Edgar Filing: DOMINION RESOURCES INC /VA/

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

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, 2009

¨	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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ 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.

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, 2009, the latest practicable date for determination, 589,959,716 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, 2009 and 2008	4

	Consolidated Balance Sheets – March 31, 2009 and December 31, 2008	5

	Consolidated Statements of Cash Flows – Three Months Ended March 31, 2009 and 2008	7

	Notes to Consolidated Financial Statements	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	39

Item 4.	Controls and Procedures	40

	PART II. Other Information

Item 1.	Legal Proceedings	41

Item 1A.	Risk Factors	41

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	42

Item 6.	Exhibits	43

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)
BBIFNA		Babcock & Brown Infrastructure Fund North America
bcf		Billion cubic feet
bcfe		Billion cubic feet equivalent
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.
DFS		Dominion Field Services, Inc.
Dominion Direct®		A dividend reinvestment and open enrollment direct stock purchase plan
Dominion East Ohio		The East Ohio Gas Company
Dominion Retail		Dominion Retail, Inc.
DRS		Dominion Resources Services, Inc.
DTI		Dominion Transmission, Inc.
DVP		Dominion Virginia Power operating segment
E&P		Exploration & production
EITF		Emerging Issues Task Force
EPA		Environmental Protection Agency
EPS		Earnings per share
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FIN		FASB Interpretation No.
FSP		FASB Staff Position
FTRs		Financial transmission rights
GAAP		U.S. generally accepted accounting principles
Hope		Hope Gas, Inc.
kWh		Kilowatt-hour
LNG		Liquefied natural gas
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 Service
Mw		Megawatt
mwhrs		Megawatt hours
North Anna		North Anna power station
NRC		Nuclear Regulatory Commission
Pennsylvania Commission		Pennsylvania Public Utility Commission
Peoples		The Peoples Natural Gas Company
PJM		PJM Interconnection, LLC
ROE		Return on equity
RTO		Regional transmission organization
SEC		Securities and Exchange Commission
SFAS		Statement of Financial Accounting Standards
Standard & Poor’s		Standard & Poor’s Ratings Services, a division of the McGraw-Hill Companies, Inc.
U.S.		United States of America
VIEs		Variable interest entities
Virginia Commission		Virginia State Corporation Commission
Virginia Power		Virginia Electric and Power Company
VPEM		Virginia Power Energy Marketing, Inc.
West Virginia Commission		Public Service 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,
	2009			2008
(millions, except per share amounts)
Operating Revenue	$	4,778		$	4,353

Operating Expenses
Electric fuel and other energy-related purchases		1,141			781
Purchased electric capacity		108			107
Purchased gas		1,138			1,155
Other operations and maintenance		1,250			843
Depreciation, depletion and amortization		279			254
Other taxes		157			154

Total operating expenses		4,073			3,294

Income from operations		705			1,059

Other income (loss)		(66	)		(3	)
Interest and related charges⁽¹⁾		224			219

Income before income tax expense		415			837
Income tax expense		167			157

Net Income	$	248		$	680

Earnings Per Common Share – Basic and Diluted
Net income	$	0.42		$	1.18

Dividends paid per common share	$	0.4375		$	0.395

(1)	Includes $5 million and $13 million incurred with affiliated trusts for the three months ended March 31, 2009 and 2008, respectively.

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

PAGE 4

DOMINION RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)


	March 31, 2009			December 31, 2008⁽¹⁾
(millions)
ASSETS
Current Assets
Cash and cash equivalents	$	141		$	66
Customer receivables (less allowance for doubtful accounts of $32 at both dates)		2,300			2,354
Other receivables (less allowance for doubtful accounts of $6 and $7)		150			205
Inventories		888			1,166
Derivative assets		1,595			1,497
Assets held for sale		1,355			1,416
Other		863			957

Total current assets		7,292			7,661

Investments
Nuclear decommissioning trust funds		2,140			2,246
Investment in equity method affiliates		749			726
Other		267			285

Total investments		3,156			3,257

Property, Plant and Equipment
Property, plant and equipment		36,211			35,448
Accumulated depreciation, depletion and amortization		(12,858	)		(12,174	)

Total property, plant and equipment, net		23,353			23,274

Deferred Charges and Other Assets
Goodwill		3,503			3,503
Regulatory assets		2,162			2,226
Other		2,221			2,132

Total deferred charges and other assets		7,886			7,861

Total assets	$	41,687		$	42,053

(1)	Our Consolidated Balance Sheet at December 31, 2008 has been derived from the audited Consolidated Financial Statements at that date.

