived from the audited Consolidated Financial Statements at that date and includes the impact of adopting FSP No. FIN 39-1, Amendment of FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts, as discussed in Note 3.

The accompanying notes are an integral part of our Consolidated Financial Statements.

PAGE 5

DOMINION RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)


	March 31, 2008			December 31, 2007 ⁽¹⁾
(millions)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Securities due within one year	$	1,043		$	1,477
Short-term debt		2,375			1,757
Accounts payable		1,497			1,734
Accrued interest, payroll and taxes		681			934
Derivative liabilities		1,171			694
Liabilities held for sale		531			492
Other		624			672

Total current liabilities		7,922			7,760

Long-Term Debt
Long-term debt		11,335			11,759
Junior subordinated notes payable:
Affiliates		678			678
Other		798			798

Total long-term debt		12,811			13,235

Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		4,214			4,253
Asset retirement obligations		1,746			1,722
Other		2,577			2,478

Total deferred credits and other liabilities		8,537			8,453

Total liabilities		29,270			29,448

Commitments and Contingencies (see Note 16)
Minority Interest		—			28
Subsidiary Preferred Stock Not Subject to Mandatory Redemption		257			257
Common Shareholders’ Equity
Common stock – no par ⁽²⁾		5,789			5,733
Other paid-in capital		180			175
Retained earnings		3,960			3,510
Accumulated other comprehensive loss		(404	)		(12	)

Total common shareholders’ equity		9,525			9,406

Total liabilities and shareholders’ equity	$	39,052		$	39,139

(1)	Our Consolidated Balance Sheet at December 31, 2007 has been derived from the audited Consolidated Financial Statements at that date and includes the impact of adopting FSP No. FIN 39-1, as discussed in Note 3.

(2)	1 billion shares authorized; 578 million shares outstanding at March 31, 2008 and 577 million shares outstanding at December 31, 2007.

The accompanying notes are an integral part of our Consolidated Financial Statements.

PAGE 6

DOMINION RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


Three Months Ended March 31,	2008			2007
(millions)
Operating Activities
Net income	$	680		$	453
Adjustments to reconcile net income to net cash provided by operating activities:
Dominion Capital, Inc. (DCI) impairment loss		62			—
Net realized and unrealized derivative losses		18			47
Depreciation, depletion and amortization		294			458
Deferred income taxes and investment tax credits, net		(55	)		205
Changes in:
Accounts receivable		(188	)		(169	)
Inventories		196			391
Deferred fuel and purchased gas costs, net		(140	)		2
Accounts payable		(254	)		(131	)
Accrued interest, payroll and taxes		(250	)		(142	)
Margin deposit assets and liabilities		(250	)		(68	)
Prepayments		183			38
Other operating assets and liabilities		255			126

Net cash provided by operating activities		551			1,210

Investing Activities
Plant construction and other property additions		(650	)		(471	)
Additions to gas and oil properties, including acquisitions		(47	)		(576	)
Net proceeds from sale of merchant generation peaking facilities		—			257
Proceeds from sale of securities and loan receivable collections and payoffs		651			287
Purchases of securities and loan receivable originations		(608	)		(304	)
Other		(64	)		11

Net cash used in investing activities		(718	)		(796	)

Financing Activities
Issuance of short-term debt, net		619			418
Issuance of long-term debt		30			—
Repayment of long-term debt		(510	)		(720	)
Issuance of common stock		58			88
Common dividend payments		(228	)		(249	)
Other		(4	)		15

Net cash used in financing activities		(35	)		(448	)

Decrease in cash and cash equivalents		(202	)		(34	)
Cash and cash equivalents at beginning of period ⁽¹⁾		287			142

Cash and cash equivalents at end of period ⁽²⁾	$	85		$	108

Significant Noncash Investing and Financing Activities
Accrued capital expenditures	$	60		$	205

(1)	2008 and 2007 amounts include $4 million of cash classified as held for sale on the Consolidated Balance Sheets.

(2)	2008 and 2007 amounts include $6 million and $5 million of cash classified as held for sale on the Consolidated Balance Sheet.

The accompanying notes are an integral part of our Consolidated Financial Statements.

PAGE 7

DOMINION RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1.

Nature of Operations

Dominion, headquartered in Richmond, Virginia, is one of the nation’s largest producers and transporters of energy. Our principal subsidiaries are Virginia Electric and Power Company (Virginia Power), Dominion Energy, Inc. (DEI), Dominion Transmission, Inc. (DTI), Virginia Power Energy Marketing, Inc. (VPEM), Dominion Exploration & Production, Inc. (DEPI) and The East Ohio Gas Company (Dominion East Ohio).

Virginia Power is a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and northeastern North Carolina. As of March 31, 2008, Virginia Power served approximately 2.4 million retail customer accounts, including governmental agencies, as well as wholesale customers such as rural electric cooperatives and municipalities. Virginia Power is a member of PJM Interconnection, LLC (PJM), a regional transmission organization (RTO), and its electric transmission facilities are integrated into the PJM wholesale electricity markets.

DEI engages in merchant generation, energy marketing and price risk management activities and natural gas exploration and production in the Appalachian basin of the U.S.

DTI operates a regulated interstate natural gas transmission pipeline and underground storage system in the Northeast, mid-Atlantic and Midwest states and is engaged in the production, gathering and extraction of natural gas in the Appalachian basin.

VPEM provides fuel, gas supply management and price risk management services to other Dominion affiliates and engages in energy trading activities.

DEPI explores for, develops and produces natural gas and oil in the Appalachian basin of the U.S.

As of March 31, 2008, our regulated gas distribution subsidiaries, Dominion East Ohio, The Peoples Natural Gas Company (Peoples) and Hope Gas, Inc. (Hope), served approximately 1.7 million residential, commercial and industrial gas sales and transportation customer accounts in Ohio, Pennsylvania and West Virginia. Approximately 500,000 of these customers are served by Peoples and Hope, which are held for sale, as discussed in Note 5.

We also operate a liquefied natural gas (LNG) import and storage facility in Maryland. Our producer services operations involve the aggregation of natural gas supply and related wholesale activities. We also have nonregulated retail energy marketing operations that include the marketing of gas, electricity and related products and services to residential and small commercial customers. As of March 31, 2008, our retail energy marketing operations served approximately 1.6 million residential and small commercial customer accounts in the Northeast, mid-Atlantic and Midwest regions of the U.S.

We manage our daily operations through three primary operating segments: Dominion Virginia Power (DVP), Dominion Energy and Dominion Generation. In addition, we also report a Corporate and Other segment that includes our service company functions, as well as the net impact of certain operations disposed of or to be disposed of, as discussed in Note 5. Our assets remain wholly owned by us and our legal subsidiaries.

The terms “Dominion,” “Company,” “we,” “our” and “us” are used throughout this report and, depending on the context of their use, may represent any of the following: the legal entity, Dominion Resources, Inc., one or more of Dominion Resources, Inc.’s consolidated subsidiaries or operating segments, or the entirety of Dominion Resources, Inc. and its consolidated subsidiaries.

Note 2.

Significant Accounting Policies

As permitted by the rules and regulations of the Securities and Exchange Commission (SEC), our accompanying unaudited Consolidated Financial Statements contain certain condensed financial information and exclude certain footnote disclosures normally included in annual audited consolidated financial statements prepared in accordance with U.S. generally accepted accounting principles (GAAP). These unaudited Consolidated Financial Statements should be read in conjunction with our Consolidated Financial Statements and Notes in our Annual Report on Form 10-K for the year ended December 31, 2007.

PAGE 8

In our opinion, the accompanying unaudited Consolidated Financial Statements contain all adjustments, including normal recurring accruals, necessary to present fairly our financial position as of March 31, 2008 and our results of operations and cash flows for the three months ended March 31, 2008 and 2007.

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

Our accompanying unaudited Consolidated Financial Statements include, after eliminating intercompany transactions and balances, our accounts and those of our majority-owned subsidiaries.

In accordance with GAAP, we report certain contracts and instruments at fair value. Observable market prices are used to measure fair value when available. In the absence of this information, we estimate fair value based on near-term and historical price information and statistical methods. For individual contracts, the use of differing assumptions could have a material effect on the contract’s estimated fair value. See Note 10 for further information on fair value measurements in accordance with Statement of Financial Accounting Standards (SFAS) No. 157, Fair Value Measurements.

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

Certain amounts in our 2007 Consolidated Financial Statements and Notes have been recast to conform to the 2008 presentation. See Note 3 for discussion of 2007 amounts that have been recast due to the adoption of FSP No. FIN 39-1, Amendment of FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts.

Note 3.

Newly Adopted Accounting Standards

SFAS No. 157

We adopted the provisions of SFAS No. 157, effective January 1, 2008. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures related to fair value measurements. SFAS No. 157 applies broadly to financial and non-financial assets and liabilities that are measured at fair value under other authoritative accounting pronouncements, but does not expand the application of fair value accounting to any new circumstances.

Generally, the provisions of this statement are applied prospectively. Certain situations, however, require retrospective application as of the beginning of the year of adoption through the recognition of a cumulative effect of accounting change. Such retrospective application is required for financial instruments, including derivatives and certain hybrid instruments with limitations on initial gains or losses under Emerging Issues Task Force (EITF) Issue No. 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities, and SFAS No. 155, Accounting for Certain Hybrid Financial Instruments. Retrospective application resulted in an immaterial amount recognized through a cumulative effect of accounting change adjustment to retained earnings as of January 1, 2008.

In February 2008, the Financial Accounting Standards Board (FASB) issued FSP FAS No. 157-1, Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13, which excludes leasing transactions from the scope of SFAS No. 157. However, the exclusion does not apply to fair value measurements of assets and liabilities recorded as a result of a lease transaction but measured pursuant to other pronouncements within the scope of SFAS No. 157.

In February 2008, the FASB issued FSP FAS No. 157-2, Effective Date of FASB Statement No. 157, which delays the effective date of SFAS No. 157 by one year (to January 1, 2009) for non-financial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). For Dominion, this delays the effective date of SFAS No. 157 primarily for goodwill, intangibles, property, plant and equipment and asset retirement obligations.

In January 2008, the FASB proposed FSP FAS No. 157-c, Measuring Liabilities Under FASB Statement No. 157, which if issued, would clarify the principles in SFAS No. 157 for the fair value measurements of liabilities. Specifically, this FSP would require an entity to measure liabilities first based on a quoted price in an active market for an identical liability, however in the absence of such information, an entity would be allowed to measure the fair value of the liability at the amount it would receive as proceeds if it were to issue that liability at the measurement date.

PAGE 9

See Note 10 for further information on fair value measurements in accordance with SFAS No. 157.

SFAS No. 159

The provisions of SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, became effective for us beginning January 1, 2008. SFAS No. 159 provides an entity with the option, at specified election dates, to measure certain financial assets and liabilities and other items at fair value, with changes in fair value recognized in earnings as those changes occur. SFAS No. 159 also establishes presentation and disclosure requirements that include displaying the fair value of those assets and liabilities for which the entity elected the fair value option on the face of the balance sheet and providing management’s reasons for electing the fair value option for each eligible item. As of March 31, 2008, we had not elected the fair value option for any eligible items. Therefore, the provisions of SFAS No. 159 have not impacted our results of operations or financial condition.

FSP FIN 39-1

FSP FIN 39-1 became effective for us beginning January 1, 2008. FSP FIN 39-1 amends FIN 39 to permit the offsetting of 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 that have been offset. Upon our adoption of FSP FIN 39-1, we revised our accounting policy to no longer offset fair value amounts recognized for certain derivative instruments and recast our prior year Consolidated Balance Sheet in order to retrospectively apply the standard. The adoption of FSP FIN 39-1 resulted in an increase in Derivative assets of $14 million, Other deferred charges and other assets of $2 million, Derivative liabilities of $14 million and Other deferred credits and other liabilities of $2 million as of December 31, 2007. The adoption of FSP FIN 39-1 had no impact on our results of operations or cash flows.