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

PAGE 5

DOMINION RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)


	March 31, 2009			December 31, 2008⁽¹⁾
(millions)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Securities due within one year	$	444		$	444
Short-term debt		1,619			2,030
Accounts payable		1,263			1,499
Accrued interest, payroll and taxes		968			754
Derivative liabilities		969			1,100
Liabilities held for sale		561			570
Accrued dividends		—			260
Other		1,182			1,137

Total current liabilities		7,006			7,794

Long-Term Debt
Long-term debt		13,833			13,890
Junior subordinated notes payable:
Affiliates		268			268
Other		798			798

Total long-term debt		14,899			14,956

Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		3,943			4,137
Asset retirement obligations		1,828			1,802
Pension and other postretirement benefit liabilities		1,549			1,525
Regulatory liabilities		902			944
Other		594			561

Total deferred credits and other liabilities		8,816			8,969

Total liabilities		30,721			31,719

Commitments and Contingencies (see Note 15)

Subsidiary Preferred Stock Not Subject to Mandatory Redemption		257			257

Common Shareholders’ Equity
Common stock – no par⁽²⁾		6,204			5,994
Other paid-in capital		182			182
Retained earnings		4,417			4,170
Accumulated other comprehensive loss		(94	)		(269	)

Total common shareholders’ equity		10,709			10,077

Total liabilities and shareholders’ equity	$	41,687		$	42,053

(1)	Our Consolidated Balance Sheet at December 31, 2008 has been derived from the audited Consolidated Financial Statements at that date.

(2)	1 billion shares authorized; 590 million shares outstanding at March 31, 2009 and 583 million shares outstanding at December 31, 2008.

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,	2009			2008
(millions)
Operating Activities
Net income	$	248		$	680
Adjustments to reconcile net income to net cash from operating activities:
Dominion Capital, Inc. impairment loss		—			62
Impairment of gas and oil properties		455			—
Net change in realized and unrealized derivative (gains) losses		(45	)		18
Depreciation, depletion and amortization		325			294
Deferred income taxes and investment tax credits		(365	)		(55	)
Other adjustments		93			2
Changes in:
Accounts receivable		95			(188	)
Inventories		271			196
Deferred fuel and purchased gas costs		226			(140	)
Accounts payable		(264	)		(254	)
Accrued interest, payroll and taxes		223			(250	)
Margin deposit assets and liabilities		(21	)		(250	)
Prepayments		35			183
Other operating assets and liabilities		201			253

Net cash provided by operating activities		1,477			551

Investing Activities
Plant construction and other property additions		(796	)		(650	)
Additions to gas and oil properties		(41	)		(47	)
Proceeds from sale of securities and loan receivable collections and payoffs		289			651
Purchases of securities and loan receivable originations		(289	)		(608	)
Other		(37	)		(64	)

Net cash used in investing activities		(874	)		(718	)

Financing Activities
Issuance (repayment) of short-term debt, net		(411	)		619
Issuance of long-term debt		—			30
Repayment of long-term debt		(4	)		(510	)
Issuance of common stock		147			58
Common dividend payments		(257	)		(228	)
Other		(2	)		(4	)

Net cash used in financing activities		(527	)		(35	)

Increase (decrease) in cash and cash equivalents		76			(202	)
Cash and cash equivalents at beginning of period⁽¹⁾		71			287

Cash and cash equivalents at end of period⁽²⁾	$	147		$	85

Significant Noncash Investing and Financing Activities
Accrued capital expenditures	$	186		$	60
Debt for equity exchange	$	56		$	—

(1)	2009 and 2008 amounts include $5 million and $4 million, respectively, of cash classified as held for sale in our Consolidated Balance Sheets.

(2)	2009 and 2008 amounts include $6 million of cash classified as held for sale in our Consolidated Balance Sheets.

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 Resources, Inc., 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), Dominion Field Services, Inc. (DFS), Dominion Retail, Inc. (Dominion Retail), Dominion Resources Services, Inc. (DRS) 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, 2009, 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, a regional transmission organization (RTO), and its electric transmission facilities are integrated into the PJM wholesale electricity markets.

DEI is involved 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 and gathering of natural gas and the extraction of natural gas liquids in the Appalachian basin. We also own and operate a liquefied natural gas (LNG) import and storage facility in Maryland.

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

DEPI explores for, develops and produces natural gas, natural gas liquids and oil in the Appalachian basin.

DFS is involved in the gathering and aggregation of Appalachian natural gas supply and provides various marketing-related services to its customers.

Dominion Retail markets gas, electricity and related products and services to residential and small commercial and industrial customers. As of March 31, 2009, these nonregulated retail energy marketing operations served approximately 1.7 million residential and small commercial customer accounts in the Northeast, mid-Atlantic and Midwest regions of the U.S and Texas.

DRS provides accounting, legal, finance and certain administrative and technical services to our subsidiaries. In addition, all of our officers are employees of DRS.

As of March 31, 2009, 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. Of these customers, approximately 500,000 are served by Peoples and Hope, which are held for sale as discussed in Note 4.

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 corporate, service company and other functions and the net impact of certain operations to be disposed of, which are discussed in Note 4. Corporate and Other also includes specific items attributable to Dominion’s operating segments that are not included in profit measures evaluated by executive management, in assessing the segments’ performance or allocating resources among the segments.

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.

PAGE 8

Note 2. Significant Accounting Policies

As permitted by the rules and regulations of the 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 GAAP. These unaudited Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and Notes in our Annual Report on Form 10-K for the year ended December 31, 2008.

In our opinion, the accompanying unaudited Consolidated Financial Statements contain all adjustments necessary to present fairly our financial position as of March 31, 2009 and our results of operations and cash flows for the three months ended March 31, 2009 and 2008. Such adjustments are normal and recurring in nature unless otherwise noted.

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. See Note 9 for further information on fair value measurements in accordance with 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 other energy-related purchases, purchased gas expenses and other factors.

Certain amounts in our 2008 Consolidated Financial Statements and Notes have been recast to conform to the 2009 presentation.

Note 3. Newly Adopted Accounting Standards

FSP APB 14-1

We adopted the provisions of FSP APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement) effective January 1, 2009. The FSP requires issuers of convertible debt instruments to separately account for the liability and equity components in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. The provisions of FSP APB 14-1 were to be applied retrospectively to our 2.125% unsecured convertible senior notes due in 2023; however, the impact on prior periods was immaterial. Therefore, we did not recast our prior period financial statements and will instead apply the provisions of this FSP prospectively. See Note 13 for additional information on our convertible debt securities.

Note 4. Dispositions

Sale of Certain DCI Operations

Previously, Dominion Capital, Inc. (DCI) held an investment in the subordinated notes of a third-party collateralized debt obligation (CDO) entity which we consolidated in accordance with FIN 46R (revised December 2003), Consolidation of Variable Interest Entities. In March 2008, we reached 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 and recognized impairment losses of $62 million ($38 million after-tax) in other operations and maintenance expense. In connection with the sale of the subordinated notes, in April 2008, we received proceeds of $54 million, including accrued interest.

Planned Sale of Regulated Gas Distribution Subsidiaries

In March 2006, we entered into an agreement with Equitable Resources, Inc. (Equitable) for the sale of Peoples and Hope. In January 2008, Dominion and Equitable announced the termination of that agreement, primarily due to the continued delays in achieving final regulatory approvals. We continued to seek other offers for the purchase of these utilities.

PAGE 9

In July 2008, we announced that we entered into an agreement with a subsidiary of Babcock & Brown Infrastructure Fund North America (BBIFNA) to sell Peoples and Hope for approximately $910 million, subject to adjustments to reflect levels of capital expenditures and changes in working capital. The transaction is expected to close in 2009, subject to regulatory approvals in Pennsylvania and West Virginia as well as clearance under the Exon-Florio provision of the Omnibus Trade and Competitiveness Act.