EITF 06-4

The provisions of EITF Issue No. 06-4, Accounting for Deferred Compensation and Postretirement Benefit Aspects of Endorsement Split-Dollar Life Insurance Arrangements, became effective for us beginning January 1, 2008. EITF 06-4 specifies that if an employer provides a benefit to an employee under an endorsement split-dollar life insurance arrangement that extends to postretirement periods, it should recognize a liability for future benefits in accordance with SFAS No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions (if, in substance, a postretirement benefit plan exists) or APB Opinion No. 12, Deferred Compensation Contracts (if the arrangement is, in substance, an individual deferred compensation contract) based on the substantive agreement with the employee. Retrospective application resulted in an immaterial amount recognized through a cumulative effect of accounting change adjustment to retained earnings as of January 1, 2008.

EITF 06-11

The provisions of EITF Issue No. 06-11, Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards, became effective for us beginning January 1, 2008. EITF 06-11 addresses the recognition of income tax benefits realized from dividends or dividend equivalents that are charged to retained earnings and are paid to employees for nonvested share-based payment awards that are classified as equity. Effective January 1, 2008, we began recognizing such income tax benefits as an increase to additional paid-in capital rather than as a reduction to income tax expense. Our adoption of EITF 06-11 did not have a material impact on our results of operations or financial condition.

Note 4.

Recently Issued Accounting Standards

SFAS No. 141R

In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations. SFAS No. 141R requires an acquirer to recognize the assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their acquisition-date fair values. SFAS No. 141R also requires disclosure of the information necessary for investors and other users to evaluate and understand the nature and financial effect of the business combination. Additionally, SFAS No. 141R requires that acquisition-related costs be expensed as incurred. The provisions of SFAS No. 141R will become effective for acquisitions completed on or after January 1, 2009; however, the income tax provisions of SFAS No. 141R will become effective as of that date for all acquisitions, regardless of the acquisition date. SFAS No. 141R amends SFAS No. 109, Accounting for Income Taxes, to require the acquirer to recognize changes in the amount of its deferred tax benefits recognizable due to a business combination either in income from continuing operations in the period of the combination or directly in contributed capital, depending on the circumstances. SFAS No. 141R further amends SFAS No. 109 and FIN 48, Accounting for Uncertainty in Income Taxes, to require, subsequent to a prescribed

PAGE 10

measurement period, changes to acquisition-date income tax uncertainties to be reported in income from continuing operations and changes to acquisition-date acquiree deferred tax benefits to be reported in income from continuing operations or directly in contributed capital, depending on the circumstances.

SFAS No. 160

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements. SFAS No. 160 requires that noncontrolling (minority) interests be reported as a component of equity, net income attributable to the parent and to the non-controlling interest be separately identified in the income statement, changes in a parent’s ownership interest while the parent retains its controlling interest be accounted for as equity transactions, and any retained noncontrolling equity investment upon the deconsolidation of a subsidiary be initially measured at fair value. The provisions of SFAS No. 160 will become effective for us beginning January 1, 2009. We do not expect the provisions of SFAS No. 160 to have an impact on our results of operations or financial condition.

SFAS No. 161

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities. SFAS No. 161 requires enhancements to disclosures regarding derivative instruments and hedging activities accounted for under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. The enhancements include additional disclosures regarding the reasons derivative instruments are used, how they are used, how these instruments and their related hedged items are accounted for under SFAS No. 133, as well the impact of these derivative instruments on an entity’s results of operations, financial condition and cash flows. In addition, SFAS No. 161 requires the disclosure of the fair values of derivative instruments, gains and losses in a tabular format and derivative features that are credit-risk related. The provisions of SFAS No. 161 will become effective for us beginning January 1, 2009 and will have no impact on our results of operations or financial condition.

Note 5.

Dispositions

Sale of Non-Appalachian Natural Gas and Oil E&P Operations and Assets

In 2007, we completed the sale of our non-Appalachian natural gas and oil exploration & production (E&P) operations and assets for approximately $13.9 billion. The results of operations for our U.S. non-Appalachian E&P business were not reported as discontinued operations in our Consolidated Statements of Income since we did not sell our entire U.S. cost pool, which includes the retained Appalachian assets. Due to the sale of our entire Canadian cost pool, the results of operations for our Canadian E&P business are reported as discontinued operations in our 2007 Consolidated Statement of Income. For the three months ended March 31, 2007, our Canadian E&P operations reported $41 million of operating revenue and $8 million of income before income taxes.

Sale of Merchant Generation Facilities

In March 2007, we sold three natural gas-fired merchant generation peaking facilities (Peaker facilities) for net cash proceeds of $254 million. The results of operations of the Peaker facilities are reported as discontinued operations in our 2007 Consolidated Statement of Income. For the three months ended March 31, 2007, the Peaker facilities reported $5 million of operating revenue and a $31 million loss before income taxes. The loss before income taxes includes a pre-tax loss of $25 million recognized on the sale, resulting largely from the allocation of $24 million of Generation reporting unit goodwill to the bases of the investments sold.

Sale of Certain DCI Operations

In August 2007, we completed the sale of Gichner, LLC (Gichner), all of the issued and outstanding shares of the capital stock of Gichner, Inc. (an affiliate of Gichner), as well as all of the membership interests in Dallastown Realty (Dallastown) for approximately $30 million. The results of operations of Gichner and Dallastown are reported as discontinued operations in our 2007 Consolidated Statement of Income. For the three months ended March 31, 2007, Gichner and Dallastown reported $10 million of operating revenue and $1 million of income before income taxes.

In March 2008, we entered into an agreement to sell our remaining interest in the subordinated notes of a third-party collateralized debt obligation (CDO) entity held as an investment by DCI, as discussed in Note 13.

Planned Sale of Regulated Gas Distribution Subsidiaries

In January 2008, Dominion and Equitable Resources, Inc. (Equitable) announced the termination of the agreement for the sale of Peoples and Hope, primarily due to the continued delays in achieving final regulatory approvals. We are seeking other offers for the purchase of these utilities.

PAGE 11

The carrying amounts of the major classes of assets and liabilities associated with the planned sale of Peoples and Hope and classified as held for sale in our Consolidated Balance Sheets are as follows:


	March 31, 2008			December 31, 2007
(millions)
ASSETS
Current Assets
Customer receivables	$	189		$	147
Other		79			109

Total current assets		268			256

Property, Plant and Equipment
Property, plant and equipment		1,167			1,160
Accumulated depreciation, depletion and amortization		(365	)		(367	)

Total property, plant and equipment, net		802			793

Deferred Charges and Other Assets
Regulatory assets		110			109
Other		2			2

Total deferred charges and other assets		112			111

Assets held for sale	$	1,182		$	1,160

LIABILITIES
Current Liabilities	$	247		$	210
Deferred Credits and Other Liabilities
Deferred income taxes ⁽¹⁾		204			203
Other		80			79

Liabilities held for sale	$	531		$	492

(1)	Represents net deferred tax liabilities that relate to, and are being reported with, the subsidiaries’ assets and liabilities held for sale and, that based on the expected form of the planned dispositions, would reverse upon closing.

The following table presents selected information regarding the results of operations of Peoples and Hope:

Note 6.

Operating Revenue

Our operating revenue consists of the following:


	Three Months Ended March 31,
	2008		2007
(millions)
Electric sales:
Regulated	$	1,496	$	1,411
Nonregulated		882		736
Gas sales:
Regulated		602		559
Nonregulated		891		1,263
Other energy-related commodity sales		78		280
Gas transportation and storage		389		349
Other		51		63

Total operating revenue	$	4,389	$	4,661

PAGE 12

Note 7.

Income Taxes

A reconciliation of income taxes at the U.S. statutory federal rate as compared to the income tax expense recorded for continuing operations in our Consolidated Statements of Income is presented below:


	Three Months Ended March 31,
	2008		2007
U.S. statutory rate	35.0	%	35.0	%
Increases (reductions) resulting from:
State taxes, net of federal benefit	2.1		4.6
Reversal of deferred taxes – stock of subsidiaries held for sale	(16.2	)	0.3
Legislative changes	(1.7	)	—
Other, net	(0.4	)	(0.5	)

Effective tax rate	18.8	%	39.4	%

The change in our effective tax rate for the three months ended March 31, 2008, is primarily attributable to the reversal of deferred tax liabilities, recognized in 2006, associated with the excess of our financial reporting basis over the tax basis in the stock of Peoples and Hope, in accordance with EITF Issue No. 93-17, Recognition of Deferred Tax Assets for a Parent Company’s Excess Tax Basis in the Stock of a Subsidiary that is Accounted for as a Discontinued Operation. Although these subsidiaries are not classified as discontinued operations, EITF 93-17 requires that the deferred tax impact of the excess of the financial reporting basis over the tax basis of a parent’s investment in a subsidiary be recognized when it is apparent that this difference will reverse in the foreseeable future. Based on the intended form of the sale, we recognized these deferred tax liabilities in 2006, and such difference was expected to reverse upon closing of the sale.

In January 2008, Dominion and Equitable agreed to terminate the agreement for the sale of Peoples and Hope. We now expect that the form of the ultimate disposal of these subsidiaries can be structured so that the taxable gain will be determined by reference to the basis in the subsidiaries’ underlying assets. Accordingly, in January 2008, we reversed those deferred tax liabilities ($136 million) recognized in 2006.

In addition, as the result of West Virginia income tax rate reductions, enacted in March 2008, to be phased in during the period 2009 through 2014, we reduced our net deferred tax liabilities by $13 million.

At March 31, 2008, unrecognized tax benefits related to current year tax positions are $9 million. Unrecognized tax benefits related to prior year uncertain tax positions decreased by $24 million, reflecting reductions to uncertain tax positions for amounts that would otherwise be deductible in 2008 and settlement negotiations with tax authorities.

PAGE 13

Note 8.

Earnings Per Share

The following table presents the calculation of our basic and diluted earnings per share (EPS):


	Three Months Ended March 31,
	2008		2007
(millions, except EPS)
Income from continuing operations	$	680	$	475
Loss from discontinued operations		—		(22	)

Net income	$	680	$	453

Average shares of common stock outstanding – basic		575.3		696.9
Net effect of potentially dilutive securities⁽¹⁾		3.1		4.8

Average shares of common stock outstanding – diluted		578.4		701.7

Basic and Diluted EPS
Income from continuing operations	$	1.18	$	0.68
Loss from discontinued operations		—		(0.03	)

Net income	$	1.18	$	0.65

(1)	Potentially dilutive securities consist of options, restricted stock and contingently convertible senior notes.

There were no anti-dilutive securities outstanding during the three months ended March 31, 2008 or 2007.

Note 9.

Comprehensive Income

The following table presents total comprehensive income:


	Three Months Ended March 31,
	2008			2007
(millions)
Net income	$	680		$	453
Other comprehensive income (loss):
Net other comprehensive loss associated with effective portion of changes in fair value of derivatives designated as cash flow hedges, net of taxes and amounts reclassified to earnings		(336	)		(215	)
Other, net of tax		(56	)⁽¹⁾		11

Other comprehensive loss		(392	)		(204	)

Total comprehensive income	$	288		$	249

(1)	Primarily represents a net reduction in unrealized gains on investments held in nuclear decommissioning trusts.

Note 10.

Fair Value Measurements

As described in Note 3, we adopted SFAS No. 157 effective January 1, 2008. SFAS No. 157 defines fair value 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, SFAS No. 157 permits the use of a mid-market pricing convention (the mid-point between bid and ask prices) as a practical expedient. SFAS No. 157 clarifies that fair value should be 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 our own nonperformance risk on our liabilities. SFAS No. 157 also requires fair value measurements to 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). We apply fair value measurements to certain assets and liabilities including commodity and interest rate derivative instruments, and nuclear decommissioning trust and other investments in accordance with the requirements described above.

In accordance with SFAS No. 157, we maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Fair value is based on actively-quoted market prices, if available. In the absence of

PAGE 14

actively-quoted market prices, we seek price information from external sources, including broker quotes and industry publications. If pricing information from external sources is not available, we must estimate prices based on available historical and near-term future price information and certain statistical methods, including regression analysis, that reflect our market assumptions.

For options and contracts with option-like characteristics where observable pricing information is not available from external sources, we 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. We use other option models under special circumstances, including a Spread Approximation Model, when contracts include different commodities or commodity locations and a Swing Option Model, when contracts allow either the buyer or seller the ability to exercise within a range of quantities. For contracts with unique characteristics, we estimate fair value using a discounted cash flow approach deemed appropriate in the circumstances and applied consistently from period to period. If pricing information is not available from external sources, judgment is required to develop the estimates of fair value. For individual contracts, the use of different valuation models or assumptions could have a material effect on the contract’s estimated fair value.

Also, we 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 we have the ability to access at the measurement date. Instruments categorized in Level 1 primarily consist of financial instruments such as the majority of exchange-traded derivatives, listed equities and Treasury securities.

•

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 include non-exchange traded derivatives such as over-the-counter forwards and swaps, interest rate swaps, and municipal bonds held in nuclear decommissioning and rabbi trust funds.

•

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 include long-dated and modeled commodity derivatives and financial transmission rights (FTRs).

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. 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.

SFAS No. 157 requires fair value measurements to be separately disclosed by level within the fair value hierarchy and requires a separate reconciliation of fair value measurements categorized as Level 3. The following table presents for each hierarchy level our assets and liabilities, including both current and noncurrent portions, measured at fair value on a recurring basis, as of March 31, 2008:


	Level 1		Level 2		Level 3		Total
(millions)
Assets:
Derivatives	$	16	$	888	$	89	$	993
Investments		999		1,774		—		2,773

Total		1,015		2,662		89		3,766
Liabilities:
Derivatives	$	89	$	1,209	$	161	$	1,459

PAGE 15

The following table presents the changes in the assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category for the three months ended March 31, 2008:


(millions)	Derivatives ⁽¹⁾
Balance at January 1, 2008	$	(61	)
Total realized and unrealized gains or (losses):
Included in earnings		9
Included in other comprehensive income (loss)		(50	)
Included in regulatory assets/liabilities		33
Purchases, issuances and settlements		(1	)
Transfers out of Level 3		(2	)

Balance at March 31, 2008	$	(72	)

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	$	3

(1)	Derivative assets and liabilities are presented on a net basis.

The following table presents gains and losses included in earnings in the Level 3 fair value category for the three months ended March 31, 2008:


(millions)	Operating Revenue			Other Operations and Maintenance		Electric Fuel and Energy Purchases		Total
Total gains or (losses) included in earnings	$	(11	)	$	12	$	8	$	9
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		(1	)		4		—		3

Note 11.

Hedge Accounting Activities

We are exposed to the impact of market fluctuations in the price of electricity, natural gas and other energy-related products marketed and purchased, as well as currency exchange and interest rate risks of our business operations. We use derivative instruments to manage our exposure to these risks and designate certain derivative instruments as fair value or cash flow hedges for accounting purposes as allowed by SFAS No. 133. As discussed in Note 2 to our Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2007, for certain jurisdictions subject to cost-based regulation, changes in the fair value of derivatives designated as hedges are deferred as regulatory assets or regulatory liabilities until the related transactions impact earnings. Selected information about our hedge accounting activities follows:


	Three Months Ended March 31,
	2008			2007
(millions)
Portion of gains (losses) on hedging instruments determined to be ineffective and included in net income:
Fair value hedges	$	5		$	4
Cash flow hedges		(3	)		15

Net ineffectiveness	$	2		$	19

For the three months ended March 31, 2008 and 2007, amounts excluded from the measurement of effectiveness did not have a significant impact on net income.

PAGE 16

The following table presents selected information, for jurisdictions not subject to cost-of-service rate regulation, related to cash flow hedges included in accumulated other comprehensive income (loss) (AOCI) in our Consolidated Balance Sheet at March 31, 2008:


	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings during the next 12 Months After Tax			Maximum Term
(millions)
Commodities:
Gas	$	(23	)	$	(21	)	36 months
Electricity		(306	)		(223	)	45 months
Natural gas liquids		(34	)		(19	)	45 months
Other		7			5		86 months
Interest rate		(26	)		—		364 months
Foreign currency		3			2		38 months

Total	$	(379	)	$	(256	)

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 exchange rates.

Note 12.

Ceiling Test

We follow the full cost method of accounting for gas and oil E&P activities prescribed by the SEC. Under the full cost method, capitalized costs are subject to a quarterly ceiling test. Under the ceiling test, amounts capitalized are limited to the present value of estimated future net revenues to be derived from the anticipated production of proved gas and oil reserves, discounted at 10 percent, assuming period-end hedge-adjusted prices.

Approximately 7% of the anticipated production from our remaining E&P operations and fixed-term overriding royalty interests formerly associated with volumetric production payment (VPP) agreements that were terminated in conjunction with the 2007 sale of our E&P operations, is hedged by qualifying cash flow hedges, for which hedge-adjusted prices were used to calculate estimated future net revenue. Whether period-end market prices or hedge-adjusted prices were used for the portion of production that is hedged, there was no ceiling test impairment as of March 31, 2008.

Note 13.

Variable Interest Entities

As discussed in Note 17 to our Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2007, certain variable pricing terms in some of our long-term power and capacity contracts cause them to be considered potential variable interests in the counterparties.

We have long-term power and capacity contracts with four potential variable interest entities (VIEs), which contain certain variable pricing mechanisms to the counterparty in the form of partial fuel reimbursement. We have concluded we are not the primary beneficiary of any of these potential VIEs. The contracts expire at various dates ranging from 2015 to 2021. We are not subject to any risk of loss from these potential VIEs other than our remaining purchase commitments which totaled $2.1 billion as of March 31, 2008. We paid $52 million and $55 million for electric capacity and $47 million and $41 million for electric energy to these entities for the three months ended March 31, 2008 and 2007, respectively.

As discussed in Note 28 to our Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2007, DCI held an investment in the subordinated notes of a third-party CDO entity. The CDO entity’s primary focus is the purchase and origination of middle market senior secured first and second lien commercial and industrial loans in both the primary and secondary loan markets. We concluded previously that the CDO entity was a VIE and that DCI was the primary beneficiary of the CDO entity and therefore we consolidated the CDO entity in accordance with FIN 46 (revised December 2003), Consolidation of Variable Interest Entities at December 31, 2007. In March 2008, we entered into an agreement to sell our remaining interest in the subordinated notes effectively eliminating the variability of our interest, and therefore deconsolidated the CDO entity as of March 31, 2008. In connection with the sale of the subordinated notes, we recognized impairment losses of $62 million ($38 million after tax) for the three months ended March 31, 2008. In April 2008, we received proceeds of $54 million, including accrued interest, from the sale of the subordinated notes.

PAGE 17

Due to the consolidation of the CDO entity at December 31, 2007, our consolidated balance sheet included $460 million of notes payable, which were nonrecourse to us, and the following assets that served as collateral for its obligations:


	Amount
(millions)
Other current assets⁽¹⁾	$	257
Loans held for sale		323
Other investments		32

Total assets	$	612

(1)	Includes $30 million of loans held for resale.

Note 14.

Significant Financing Transactions

Credit Facilities and Short-Term Debt

We use short-term debt, primarily commercial paper, to fund working capital requirements, as a bridge to long-term debt financing and as bridge financing for acquisitions, if applicable. The levels of our borrowings 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, we utilize cash and letters of credit to fund collateral requirements under our commodities hedging program. Collateral requirements are impacted by commodity prices, hedging levels and our credit quality and the credit quality of our counterparties. At March 31, 2008, we had committed lines of credit totaling $4.9 billion. These lines of credit support commercial paper borrowings and letter of credit issuances. At March 31, 2008, we had the following commercial paper, bank loans and letters of credit outstanding and capacity available under our core credit facilities:


Core Credit Facilities	Facility Limit		Outstanding Commercial Paper		Outstanding Bank Borrowings		Outstanding Letters of Credit		Facility Capacity Available
(millions)
Five-year joint revolving credit facility⁽¹⁾	$	3,000	$	522	$	—	$	315	$	2,163
Five-year Dominion credit facility⁽²⁾		1,700		653		1,000		47		—
Five-year Dominion bilateral facility⁽³⁾		200		200		—		—		—

Totals	$	4,900	$	1,375	$	1,000	$	362	$	2,163

(1)	The $3.0 billion five-year credit facility was entered into in February 2006 and terminates in February 2011. The credit facility can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion of letters of credit.

(2)	The amended and restated $1.7 billion five-year credit facility is dated February 2006 and terminates in August 2010. This facility can be used to support bank borrowings, the issuance of letters of credit and commercial paper.

(3)	The $200 million five-year facility was entered into in December 2005 and terminates in December 2010. This credit facility can be used to support commercial paper and letter of credit issuances.

In addition to the facilities above, we also entered into a $100 million bilateral credit facility in August 2004 that terminates in August 2009. At March 31, 2008, there were no letters of credit outstanding under this facility. In April 2008, we elected to terminate this credit facility effective May 15, 2008.

Long-Term Debt

In November 2007, Virginia Power borrowed $14 million in connection with the Economic Development Authority of the County of Chesterfield’s issuance of its Solid Waste and Sewage Disposal Revenue Bonds, Series 2007 A, which mature in 2031 and bear a coupon rate of 5.60%. The bonds were issued pursuant to a trust agreement whereby funds are withdrawn from the trust as improvements are made at our Chesterfield power station. We have withdrawn $6 million from the trust as of March 31, 2008.

PAGE 18

In January 2008, Virginia Power borrowed $30 million in connection with the Economic Development Authority of the City of Chesapeake Pollution Control Refunding Revenue Bonds, Series 2008 A, which mature in 2032 and bear an initial coupon rate of 3.6% for the first five years, after which they will bear interest at a market rate to be determined at that time. The proceeds were used to refund the principal amount of the Industrial Development Authority of the City of Chesapeake Money Market Municipals Pollution Control Revenue Bonds, Series 1985 that would otherwise have matured in February 2008.

In April 2008, Virginia Power issued $600 million of 5.4% senior notes that mature in 2018. The proceeds will be used for general corporate purposes, including the repayment of short-term debt and the redemption of all 16 million units of the $400 million 7.375% Virginia Power Capital Trust II preferred securities (including the related $412 million 7.375% unsecured Junior Subordinated Notes) due July 30, 2042. These securities were called for redemption in April 2008 and will be redeemed in May 2008 at a price of $25 per preferred security plus accrued and unpaid distributions.

We repaid $510 million of long-term debt during the three months ended March 31, 2008.

Convertible Securities

In December 2003, we issued $220 million of contingent convertible senior notes that are convertible by holders into a combination of cash and shares of our common stock under certain circumstances. In 2004 and 2005, we entered into exchange transactions with respect to these contingent convertible senior notes in contemplation of EITF Issue No. 04-8, The Effect of Contingently Convertible Instruments on Diluted Earnings per Share. We exchanged the outstanding notes for new notes with a conversion feature that requires that the principal amount of each note be repaid in cash. At issuance, the notes were valued at a conversion rate of 27.173 shares of common stock per $1,000 principal amount of senior notes, which represents a conversion price of $36.80, recast to reflect our November 2007 stock split. Amounts payable in excess of the principal amount will be paid in common stock. The conversion rate is subject to adjustment upon certain events such as subdivisions, splits, combinations of common stock or the issuance to all common stock holders of certain common stock rights, warrants or options and certain dividend increases. As of March 31, 2008, the conversion rate has been adjusted to 27.5781 primarily due to individual dividend payments above the level paid at issuance.

The new notes have been included in the diluted EPS calculation using the method described in EITF 04-8 when appropriate. Under this method, the number of shares included in the denominator of the diluted EPS calculation is calculated as the net shares issuable for the reporting period based upon the average market price for the period. This results in an increase in the average shares outstanding used in the calculation of our diluted EPS when the conversion price of $36.80 is lower than the average market price of our common stock over the period, and no adjustment when the conversion price exceeds the average market price.

As of December 31, 2007, the closing price of our common stock was equal to $44.16 per share or higher for at least 20 out of the last 30 consecutive trading days. Therefore, the senior notes were eligible for conversion during the first quarter of 2008. During the first quarter, less than $1 million of the contingent convertible senior notes were converted by shareholders. At March 31, 2008, the applicable contingent conversion price of the notes was $43.51 per share and none of the conditions for conversion had been met, therefore the senior notes are not eligible for conversion during the second quarter of 2008.

Issuance of Common Stock

During the three months ended March 31, 2008, we issued 1.5 million shares and received cash proceeds of $58 million, primarily through Dominion Direct^® (a dividend reinvestment and open enrollment direct stock purchase plan), employee savings plans and the exercise of employee stock options.