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, 2009			December 31, 2008
(millions)
ASSETS
Current Assets
Customer receivables	$	186		$	172
Other		59			142

Total current assets		245			314

Property, Plant and Equipment
Property, plant and equipment		1,212			1,204
Accumulated depreciation, depletion and amortization		(357	)		(358	)

Total property, plant and equipment, net		855			846

Deferred Charges and Other Assets
Regulatory assets		154			156
Other		101			100

Total deferred charges and other assets		255			256

Assets held for sale	$	1,355		$	1,416

LIABILITIES
Current Liabilities	$	179		$	192
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		293			289
Other		89			89

Total deferred credits and other liabilities		382			378

Liabilities held for sale	$	561		$	570

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

Note 5. Operating Revenue

Our operating revenue consists of the following:


	Three Months Ended March 31,
	2009		2008
(millions)
Operating Revenue
Electric sales:
Regulated	$	1,825	$	1,496
Nonregulated		994		885
Gas sales:
Regulated		516		602
Nonregulated		912		851
Gas transportation and storage		420		389
Other		111		130

Total operating revenue	$	4,778	$	4,353

PAGE 10

Note 6. Income Taxes

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


	Three Months Ended March 31,
	2009		2008
U.S. statutory rate	35.0	%	35.0	%
Increases (reductions) resulting from:
State taxes, net of federal benefit	4.3		2.1
Reversal of deferred taxes – stock of subsidiaries held for sale	—		(16.2	)
State legislative changes	0.3		(1.7	)
Other, net	0.6		(0.4	)

Effective tax rate	40.2	%	18.8	%

In 2008, our effective tax rate reflected the reversal of $136 million 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. In 2006, based on the intended form of the sale to Equitable, we recognized these deferred tax liabilities since this 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. At that time, based on our expectation that the form of any future disposal of these subsidiaries would be structured so that the taxable gain would instead be determined by reference to the basis in the subsidiaries’ underlying assets, we reversed the related deferred tax liabilities recognized in 2006. As discussed in Note 4, we have executed a new agreement to sell Peoples and Hope, whereby we will determine our taxable gain by reference to the basis in the subsidiaries’ underlying assets.

At March 31, 2009, unrecognized tax benefits related to current year tax positions were $11 million. During the three months ended March 31, 2009, unrecognized tax benefits related to prior year uncertain tax positions increased by $30 million and decreased by $29 million, reflecting settlement negotiations, payments to tax authorities and amounts that otherwise become deductible in 2009.

For a discussion of reasonably possible changes that could occur in our unrecognized tax benefits during the next twelve months, see Note 7 to the Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2008.

Note 7. Earnings Per Share

The following table presents the calculation of our basic and diluted EPS:


	Three Months Ended March 31,
	2009		2008
(millions, except EPS)
Net income	$	248	$	680

Average shares of common stock outstanding – basic		585.3		575.3
Net effect of potentially dilutive securities⁽¹⁾		0.4		3.1

Average shares of common stock outstanding – diluted		585.7		578.4

Basic and Diluted EPS
Net income	$	0.42	$	1.18

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

PAGE 11

Potentially dilutive securities with the right to acquire approximately 1.6 million common shares for the three months ended March 31, 2009 were not included in the respective period’s calculation of diluted EPS because the exercise or purchase prices of those instruments were greater than the average market price of our common shares. There were no such anti-dilutive securities outstanding for the three months ended March 31, 2008.

Note 8. Comprehensive Income

The following table presents total comprehensive income:


	Three Months Ended March 31,
	2009		2008
(millions)
Net income	$	248	$	680
Other comprehensive income (loss):
Net other comprehensive income associated with effective portion of changes in fair value of derivatives designated as cash flow hedges, net of taxes and amounts reclassified to earnings⁽¹⁾		151		(336	)
Other, net of tax⁽²⁾		24		(56	)

Other comprehensive income (loss)		175		(392	)

Total comprehensive income	$	423	$	288

(1)	Principally reflects a decrease in commodity prices in 2009 as compared to an increase in 2008.

(2)

2009 amount primarily represents an increase in unrealized gains on investments held in merchant nuclear decommissioning trusts and the recognition of certain pension and other postretirement benefit-related amounts as a component of net periodic benefit cost that were previously deferred in AOCI. 2008 amount largely reflects a net reduction in unrealized gains on investments held in nuclear decommissioning trusts.