Note 15.

Stock-Based Awards

Our results for the three months ended March 31, 2008 and 2007 include $7 million and $9 million, respectively, of compensation costs and $2 million and $3 million, respectively, of income tax benefits related to our stock-based compensation arrangements. Stock-based compensation cost is reported in other operations and maintenance expense in our Consolidated Statements of Income. SFAS No. 123R, Share-Based Payment, requires the benefits of tax deductions in excess of the compensation cost recognized for stock-based compensation (excess tax benefits) to be classified as a financing cash flow. Approximately $4 million and $14 million of excess tax benefits were realized for the three months ended March 31, 2008 and 2007, respectively.

PAGE 19

Stock Options

The following table provides a summary of changes in amounts of stock options outstanding as of and for the three months ended March 31, 2008:


	Shares		Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Life	Aggregated intrinsic value⁽¹⁾
	(thousands)				(years)	(millions)
Outstanding and exercisable at January 1, 2008	7,021		$	30.46
Exercised	(271	)		29.55		$	3.5
Forfeited/expired	(2	)		30.77

Outstanding and exercisable at March 31, 2008	6,748		$	30.49	2.64	$	70

(1)	Intrinsic value represents the difference between the exercise price of the option and the market value of our stock.

We issue new shares to satisfy stock option exercises. We received cash proceeds from the exercise of stock options of approximately $8 million and $88 million in the three months ended March 31, 2008 and 2007, respectively.

Restricted Stock

The fair value of our restricted stock awards is equal to the market price of our stock on the date of grant. These awards generally vest over a three-year service period and are settled by issuing new shares. The following table provides a summary of restricted stock activity for the three months ended March 31, 2008:


	Shares		Weighted-Average Grant Date Fair Value
	(thousands)
Nonvested at January 1, 2008	2,014		$	35.31
Granted	9			43.23
Vested	(617	)		29.26
Cancelled and forfeited	(11	)		37.38
Transferred from goal-based stock to restricted stock	200			34.77

Nonvested at March 31, 2008	1,595		$	38.51

As of March 31, 2008, unrecognized compensation cost related to nonvested restricted stock awards totaled approximately $24 million and is expected to be recognized over a weighted-average period of 1.4 years.

Goal-Based Stock

Goal-based stock awards are generally granted to key non-officer employees on an annual basis. The issuance of awards is based on the achievement of multiple performance metrics during a two-year period, including return on invested capital and total shareholder return relative to that of a peer group of companies. Goal-based stock awards are also granted in lieu of cash-based performance grants to certain officers who had not achieved a certain level of share ownership.

After the performance period for the April 2006 grants ended on December 31, 2007, the Compensation, Governance and Nominating Committee determined that the total number of shares expected to be issued under those goal-based stock awards was 200 thousand, based on the actual performance against metrics established for those awards, and 130 thousand shares of goal-based stock were converted to 200 thousand shares and transferred to restricted stock for the remaining term of the vesting period.

PAGE 20

For remaining stock-based awards, at March 31, 2008, the targeted number of shares to be issued is 158 thousand, but the actual number of shares issued will vary between zero and 200% of the targeted shares depending on the level of performance metrics achieved. The fair value of goal-based stock is equal to the market price of our stock on the date of grant. These awards generally vest over a three-year service period and are settled by issuing new shares. The following table provides a summary of goal-based stock activity:


	Targeted Number of Shares		Weighted-Average Grant Date Fair Value
	(thousands)
Nonvested at January 1, 2008	289		$	39.16
Granted	1			43.00
Cancelled and forfeited	(2	)		38.83
Transferred from goal-based stock to restricted stock	(130	)		34.77

Nonvested at March 31, 2008	158		$	44.24

At March 31, 2008, unrecognized compensation cost related to nonvested goal-based stock awards totaled approximately $4 million and is expected to be recognized over a weighted-average period of 1.5 years.

Cash-Based Performance Grants

The targeted amount of the cash-based performance grant made to officers in April 2006 was $13 million, but the actual payout of the award in February 2008 determined by the Compensation, Governance and Nominating Committee was $18 million, based on the level of performance metrics achieved.

In April 2007, a cash-based performance grant was made to officers. Payout of the performance grant will occur by March 15, 2009 and is based on the achievement of two performance metrics during 2007 and 2008: return on invested capital and total shareholder return relative to that of a peer group of companies. At March 31, 2008, the targeted amount of the grant is $14 million, but actual payout will vary between zero and 200% of the targeted amount depending on the level of performance metrics achieved. At March 31, 2008, a liability of $7 million has been accrued for this award.

Note 16.

Commitments and Contingencies

Other than the following matters, there have been no significant developments regarding the commitments and contingencies disclosed in Note 24 to our Consolidated Financial Statements in our Annual Report on Form 10-K, for the year ended December 31, 2007, nor have any significant new matters arisen during the three months ended March 31, 2008.

Guarantees

At March 31, 2008, we had issued $36 million of guarantees to support third parties and equity method investees. Additionally, we have issued $110 million of guarantees to support our investment in a joint venture with Shell WindEnergy Inc. (Shell) to develop a wind-turbine facility in Grant County, West Virginia (NedPower). This amount is primarily comprised of a limited-scope guarantee and indemnification for one-half of the project-level financing for phase one of the NedPower wind farm. Under this guarantee, we would be required to repay one-half of NedPower’s debt, only if it is unable to do so, as a direct result of an unfavorable ruling associated with current litigation seeking to halt the project. The guarantee will terminate when a final non-appealable ruling in favor of the project is received. We do not expect an unfavorable ruling and no significant amounts have been recorded. Our exposure under the guarantee totaled $74 million as of March 31, 2008 and will increase to $103 million during the remainder of 2008 based upon NedPower’s future expected borrowings to complete phase one. Shell has provided an identical guarantee for the other one-half of NedPower’s borrowings.

We have also issued $236 million of guarantees to support our investment in a joint venture with BP Alternative Energy to develop a wind-turbine facility in Benton County, Indiana, referred to as the Fowler Ridge wind farm. The guarantees primarily relate to payments for wind turbines and construction costs. Our exposure under these guarantees will largely decline during the remainder of 2008, as the joint venture makes the underlying payments covered by these guarantees. BP has provided identical guarantees for the other one-half of these joint venture commitments.

PAGE 21

We also enter into guarantee arrangements on behalf of our consolidated subsidiaries primarily to facilitate their commercial transactions with third parties. To the extent that a liability subject to a guarantee has been incurred by one of our consolidated subsidiaries, that liability is included in our Consolidated Financial Statements. We are not required to recognize liabilities for guarantees issued on behalf of our subsidiaries unless it becomes probable that we will have to perform under the guarantees. We believe it is unlikely that we would be required to perform or otherwise incur any losses associated with guarantees of our subsidiaries’ obligations. At March 31, 2008, we had issued the following subsidiary guarantees:


	Stated Limit		Value⁽¹⁾
(millions)
Subsidiary debt⁽²⁾	$	47	$	47
Commodity transactions⁽³⁾		2,975		606
Lease obligation for power generation facility⁽⁴⁾		917		917
Nuclear obligations⁽⁵⁾		383		307
Other		359		202

Total	$	4,681	$	2,079

(1)

Represents the estimated portion of the guarantee’s stated limit that is utilized as of March 31, 2008, based upon prevailing economic conditions and fact patterns specific to each guarantee arrangement. For those guarantees related to obligations that are recorded as liabilities by our subsidiaries, the value includes the recorded amount.

(2)	Guarantees of debt of a DEI subsidiary. In the event of default by the subsidiary, we would be obligated to repay such amount.

(3)

Guarantees related to energy trading and marketing activities and other commodity commitments of certain subsidiaries, including subsidiaries of Virginia Power and DEI. These guarantees were provided to counterparties in order to facilitate physical and financial transactions in gas, oil, electricity, pipeline capacity, transportation and related commodities and services. If these subsidiaries fail to perform or pay under the contracts and the counterparties seek performance or payment, we would be obligated to satisfy such obligation. We and our subsidiaries receive similar guarantees as collateral for credit extended to others. The value provided includes certain guarantees that do not have stated limits.

(4)	Guarantee of a DEI subsidiary’s leasing obligation for the Fairless Energy power station.

(5)

Guarantees related to certain DEI subsidiaries’ potential retrospective premiums that could be assessed if there is a nuclear incident under our nuclear insurance programs and guarantees for a DEI subsidiary’s and Virginia Power’s commitment to buy nuclear fuel. In addition to the guarantees listed above, we have also agreed to provide up to $150 million and $60 million to two DEI subsidiaries, to pay the operating expenses of the Millstone and Kewaunee power stations, respectively, in the event of a prolonged outage, as part of satisfying certain Nuclear Regulatory Commission (NRC) requirements concerned with ensuring adequate funding for the operations of nuclear power stations.

Surety Bonds and Letters of Credit

As of March 31, 2008, we had purchased $112 million of surety bonds and authorized the issuance of standby letters of credit by financial institutions of $362 million to facilitate commercial transactions by our subsidiaries with third parties.

Note 17.

Credit Risk

Credit risk is our risk of financial loss if counterparties fail to perform their contractual obligations. In order to minimize overall credit risk, we maintain credit policies, 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. We maintain a provision for credit losses based on factors surrounding the credit risk of our customers, historical trends and other information. We believe, based on our credit policies and our March 31, 2008 provision for credit losses, that it is unlikely that a material adverse effect on our financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.

As a diversified energy company, we transact with major companies in the energy industry and with commercial and residential energy consumers. These transactions principally occur in the Northeast, mid-Atlantic and Midwest regions of the U.S. We do not believe that this geographic concentration contributes significantly to our overall exposure to credit risk. In addition, as a result of our large and diverse customer base, we are not exposed to a significant concentration of credit risk for receivables arising from electric and gas utility operations, including transmission services and retail energy sales.

Our exposure to credit risk is concentrated primarily within our energy marketing and price risk management activities, as we transact 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 trading of energy-related commodities, 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

PAGE 22

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 March 31, 2008, our gross credit exposure totaled $889 million. After the application of collateral, our credit exposure is reduced to $856 million. Of this amount, investment grade counterparties, including those internally rated, represented 75% and no single counterparty exceeded 12%.

Note 18.

Employee Benefit Plans

The components of the provision for net periodic benefit (credit) cost were as follows:


	Pension Benefits						Other Postretirement Benefits
Three Months Ended March 31,	2008			2007			2008			2007
(millions)
Service cost	$	27		$	23		$	13		$	15
Interest cost		64			43			20			19
Expected return on plan assets		(111	)		(76	)		(16	)		(18	)
Amortization of prior service (credit) cost		1			1			(1	)		(2	)
Amortization of transition obligation		—			—			—			1
Amortization of net loss		2			8			1			1

Net periodic benefit (credit) cost	$	(17	)	$	(1	)	$	17		$	16

Employer Contributions

Under our funding policies, we evaluate pension and other postretirement benefit plan funding requirements annually, usually in the second half of the year after receiving updated plan information from our actuary. Based on the funded status of each plan and other factors, the amount of additional contributions to be made each year is determined at that time. We made no contributions to our defined benefit pension plans or other postretirement benefit plans during the three months ended March 31, 2008. We do not expect to make any contributions to our pension plans, but we do expect to contribute approximately $35 million to our other postretirement benefit plans during the remainder of 2008.

Note 19.

Operating Segments

We are organized primarily on the basis of the products and services we sell. We manage our daily operations through the following segments.

DVP includes our regulated electric distribution and electric transmission operations in Virginia and North Carolina, as well as nonregulated retail energy marketing operations. DVP also includes our regulated and nonregulated customer service operations.

Dominion Energy includes our Ohio regulated natural gas distribution company, regulated gas transmission pipeline and storage operations, including gathering and extraction activities, regulated LNG operations and our remaining E&P operations. Dominion Energy also includes producer services, which aggregates gas supply, provides market-based services related to gas transportation and storage and engages in associated gas trading and marketing.

Dominion Generation includes the electric generation operations of our utility and merchant fleet, as well as energy marketing and price risk management activities associated with our generation assets.

PAGE 23

Corporate includes our corporate, service company and other functions (including unallocated debt), corporate-wide enterprise commodity risk management services, the remaining assets and operations of DCI, the net impact of discontinued operations, our divested U.S. E&P operations and our regulated gas distribution subsidiaries in West Virginia and Pennsylvania that are held for sale. In addition, the contribution to net income by our primary operating segments is determined based on a measure of profit that executive management believes represents the segments’ core earnings. As a result, certain specific items attributable to those segments are not included in profit measures evaluated by executive management in assessing the segment’s performance or allocating resources among the segments and are instead reported in the Corporate and Other segment. In the three months ended March 31, 2008 and 2007, our Corporate and Other segment included $16 million and $24 million, respectively, of after-tax expenses attributable to our operating segments:

•

The expenses in 2008 reflect $26 million ($16 million after-tax) of impairment charges resulting from other-than-temporary declines in the fair value of securities held in nuclear decommissioning trust funds, attributable to Dominion Generation.

•

The expenses in 2007 largely resulted from:

•

A $26 million ($16 million after-tax) charge resulting from the accrual of litigation reserves, attributable to Dominion Energy; and

•

A $6 million ($4 million after-tax) charge resulting from a contract termination settlement, attributable to Dominion Generation.

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

The following table presents segment information pertaining to our operations:


	DVP		Dominion Energy		Dominion Generation		Corporate and Other			Adjustments/ Eliminations			Consolidated Total
(millions)
Three Months Ended March 31,
2008
Total revenue from external customers	$	919	$	932	$	1,930	$	318		$	290		$	4,389
Intersegment revenue		71		352		15		158			(596	)		—

Total operating revenue		990		1,284		1,945		476			(306	)		4,389
Net income		118		182		336		44			—			680

2007
Total revenue from external customers	$	881	$	808	$	1,780	$	937		$	255		$	4,661
Intersegment revenue		51		300		27		137			(515	)		—

Total operating revenue		932		1,108		1,807		1,074			(260	)		4,661
Loss from discontinued operations, net of tax		—		—		—		(22	)		—			(22	)
Net income		132		142		139		40			—			453

PAGE 24

DOMINION RESOURCES, INC.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management’s Discussion & Analysis of Financial Condition and Results of Operations (MD&A) discusses our results of operations and general financial condition. MD&A should be read in conjunction with our Consolidated Financial Statements. The terms “Dominion,” “Company,” “we,” “our” and “us” are used throughout this report and, depending on the context of their use, may represent any of the following: the legal entity, Dominion Resources, Inc., one or more of Dominion Resources, Inc.’s consolidated subsidiaries or operating segments or the entirety of Dominion Resources, Inc. and its consolidated subsidiaries.

Contents of MD&A

The reader will find the following information in our MD&A:

•

Forward-Looking Statements

•

Accounting Matters

•

Results of Operations

•

Segment Results of Operations

•

Selected Information — Energy Trading Activities

•

Liquidity and Capital Resources

•

Future Issues and Other Matters

Forward-Looking Statements

This report contains statements concerning our expectations, plans, objectives, future financial performance and other statements that are not historical facts. These statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. In most cases, the reader can identify these forward-looking statements by such words as “anticipate,” “estimate,” “forecast,” “expect,” “believe,” “should,” “could,” “plan,” “may,” “target” or other similar words.

We make forward-looking statements with full knowledge that risks and uncertainties exist that may cause actual results to differ materially from predicted results. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Additionally, other factors may cause actual results to differ materially from those indicated in any forward-looking statement. These factors include but are not limited to:

•

Unusual weather conditions and their effect on energy sales to customers and energy commodity prices;

•

Extreme weather events, including hurricanes and winter storms, that can cause outages and property damage to our facilities;

•

State and federal legislative and regulatory developments and changes to environmental and other laws and regulations, including those related to climate change, to which we are subject;

•

Cost of environmental compliance, including those costs related to climate change;

•

Risks associated with the operation of nuclear facilities;

•

Fluctuations in energy-related commodity prices and the effect these could have on our earnings, liquidity position and the underlying value of our assets;

•

Counterparty credit risk;

•

Capital market conditions, including price risk due to securities held as investments in nuclear decommissioning and benefit plan trusts;

•

Fluctuations in interest rates;

•

Changes in federal and state tax laws and regulations;

•

Changes to benefit plan assumptions such as discount rates and the expected rate of return on plan assets;

•

Changes in rating agency requirements or credit ratings and their effect on availability and cost of capital;

•

Changes in financial or regulatory accounting principles or policies imposed by governing bodies;

•

Employee workforce factors including collective bargaining agreements and labor negotiations with union employees;

•

The risks of operating businesses in regulated industries that are subject to changing regulatory structures;

•

Changes to regulated gas and electric rates collected by Dominion and the timing of such collection as it relates to fuel costs;

•

Receipt of approvals for and timing of closing dates for acquisitions and divestitures;

•

Changes in rules for RTOs in which we participate, including changes in rate designs and capacity models;

•

Political and economic conditions, including the threat of domestic terrorism, inflation and deflation;

PAGE 25

•

Timing and receipt of regulatory approvals necessary for planned construction or expansion projects;

•

The inability to complete planned construction or expansion projects within the terms and time frames initially anticipated; and

•

Completing the divestiture of Peoples and Hope.

Additionally, other risks that could cause actual results to differ from predicted results are set forth in Item 1A. Risk Factors in this report and in our Annual Report on Form 10-K for the year ended December 31, 2007.

Our forward-looking statements are based on our beliefs and assumptions using information available at the time the statements are made. We caution the reader not to place undue reliance on our forward-looking statements because the assumptions, beliefs, expectations and projections about future events may, and often do, differ materially from actual results. We undertake no obligation to update any forward-looking statement to reflect developments occurring after the statement is made.

Accounting Matters

Critical Accounting Policies and Estimates

As of March 31, 2008, there have been no significant changes with regard to the critical accounting policies and estimates disclosed in MD&A in our Annual Report on Form 10-K for the year ended December 31, 2007. The policies disclosed included the accounting for derivative contracts at fair value, goodwill and long-lived asset impairment testing, regulated operations, asset retirement obligations, employee benefit plans, gas and oil operations, and income taxes.

Other

See Notes 3 and 4 to our Consolidated Financial Statements for a discussion of newly adopted and recently issued accounting standards.

Results of Operations

Presented below is a summary of our consolidated results for the quarters ended March 31, 2008 and 2007:


	2008		2007		$ Change
(millions, except EPS)
First Quarter
Net income	$	680	$	453	$	227
Diluted EPS		1.18		0.65		0.53

Overview

Net income increased by 50% to $680 million. Diluted EPS increased to $1.18 and includes $0.19 of share accretion resulting primarily from the repurchase of shares in 2007 with proceeds received from the sale of the majority of our E&P operations. Favorable drivers include the reversal of deferred tax liabilities associated with the planned sale of Peoples and Hope, the reinstatement of annual fuel rate adjustments for the Virginia jurisdiction of our utility generation operations effective July 1, 2007, with deferred fuel accounting for over- or under-recoveries of fuel costs, a higher contribution from our merchant generation operations, and higher volumes and realized prices for our remaining E&P operations, including volumes associated with reacquired overriding royalty interests arising from the VPPs terminated in 2007. Unfavorable drivers include a decrease in earnings due to the sale of the majority of our E&P operations and an impairment charge related to a DCI investment.

PAGE 26

Analysis of Consolidated Operations

Presented below are selected amounts related to our results of operations.


	First Quarter
	2008			2007			$ Change
(millions)
Operating Revenue	$	4,389		$	4,661		$	(272	)
Operating Expenses
Electric fuel and energy purchases		806			918			(112	)
Purchased electric capacity		107			119			(12	)
Purchased gas		1,187			1,148			39
Other energy-related commodity purchases		13			56			(43	)
Other operations and maintenance		809			828			(19	)
Depreciation, depletion and amortization		254			409			(155	)
Other taxes		154			183			(29	)
Other income (loss)		(3	)		49			(52	)
Interest and related charges		219			259			(40	)
Income tax expense		157			310			(153	)
Loss from discontinued operations, net of tax		—			(22	)		22

An analysis of our results of operations for the first quarter of 2008 compared to the first quarter of 2007 follows:

Operating Revenue decreased 6% to $4.4 billion, primarily reflecting:

•

A $619 million decrease due to the sale of the majority of our U.S. E&P operations; and

•

A $44 million decrease in nonutility coal sales, resulting principally from lower sales volumes related to exiting these activities. This decrease was offset by a corresponding decrease in Other energy-related commodity purchases expense.

These decreases were partially offset by:

•

A $132 million increase for merchant generation operations, primarily reflecting higher overall realized prices;

•

An $85 million increase in revenue from our electric utility operations, largely due to the impact of a comparatively higher fuel rate in certain customer jurisdictions;

•

A $72 million increase in sales of gas production from our remaining E&P operations as a result of an increase in volumes, primarily associated with reacquired overriding royalty interests arising from the VPPs terminated in 2007, and higher realized prices;

•

A $24 million increase in electric sales by our retail energy marketing operations due to higher volumes ($18 million) and higher sales prices ($6 million). This increase was more than offset by a corresponding increase in Electric fuel and energy purchases expense; and

•

A $19 million increase in sales of extracted products from our gas transmission operations as a result of higher realized prices.

Operating Expenses and Other Items

Electric fuel and energy purchases expense decreased 12% to $806 million, primarily reflecting the combined effects of:

•

A $152 million decrease for our utility generation operations due to the deferral of fuel expenses that were in excess of current period fuel rate recovery costs ($166 million). The underlying fuel costs, including those subject to deferral accounting, increased $14 million as a result of higher commodity prices, including purchased power, partially offset by lower volumes due to fewer heating degree days (HDDs).

This decrease was partially offset by:

•

A $29 million increase related to our retail energy marketing operations, as discussed in Operating Revenue; and

•

A $17 million increase for our merchant generation operations primarily reflecting 2008 fuel costs for State Line power station (State Line). In 2007, State Line’s fuel was supplied by a customer under a long-term power sales agreement that was terminated in the fourth quarter.

Other energy-related commodity purchases expense decreased 77% to $13 million, primarily resulting from a $44 million decrease in the cost of nonutility coal sales, as discussed in Operating Revenue.

PAGE 27

Other operations and maintenance expense decreased 2% to $809 million, primarily reflecting the combined effects of:

•

A $127 million decrease due to the sale of the majority of our U.S. E&P operations; and

•

The absence of a $26 million charge recorded in 2007 resulting from the accrual of litigation reserves.

These decreases were partially offset by:

•

A $62 million charge related to the impairment of a DCI investment;

•

A $27 million increase in salaries, wages and benefits expenses;

•

A $22 million increase in bad debt expense for our gas distribution operations, primarily related to low income energy assistance programs and an increase in sales and transport volumes. These expenses are recovered through rates and do not impact our net income; and

•

A $15 million increase primarily due to the inclusion of certain FTR proceeds in Electric fuel and energy purchases expense, beginning July 1, 2007, as a result of the reapplication of deferred fuel accounting for the Virginia jurisdiction of our utility generation operations. These FTR proceeds are used to offset congestion costs incurred by our utility generation operations.

Depreciation, depletion & amortization expense (DD&A) decreased 38% to $254 million, principally due to decreased oil and gas production resulting from the sale of the majority of our U.S. E&P business, partially offset by an increase resulting from property additions and an increase in depreciation rates for our utility generation assets.

Other income (loss) decreased by $52 million to a net loss of $3 million, primarily due to net realized losses (net of investment income) on nuclear decommissioning trust fund investments resulting largely from comparatively higher other-than-temporary impairments for merchant generation-related trust investments.

Interest and related charges decreased 15% to $219 million, primarily due to a reduction in outstanding debt.

Income tax expense reflects a decrease in our effective tax rate to 18.8%, largely due to the reversal of deferred tax liabilities in the first quarter of 2008, associated with a change in the expected tax treatment of the planned sale of Peoples and Hope.

Loss from discontinued operations primarily reflects the absence of a loss on the sale of the Peaker facilities in March 2007.

Segment Results of Operations

Segment results include the impact of intersegment revenues and expenses, which may result in intersegment profit and loss. Presented below is a summary of contributions by operating segments to net income for the quarters ended March 31, 2008 and 2007:


	Net Income							Diluted EPS
First Quarter	2008		2007		$ Change			2008		2007		$ Change
(millions, except EPS)
DVP	$	118	$	132	$	(14	)	$	0.20	$	0.19	$	0.01
Dominion Energy		182		142		40			0.32		0.20		0.12
Dominion Generation		336		139		197			0.58		0.20		0.38

Primary operating segments		636		413		223			1.10		0.59		0.51
Corporate and Other		44		40		4			0.08		0.06		0.02

Consolidated	$	680	$	453	$	227		$	1.18	$	0.65	$	0.53

PAGE 28

DVP

Presented below are operating statistics related to DVP’s operations:


	First Quarter
	2008	2007	% Change
Electricity delivered (million mwhrs)⁽¹⁾	20.8	21.0	(1	)%
Degree days (electric distribution service area):
Cooling⁽²⁾	3	12	(75	)
Heating⁽³⁾	1,810	1,993	(9	)
Average electric distribution customer accounts⁽⁴⁾	2,380	2,351	1
Average retail energy marketing customer accounts⁽⁴⁾	1,584	1,490	6

mwhrs = megawatt hours

(1)	Includes electricity delivered through the retail choice program for our Virginia jurisdictional electric utility customers.

(2)	Cooling degree days (CDDs) are units measuring the extent to which the average daily temperature is greater than 65 degrees. CDDs are calculated as the difference between the average temperature for each day and 65 degrees.

(3)	HDDs are units measuring the extent to which the average daily temperature is less than 65 degrees. HDDs are calculated as the difference between the average temperature for each day and 65 degrees.

(4)	Period average, in thousands.

Presented below, on an after-tax basis, are the key factors impacting DVP’s net income contribution:


	First Quarter 2008 vs. 2007 Increase (Decrease)
	Amount			EPS
(millions, except EPS)
Regulated electric sales:
Weather	$	(9	)	$	(0.01	)
Customer growth		3			—
Interest expense⁽¹⁾		(6	)		(0.01	)
Major storm damage and service restoration – distribution operations		(4	)		(0.01	)
Retail energy marketing operations⁽²⁾		6			0.01
Other		(4	)		(0.01	)
Share accretion		—			0.04

Change in net income contribution	$	(14	)	$	0.01

(1)	Increase primarily due to additional borrowings at our Virginia Power subsidiary.

(2)	Primarily due to increased gas margins.

PAGE 29

Dominion Energy

Presented below are operating statistics related to our Dominion Energy operations:


	First Quarter
	2008		2007		% Change
Gas throughput (bcf):
Gas sales (distribution)		26		26	—	%
Gas transportation (distribution)		91		89	2
HDDs		3,172		3,117	2
Average gas distribution customer accounts⁽¹⁾
Gas sales		410		414	(1	)
Gas transportation		807		809	—
Production⁽²⁾ (bcfe)		17.9		10.0	79
Average realized prices without hedging results (per mcfe)	$	7.92	$	6.62	20
Average realized prices with hedging results (per mcfe)		8.80		6.26	41
DD&A (unit of production rate per mcfe)		1.92		1.49	29
Average production (lifting) cost⁽³⁾ (per mcfe)		1.19		1.24	(4	)

bcf = billion cubic feet

bcfe = billion cubic feet equivalent

mcfe = thousand cubic feet equivalent

(1)	Period average, in thousands.

(2)	Includes natural gas, natural gas liquids and oil. Production for 2008 includes 6.3 bcfe associated with reacquired overriding royalty interests arising from the VPPs terminated in 2007.

(3)	The inclusion of volumes associated with reacquired overriding royalty interests arising from the VPPs terminated in 2007 would have resulted in lifting costs of $0.91 in 2008.

Presented below, on an after-tax basis, are the key factors impacting Dominion Energy’s net income contribution:


	First Quarter 2008 vs. 2007 Increase (Decrease)
	Amount			EPS
(millions, except EPS)
Gas and oil – production⁽¹⁾	$	35		$	0.06
Gas and oil – prices		16			0.02
DD&A - gas and oil		(12	)		(0.02	)
Producer services⁽²⁾		(8	)		(0.01	)
Other		9			0.01
Share accretion		—			0.06

Change in net income contribution	$	40		$	0.12

(1)	Increase is primarily due to volumes associated with reacquired overriding royalty interests arising from the VPPs terminated in 2007.

(2)	Decrease is primarily related to lower margins due to decreases in the value derived from storage and transportation contracts.

Included below are the volumes and weighted-average prices associated with hedges in place for our E&P operations and fixed-term overriding royalty interests formerly associated with VPP agreements as of March 31, 2008, by applicable time period:


	Natural Gas
Year	Hedged Production (bcf)	Average Hedge Price (per mcf)
2008	39.6	$	8.40
2009	28.0		8.74
2010	9.8		8.44

mcf = thousand cubic feet.

PAGE 30

Dominion Generation

Presented below are operating statistics related to our Dominion Generation operations:


	First Quarter
	2008	2007	% Change
Electricity supplied (million mwhrs):
Utility	20.8	21.0	(1	)%
Merchant	11.3	11.2	1
Degree days (electric utility service area):
Cooling	3	12	(75	)
Heating	1,810	1,993	(9	)

Presented below, on an after-tax basis, are the key factors impacting Dominion Generation’s net income contribution:


	First Quarter 2008 vs. 2007 Increase (Decrease)
	Amount			EPS
(millions, except EPS)
Virginia fuel expenses⁽¹⁾	$	125		$	0.18
Merchant generation margin⁽²⁾		62			0.08
Sale of emissions allowances		9			0.01
Regulated electric sales:
Customer growth		4			0.01
Weather		(16	)		(0.02	)
Other		15			0.02
Depreciation and amortization		(12	)		(0.02	)
Outage costs		(3	)		—
Other		13			0.02
Share accretion		—			0.10

Change in net income contribution	$	197		$	0.38

(1)	Primarily reflects the reapplication of deferred fuel accounting effective July 1, 2007 for the Virginia jurisdiction of our utility generation operations.

(2)	Primarily reflects higher realized prices.

Corporate and Other

Presented below are the Corporate and Other segment’s after-tax results:


	First Quarter
	2008			2007			$ Change
(millions, except EPS)
Specific items attributable to operating segments	$	(16	)	$	(24	)	$	8
Discontinued operations		—			(22	)		22
Divested U.S. E&P operations		—			115			(115	)
Peoples and Hope		31			32			(1	)
Other corporate operations		29			(61	)		90

Total net benefit	$	44		$	40		$	4

EPS impact	$	0.08		$	0.06		$	0.02

Specific Items Attributable to Operating Segments

Corporate includes specific items attributable to our operating segments that have been excluded in profit measures evaluated by management, either in assessing segment performance or in allocating resources among the segments. See Note 19 to our Consolidated Financial Statements for discussion of these items.

Discontinued Operations

The decrease in discontinued operations primarily reflects the absence of a loss on the sale of the Peaker facilities in March 2007.

PAGE 31

Other Corporate Operations

We reported a net benefit of $29 million in 2008 associated with other corporate operations, as compared to net expenses of $61 million in 2007, primarily reflecting the reversal of $136 million of deferred tax liabilities associated with Peoples and Hope in the first quarter of 2008. This benefit was partially offset by a $38 million after-tax impairment charge related to a DCI investment that was sold in April 2008.

Selected Information—Energy Trading Activities

See Selected Information-Energy Trading Activities in MD&A included in our Annual Report on Form 10-K for the year ended December 31, 2007 for a discussion of our energy trading, hedging and marketing activities and related accounting policies. For additional discussion of trading activities, see Market Risk Sensitive Instruments and Risk Management in Item 3.

A summary of the changes in unrealized gains and losses recognized for our energy-related derivative instruments held for trading purposes during the three months ended March 31, 2008 follows:


	Amount
(millions)
Net unrealized gain at December 31, 2007	$	52
Contracts realized or otherwise settled during the period		(26	)
Net unrealized gain at inception of contracts initiated during the period		—
Changes in valuation techniques		—
Other changes in fair value		(3	)

Net unrealized gain at March 31, 2008	$	23

Effective January 1, 2008, we adopted SFAS No. 157. The fair values summarized below were determined in accordance with the requirements of SFAS No. 157. In addition, we aligned the categories below with the Level 1, 2, and 3 fair value measurements as defined by SFAS No. 157. The balance of net unrealized gains and losses recognized for our energy-related derivative instruments held for trading purposes at March 31, 2008, is summarized in the following table based on the inputs used to determine fair value:


	Maturity Based on Contract Settlement or Delivery Date(s)
Source of Fair Value	Less than 1 year			1-2 years		2-3 years		3-5 years		In excess of 5 years		Total
(millions)
Actively quoted – Level 1⁽¹⁾	$	—		$	—	$	—	$	—	$	—	$	—
Other external sources – Level 2⁽²⁾		(1	)		18		—		1		—		18
Models and other valuation methods – Level 3⁽³⁾		(3	)		3		—		5		—		5

Total	$	(4	)	$	21	$	—	$	6	$	—	$	23

(1)	Values represent observable unadjusted quoted prices for traded instruments in active markets.

(2)	Values with inputs that are observable directly or indirectly for the instrument, but do not qualify for Level 1.

(3)	Values with a significant amount of inputs that are not observable for the instrument.

Liquidity and Capital Resources

We depend on both internal and external sources of liquidity to provide working capital and to fund capital requirements. Short-term cash requirements not met by cash provided by operations are generally satisfied with proceeds from short-term borrowings. Long-term cash needs are met through issuances of debt and/or equity securities.

At March 31, 2008, we had $2.3 billion of unused capacity under our credit facilities.

PAGE 32

A summary of our cash flows for the three months ended March 31, 2008 and 2007 is presented below:


	2008			2007
(millions)
Cash and cash equivalents at January 1,⁽¹⁾	$	287		$	142
Cash flows provided by (used in):
Operating activities		551			1,210
Investing activities		(718	)		(796	)
Financing activities		(35	)		(448	)

Net decrease in cash and cash equivalents		(202	)		(34	)

Cash and cash equivalents at March 31,⁽²⁾	$	85		$	108

(1)	2008 and 2007 amounts include $4 million of cash classified as held for sale on the Consolidated Balance Sheet.

(2)	2008 and 2007 amounts include $6 million and $5 million of cash classified as held for sale in our Consolidated Balance Sheet.

Operating Cash Flows

For the three months ended March 31, 2008, net cash provided by operating activities decreased by $659 million as compared to the three months ended March 31, 2007. The decrease was primarily due to a reduction in cash flow resulting from the disposition of the majority of our E&P operations in the third quarter of 2007, higher collateral requirements related to our commodity hedging transactions primarily as a result of higher gas prices, and unfavorable changes in working capital.

Our operations are subject to risks and uncertainties that may negatively impact the timing or amounts of operating cash flows which are discussed in Item 1A. Risk Factors in this report and in our Annual Report on Form 10-K for the year-ended December 31, 2007.

Credit Risk

Our exposure to potential concentrations of credit risk results primarily from our energy marketing and price risk management activities. Presented below is a summary of our gross credit exposure as of March 31, 2008, for these activities. Our 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		Credit Collateral		Net Credit Exposure
(millions)
Investment grade⁽¹⁾	$	467	$	26	$	441
Non-investment grade⁽²⁾		2		—		2
No external ratings:
Internally rated—investment grade⁽³⁾		207		7		200
Internally rated—non-investment grade⁽⁴⁾		213		—		213

Total	$	889	$	33	$	856

(1)

Designations as investment grade are based upon minimum credit ratings assigned by Moody’s Investors Services (Moody’s) and Standard & Poor’s Ratings Services, a division of the McGraw-Hill Companies, Inc. (Standard & Poor’s). The five largest counterparty exposures, combined, for this category represented approximately 21% of the total net credit exposure.

(2)	The five largest counterparty exposures, combined, for this category represented less than 1% of the total net credit exposure.

(3)	The five largest counterparty exposures, combined, for this category represented approximately 16% of the total net credit exposure.

(4)	The five largest counterparty exposures, combined, for this category represented approximately 16% of the total net credit exposure.

Investing Cash Flows

For the three months ended March 31, 2008, net cash used in investing activities decreased by $78 million as compared to the three months ended March 31, 2007. The decrease was primarily due to a reduction in capital expenditures as a result of the disposition of the majority of our E&P operations in 2007, partially offset by the absence of the proceeds received in 2007 from the sale of the Peaker facilities and an increase in capital expenditures for our other business units.

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Financing Cash Flows and Liquidity

We rely on banks and capital markets as a significant source of funding for capital requirements not satisfied by cash provided by the companies’ operations. As discussed further in the Credit Ratings and Debt Covenants section, our ability to borrow funds or issue securities and the return demanded by investors are affected by the issuing company’s credit ratings. In addition, the raising of external capital is subject to meeting certain regulatory requirements, including registration with the SEC and in the case of Virginia Power, approval by the Virginia State Corporation Commission (Virginia Commission).

For the three months ended March 31, 2008, net cash used in financing activities decreased by $413 million as compared to the three months ended March 31, 2007. The decrease was primarily due to lower long-term debt repayments as well as higher net short-term debt issuances.

See Note 14 to our Consolidated Financial Statements for further information regarding our credit facilities, liquidity and significant financing transactions.

Credit Ratings and Debt Covenants

Credit ratings are intended to provide banks and capital market participants with a framework for comparing the credit quality of securities and are not a recommendation to buy, sell or hold securities. In the Credit Ratings and Debt Covenants sections of MD&A in our Annual Report on Form 10-K for the year ended December 31, 2007, we discussed the use of capital markets by Dominion and Virginia Power, as well as the impact of credit ratings on the accessibility and costs of using these markets. In addition, these sections of MD&A discussed various covenants present in the enabling agreements underlying Dominion and Virginia Power’s debt. In April 2008, Fitch Ratings Ltd. (Fitch) upgraded its credit ratings for Virginia Power’s preferred stock and senior unsecured and junior subordinated debt securities. There have been no other changes in our credit ratings, nor changes to or events of default under our debt covenants.

Presented below is a summary of credit ratings for Dominion and Virginia Power as of April 30, 2008:


	Fitch	Moody’s	Standard & Poor’s
Dominion Resources, Inc.
Senior unsecured debt securities	BBB+	Baa2	A-
Junior subordinated debt securities	BBB	Baa3	BBB
Enhanced junior subordinated notes	BBB	Baa3	BBB
Commercial paper	F2	P-2	A-2
Virginia Power
Mortgage bonds	A	A3	A
Senior unsecured (including tax-exempt) debt securities	A-	Baa1	A-
Junior subordinated debt securities	BBB+	Baa2	BBB
Preferred stock	BBB+	Baa3	BBB
Commercial paper	F2	P-2	A-2

Future Cash Payments for Contractual Obligations and Planned Capital Expenditures

As of March 31, 2008, there have been no material changes outside the ordinary course of business to our contractual obligations nor any material changes to our planned capital expenditures disclosed in MD&A in our Annual Report on Form 10-K for the year ended December 31, 2007.

Use of Off-Balance Sheet Arrangements

As of March 31, 2008, there have been no material changes in the off-balance sheet arrangements disclosed in MD&A in our Annual Report on Form 10-K for the year ended December 31, 2007.

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Future Issues and Other Matters

The following discussion of future issues and other information includes current developments of previously disclosed matters and new issues arising during the period covered by and subsequent to our Consolidated Financial Statements. This section should be read in conjunction with Future Issues and Other Matters in our Annual Report on Form 10-K for the year ended December 31, 2007.

Virginia Fuel Expenses

We will file our annual Virginia fuel factor application with the Virginia Commission in the second quarter of 2008.

Utility Generation Expansion

Based on available generation capacity and current estimates of growth in customer demand in our utility service area, we will need additional generation capacity over the next ten years. We have announced a comprehensive generation growth program, referred to as Powering Virginia, which involves the development, financing, construction and operation of new multi-fuel, multi-technology generation capacity to meet the growing demand in our core market in Virginia. Our Annual Report on Form 10-K for the year ended December 31, 2007 provides a description of these projects, which are in various stages of development. The following is a discussion of certain significant developments related to such projects.

In November 2007, we filed an application with the Virginia Commission for approval to add a fifth combustion turbine at Ladysmith power station at an estimated cost of $79 million. In March 2008, the Virginia Commission approved the application and granted a certificate to construct and operate the proposed generating unit.

In July 2007, we filed an application with the Virginia Commission requesting approval to construct and operate a 585 megawatt (Mw) (nominal) coal-fired electric generation facility (Virginia City Hybrid Energy Center) to be located in Wise County, Virginia. We also requested approval to continue to accrue an allowance for funds used during construction until capped rates end, which would be recovered over a three-year period beginning January 1, 2009 and, beginning January 1, 2009, receive current recovery of financing costs including a return on common equity of 11.75% together with a 200 basis point enhancement that Virginia law provides for new carbon-capture compatible, clean-coal powered generation facilities. After an evidentiary hearing in February 2008, the Virginia Commission issued a final order in March 2008 (Final Order), approving a certificate to construct and operate the proposed Virginia City Hybrid Energy Center and approving a rate adjustment clause as specified in the Final Order. In its Final Order, the Virginia Commission approved an initial return on common equity for the facility of 12.12%, consisting of a base return of 11.12% plus a 100 basis point premium that Virginia law provides for new conventional coal generation facilities. The Virginia Commission also authorized us to apply for an additional 100 basis point premium upon a demonstration that the plant is carbon-capture compatible. The enhanced returns will apply to the Virginia City Hybrid Energy Center during construction and through the first twelve years of the facility’s service life. In April 2008, the Southern Environmental Law Center, on behalf of itself and others, filed a Notice of Appeal of the Final Order with the Supreme Court of Virginia. An application for a permit to construct and operate the Virginia City Hybrid Energy Center, in compliance with federal and state air pollution laws, was filed in July 2006 with the Virginia Department of Environmental Quality. In March 2008, the Virginia Air Pollution Control Board announced that it would assume consideration of the application directly. Pending regulatory approval and necessary permits, the facility is expected to be in operation by 2012 at an estimated cost of approximately $1.8 billion, excluding financing costs.

Also in February 2008, we announced the proposed conversion of Bremo power station from coal to natural gas as part of our plan to build the Virginia City Hybrid Energy Center. The proposal is contingent upon the Virginia City Hybrid Energy Center entering service and receiving all necessary approvals. The proposed conversion project is part of our overall effort to reduce air emissions. Subject to applicable regulatory approvals, the conversion would occur within two years of the Virginia City Hybrid Energy Center entering service.

We are considering the construction of a third nuclear unit within the next twenty years at a site located at North Anna power station (North Anna) which we own along with Old Dominion Electric Cooperative (ODEC). In November 2007, the NRC issued an Early Site Permit (ESP) to our subsidiary, Dominion Nuclear North Anna, LLC (DNNA), for a site located at North Anna. Also in November 2007, Virginia Power, along with ODEC filed an application with the NRC for a Combined Construction Permit and Operating License (COL), which would allow us to build and operate a new nuclear unit at North Anna. In January 2008, the NRC accepted our application for the COL and deemed it complete. We have a cooperative agreement with the Department of Energy to share equally the cost of the COL. In April 2008, we filed applications at the Virginia Commission and the North Carolina Utilities Commission requesting authority to merge DNNA into our electric utility subsidiary, Virginia Power. In April 2008, we also filed an application with the NRC requesting authority to transfer the ESP to Virginia Power and ODEC. We have not yet committed to building a new nuclear unit.

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In March 2008, we purchased a power station development project in Buckingham County, Virginia that once constructed will generate about 590 Mw. Also in March 2008, we filed an application with the Virginia Commission for authority to build the proposed combined-cycle, natural gas-fired power station and transmission interconnection line for an estimated $619 million, excluding financing costs. Pending the receipt of regulatory approval, we expect operations to begin in the summer of 2011.

In March 2008, we also purchased a power station development project in Warren County, Virginia for future development. If developed, the project will involve the construction of a combined cycle, natural gas-fired power station expected to generate about 600 Mw of electricity and will be subject to necessary regulatory approvals.

Wind Power Project

In April 2008, we announced plans to develop a 300 Mw wind-farm in central Illinois. Construction of this facility is expected to begin in 2010, subject to receipt of all necessary permits and approvals.

West Virginia Gas Cost Recovery Proceedings

The Public Services Commission of West Virginia (West Virginia Commission) issued an order in March 2008, approving a settlement of Hope’s 2005 and 2006 gas cost recovery proceedings, approving the withdrawal of the joint application for approval of the sale of Hope to Equitable, and dismissing the claims of a former employee against Hope. In this order, the West Virginia Commission concluded that no adjustments to Hope’s gas cost rates are warranted based on allegations raised by the former employee. Accordingly, the gas cost rates effective November 1, 2007 and approved by Order dated March 12, 2008 have been upheld by the West Virginia Commission. The approved gas cost rates resulted in a rate reduction of $3.137 per mcf effective November 1, 2007.

Collective Bargaining Agreement

The contract between Dominion and the Utility Workers’ Union of America, United Gas Workers’ Local 69-II, AFL-CIO (Local 69-II) expired on April 1, 2008. While the parties have not yet reached agreement, they are continuing negotiations and the union has given notice that employees will continue to work under the terms and conditions of the expired agreement for a reasonable period of time. Local 69-II represents about 840 employees of our DTI subsidiary and about 160 employees of our Hope subsidiary.

Environmental Matters

We 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.

To the extent environmental costs are incurred in connection with operations regulated by the Virginia Commission during the period ending December 31, 2008, in excess of the level currently included in Virginia jurisdictional rates, our results of operations could decrease. After that date, we are allowed to seek recovery through rates.

Clean Air Act Compliance

In February 2008, the U.S. Court of Appeals for the District of Columbia issued a ruling that vacates the Clean Air Mercury Rule as promulgated by the Environmental Protection Agency (EPA). The EPA has filed an appeal of this decision. At this time we cannot predict how the EPA and the states may alter their approach to reducing mercury emissions. We also cannot estimate at this time the impact on our future capital expenditures.

Regulation of Greenhouse Gas Emissions

In April 2007, the U.S. Supreme Court ruled that the EPA has the authority to regulate greenhouse gas emissions. The EPA has announced its intent to issue an Advanced Notice of Proposed Rulemaking in late spring 2008 to solicit comments on potential issues related to the regulation of greenhouse gases under the Clean Air Act which could result in future EPA regulatory action. The outcome in terms of specific requirements and timing is uncertain. The cost of compliance with future greenhouse gas reduction programs could be significant. Given the highly uncertain outcome and timing of future action by the U.S. federal government and states on this issue, we cannot predict the financial impact of future greenhouse gas reduction programs on our operations or our customers at this time.

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Clean Water Act Compliance

In October 2003, the EPA and the Massachusetts Department of Environmental Protection (MADEP) each issued new National Pollution Discharge Elimination System (NPDES) permits for Brayton Point power station (Brayton Point). The new permits contained identical conditions that in effect require the installation of cooling towers to address concerns over the withdrawal and discharge of cooling water. Following various appeals, in December 2007, the EPA issued an administrative order to Brayton Point that contained a schedule for implementing the permit. On the same day, Brayton Point withdrew its appeal of the permit from the U.S. Court of Appeals. In March 2008, MADEP issued a companion order resolving the state appeal and implementing the state permit. The state appeal was dismissed on the same day. Currently, we estimate the total cost to install these cooling towers at approximately $500 million, of which $176 million is included in our planned capital expenditures through 2010.

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ITEM 3. QUANTITATIVE AND QUALITATIVE

DISCLOSURES ABOUT MARKET RISK

The matters discussed in this Item may contain “forward-looking statements” as described in the introductory paragraphs under Part I, Item 2. MD&A of this Form 10-Q. The reader’s attention is directed to those paragraphs for discussion of various risks and uncertainties that may affect our future.

Market Risk Sensitive Instruments and Risk Management

Our financial instruments, commodity contracts and related financial derivative instruments are exposed to potential losses due to adverse changes in commodity prices, interest rates and equity security prices as described below. Commodity price risk is present in our electric operations, gas production and procurement operations, and energy marketing and trading operations due to the exposure to market shifts in prices received and paid for electricity, natural gas and other commodities. We use commodity derivative contracts to manage price risk exposures for these operations. Interest rate risk is generally related to our outstanding debt. In addition, we are exposed to equity price risk through various portfolios of equity securities.

The following sensitivity analysis estimates the potential loss of future earnings or fair value from market risk sensitive instruments over a selected time period due to a 10% unfavorable change in commodity prices and interest rates.

Commodity Price Risk

To manage price risk, we primarily hold commodity-based financial derivative instruments for non-trading purposes associated with purchases and sales of electricity, natural gas and certain other energy-related products. As part of our strategy to market energy and to manage related risks, we also hold commodity-based financial derivative instruments for trading purposes.

The derivatives used to manage our commodity price risk are executed within established policies and procedures and may include instruments such as futures, forwards, swaps, options and FTRs that are sensitive to changes in the related commodity prices. For sensitivity analysis purposes, the hypothetical change in market prices of commodity-based financial derivative instruments is determined based on models that consider the market prices of commodities in future periods, the volatility of the market prices in each period, as well as the time value factors of the derivative instruments. Prices and volatility are principally determined based on observable market prices.

A hypothetical 10% unfavorable change in market prices of our non-trading commodity-based financial derivative instruments would have resulted in a decrease in fair value of approximately $510 million and $338 million as of March 31, 2008 and December 31, 2007, respectively. The change is primarily due to increased levels of gas and electricity derivative activity. A hypothetical 10% unfavorable change in commodity prices would have resulted in a decrease of approximately $4 million and $8 million in the fair value of our commodity-based financial derivative instruments held for trading purposes as of March 31, 2008 and December 31, 2007, respectively.

The impact of a change in energy commodity prices on our non-trading commodity-based financial derivative instruments at a point in time is not necessarily representative of the results that will be realized when such contracts are ultimately settled. Net losses from commodity derivative instruments used for hedging purposes, to the extent realized, will generally be offset by recognition of the hedged transaction, such as revenue from sales.

Interest Rate Risk

We manage our interest rate risk exposure predominantly by maintaining a balance of fixed and variable rate debt. We also enter into interest rate sensitive derivatives, including interest rate swaps and interest rate lock agreements. For financial instruments outstanding at March 31, 2008, a hypothetical 10% increase in market interest rates would have resulted in a decrease in annual earnings of approximately $7 million. A hypothetical 10% increase in market interest rates, as determined at December 31, 2007, would have resulted in a decrease in annual earnings of approximately $11 million.

Investment Price Risk

We are subject to investment price risk due to securities held as investments in decommissioning trust funds that are managed by third-party investment managers. These trust funds primarily hold marketable securities that are reported in our Consolidated Balance Sheets at fair value.

Following the reapplication of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, to the Virginia jurisdiction of our utility generation operations in April 2007, gains or losses on those decommissioning trust investments are deferred as regulatory liabilities.

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We recognized net realized losses (net of investment income) on nuclear decommissioning trust investments of $20 million for the three months ended March 31, 2008 and net realized gains (including investment income) of $27 million and $43 million for the three months ended March 31, 2007 and for the year ended December 31, 2007, respectively. For the three months ended March 31, 2008, we recorded, in AOCI and regulatory liabilities, a reduction in unrealized gains on these investments of $129 million. For the three months ended March 31, 2007, we recorded, in AOCI, a $2 million reduction in unrealized gains on these investments. For the year ended December 31, 2007, we recorded, in AOCI and regulatory liabilities, unrealized gains on these investments of $52 million.

We sponsor employee pension and other postretirement benefit plans, in which our employees participate, that hold investments in trusts to fund benefit payments. To the extent that the values of investments held in these trusts decline, the effect will be reflected in our recognition of the periodic cost of such employee benefit plans and the determination of the amount of cash to be contributed to the employee benefit plans.

ITEM 4. CONTROLS AND PROCEDURES

Senior management, including the Chief Executive Officer (CEO) and Chief Financial Officer (CFO), evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, the CEO and CFO have concluded that our disclosure controls and procedures are effective.

There were no changes in our internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

From time to time, we are alleged to be in violation or in default under orders, statutes, rules or regulations relating to the environment, compliance plans imposed upon or agreed to by us, or permits issued by various local, state and federal agencies for the construction or operation of facilities. Administrative proceedings may also be pending on these matters. In addition, in the ordinary course of business, we are involved in various legal proceedings. We believe that the ultimate resolution of these proceedings will not have a material adverse effect on our financial position, liquidity or results of operations. See Future Issues and Other Matters in MD&A for discussions on various environmental and other regulatory proceedings to which we are a party.

In October 2003, the EPA and MADEP each issued new NPDES permits for Brayton Point. The new permits contained identical conditions that in effect require the installation of cooling towers to address concerns over the withdrawal and discharge of cooling water. Following various appeals, in December 2007, the EPA issued an administrative order to Brayton Point that contained a schedule for implementing the permit. On the same day, Brayton Point withdrew its appeal of the permit from the U.S. Court of Appeals. In March 2008, MADEP issued a companion order resolving the state appeal and implementing the state permit. The state appeal was dismissed the same day. Currently, we estimate the total cost to install these cooling towers at approximately $500 million, of which $176 million is included in our planned capital expenditures through 2010.

ITEM 1A. RISK FACTORS

Our business is influenced by many factors that are difficult to predict, involve uncertainties that may materially affect actual results and are often beyond our control. We have identified a number of these risk factors in our Annual Report on Form 10-K for the year ended December 31, 2007, which should be taken into consideration when reviewing the information contained in this report. We have also identified an additional risk factor below. There have been no material changes with regard to the risk factors previously disclosed in our most recent Form 10-K. For other factors that may cause actual results to differ materially from those indicated in any forward-looking statement or projection contained in this report, see Forward-Looking Statements in MD&A.

Continued delays in the recovery of fuel costs at our regulated electric utility could negatively affect our electric utility’s cash flow, which could adversely affect our results of operations. Our regulated electric utility has a statutory right to recover from customers all prudently incurred fuel costs through fuel factors which have been implemented in our Virginia and North Carolina jurisdictions. However, as a result of increasing fuel costs and a statutory limitation on the amount of fuel recovery that can be collected from Virginia jurisdictional customers in the July 1, 2007 through June 30, 2008 fuel factor period, our electric utility has deferred a significant amount of fuel costs. Deferred recovery of fuel costs could have a negative impact on the cash flow of our electric utility. The recent fluctuations in fuel prices may make it difficult to accurately predict fuel costs. In the future, if actual fuel costs incurred during the fuel factor period exceed the estimate of costs which the Virginia Commission has approved for recovery in that period, we will not have authority to recover the excess costs through fuel rates until the following year when a new factor is determined. To the extent that such deferrals occur, the resulting delays in the current recovery of fuel costs could negatively impact the cash flow of our electric utility, which could adversely affect our results of operations.

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ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The table below provides certain information with respect to our purchases of our common stock:

ISSUER PURCHASES OF EQUITY SECURITIES


Period	(a) Total Number of Shares (or Units) Purchased⁽¹⁾	(b) Average Price Paid per Share (or Unit)		(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased under the Plans or Programs
1/1/08-1/31/08	46,181	$	47.43	N/A	53,971,148 shares/ $2.68 billion
2/1/08-2/29/08	185,557		42.30	N/A	53,971,148 shares/ $2.68 billion
3/1/08-3/31/08	4,437		39.94	N/A	53,971,148 shares/ $2.68 billion
Total	236,175	$	43.26	N/A	53,971,148 shares/ $2.68 billion

(1)	Amount represents registered shares tendered by employees to satisfy tax withholding obligations on vested restricted stock.

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Item 6. EXHIBITS

(a) Exhibits:


3.1		Articles of Incorporation as in effect August 9, 1999, as amended March 12, 2001 (Exhibit 3.1, Form 10-K for the year ended December 31, 2002, File No. 1-8489, incorporated by reference), as amended November 9, 2007 (Exhibit 3, Form 8-K, filed November 9, 2007, File No. 1-8489, incorporated by reference).

3.2		Amended and Restated Bylaws effective on June 20, 2007 (Exhibit 3.1, Form 8-K filed June 22, 2007, File No. 1-8489, incorporated by reference).

4.1		Dominion Resources, Inc. agrees to furnish to the SEC upon request any other instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of its total consolidated assets.

4.2		Form of Senior Indenture, dated as of June 1, 1998, between Virginia Electric and Power Company and The Bank of New York (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)) as supplemented by the First Supplemental Indenture (Exhibit 4.2, Form 8-K, dated June 12, 1998, File No. 1-2255, incorporated by reference); Second Supplemental Indenture (Exhibit 4.2, Form 8-K, dated June 3, 1999, File No.1-2255, incorporated by reference); Third Supplemental Indenture (Exhibit 4.2, Form 8-K, dated October 27, 1999, File No. 1-2255, incorporated by reference); Form of Fourth Supplemental Indenture (Exhibit 4.2, Form 8-K, dated March 22, 2001, File No. 1-2255, incorporated by reference); and Form of Fifth Supplemental Indenture (Exhibit 4.3, Form 8-K, dated March 22, 2001, File No. 1-2255, incorporated by reference); Form of Sixth Supplemental Indenture (Exhibit 4.2, Form 8-K, dated January 24, 2002, incorporated by reference); Seventh Supplemental Indenture dated September 1, 2002 (Exhibit 4.4, Form 8-K filed September 11, 2002, File No. 1-2255, incorporated by reference); Form of Eighth Supplemental Indenture (Exhibit 4.2, Form 8-K filed February 27, 2003, File No. 1-2255, incorporated by reference); Form of Ninth Supplemental Indenture (Exhibit 4.2, Form 8-K filed December 4, 2003, File No. 1-2255, incorporated by reference); Form of Tenth Supplemental Indenture (Exhibit 4.3, Form 8-K filed December 4, 2003, File No. 1-2255, incorporated by reference); Form of Eleventh Supplemental Indenture (Exhibit 4.2, Form 8-K filed December 11, 2003, File No. 1-2255, incorporated by reference); Form of Twelfth Supplemental Indenture (Exhibit 4.3, Form S-4 filed October 7, 2004, File No. 333-119605, incorporated by reference); Form of Twelfth Supplemental Indenture (Exhibit 4.2, Form 8-K filed January 12, 2006, File No. 1-2255, incorporated by reference); Form of Thirteenth Supplemental Indenture (Exhibit 4.3, Form 8-K filed January 12, 2006, File No. 1-2255, incorporated by reference); Form of Fourteenth Supplemental Indenture (Exhibit 4.2, Form 8-K filed May 16, 2007, File No. 1-2255, incorporated by reference); Form of Fifteenth Supplemental Indenture (Exhibit 4.2, Form 8-K filed September 10, 2007, File No. 1-2255, incorporated by reference); Form of Sixteenth Supplemental Indenture (Exhibit 4.2, Form 8-K filed November 30, 2007, File No. 1-2255, incorporated by reference); Form of Seventeenth Supplemental Indenture (Exhibit 4.3, Form 8-K filed November 30, 2007, File No. 1-2255, incorporated by reference); Form of Eighteenth Supplemental Indenture (Exhibit 4.2, Form 8-K filed April 15, 2008, File No. 1-2255, incorporated by reference).

10.1		Form of Restricted Stock Award Agreement under 2008 Long-Term Compensation Program approved March 27, 2008 (Exhibit 10.1, Form 8-K filed April 2, 2008, File No. 1-8489, incorporated by reference).

10.2		2008 Performance Grant Plan under 2008 Long-Term Compensation Program approved March 27, 2008 (Exhibit 10.2, Form 8-K filed April 2, 2008, File No. 1-8489, incorporated by reference).

10.3		Restricted Stock Award Agreement for Thomas N. Chewning approved March 27, 2008 (Exhibit 10.3, Form 8-K filed April 2, 2008, File No. 1-8489, incorporated by reference).

12		Ratio of earnings to fixed charges (filed herewith).

31.1		Certification by Registrant’s CEO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).

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31.2		Certification by Registrant’s CFO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).

32		Certification to the SEC by Registrant’s CEO and CFO, as required by Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).

99		Condensed consolidated earnings statements (unaudited) (filed herewith).

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


		DOMINION RESOURCES, INC. Registrant

May 1, 2008		/s/ Thomas P. Wohlfarth
		Thomas P. Wohlfarth
		Senior Vice President and Chief Accounting Officer

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