Note 9. Fair Value Measurements

Our fair value measurements are made in accordance with the policies discussed in Note 8 to our Annual Report on Form 10-K for the year ended December 31, 2008. In addition, see Note 10 for further information about our derivatives and hedge accounting activities.

The following table presents our assets and liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions as of March 31, 2009 and December 31, 2008:


	Level 1		Level 2		Level 3		Total
(millions)
As of March 31, 2009
Assets
Derivatives	$	165	$	1,849	$	205	$	2,219
Investments		679		1,433		—		2,112

Total assets		844		3,282		205		4,331
Liabilities
Derivatives	$	12	$	1,066	$	107	$	1,185

As of December 31, 2008
Assets
Derivatives	$	125	$	1,672	$	243	$	2,040
Investments		725		1,501		—		2,226

Total assets		850		3,173		243		4,266
Liabilities
Derivatives	$	7	$	1,146	$	144	$	1,297

PAGE 12

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


	Three Months ended March 31,
	2009			2008
(millions)
Balance at January 1,	$	99		$	(61	)
Total realized and unrealized gains or (losses):
Included in earnings		(62	)		9
Included in other comprehensive income (loss)		20			(50	)
Included in regulatory and other assets/liabilities		23			33
Purchases, issuances and settlements		34			(1	)
Transfers out of Level 3		(16	)		(2	)

Balance at March 31,	$	98		$	(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	$	(12	)	$	3

The following table presents gains and losses included in earnings in the Level 3 fair value category:


	Operating revenue			Electric fuel and other energy-related purchases			Purchased gas			Total
(millions)
Three Months Ended March 31, 2009
Total gains or (losses) included in earnings	$	(4	)	$	(51	)	$	(7	)	$	(62	)
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		(9	)		3			(6	)		(12	)

Three Months Ended March 31, 2008
Total gains or (losses) included in earnings	$	(16	)	$	19		$	6		$	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		(6	)		3			6			3

As of March 31, 2009, our net balance of commodity derivatives categorized as Level 3 fair value measurements was a net asset of $98 million. A hypothetical 10% increase in commodity prices would decrease the net asset by $27 million, while a hypothetical 10% decrease in commodity prices would increase the net asset by $28 million.

Additionally, during the first quarter of 2009, we evaluated an equity method investment for impairment and recorded a $23 million impairment in other income (loss) in our Consolidated Statement of Income. The resulting fair value of $10 million was estimated using an expected present value cash flow model and is considered a Level 3 fair value measurement due to the use of significant unobservable inputs related to the timing and amount of future equity distributions based on the investee’s future financing structure, contractual and market based revenues and operating costs.

Note 10. Derivatives and Hedge Accounting Activities

Our accounting policies and objectives and strategies for using derivative instruments are discussed in Note 2 to our Annual Report on Form 10-K for the year ended December 31, 2008.

The following table presents the volume of our derivative activity as of March 31, 2009. These volumes are based on open derivative positions and represent the combined volume of our long and short positions on an absolute basis, except in the case of offsetting

PAGE 13

deals, for which we present the net volume of our long and short positions on an absolute basis. A substantial portion of our derivatives is designated under hedge accounting or is subject to regulatory accounting treatment.


	Current		Noncurrent
Natural Gas (bcf):
Fixed price⁽¹⁾		514.0		229.2
Basis		1,042.6		617.3
Electricity (mwhrs):
Fixed price⁽¹⁾⁽²⁾		21,013,162		20,771,469
FTRs		20,182,334		1,171
Liquids (gallons)⁽³⁾		178,109,341		238,266,000
Interest rate	$	1,710,000,000	$	1,350,000,000
Foreign currency (euros)		12,521,770		4,000,000

(1)

Includes options.

(2)

Includes capacity derivatives.

(3)

Includes natural gas liquids and oil derivatives.

For the three months ended March 31, 2009 and 2008, gains or losses on hedging instruments determined to be ineffective and excluded from the measurement of ineffectiveness were not material. Amounts excluded from the measurement of ineffectiveness include gains or losses attributable to changes in the time value of options and changes in the differences between spot prices and forward prices.

The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in our Consolidated Balance Sheet at March 31, 2009:


	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings during the next 12 Months After-Tax			Maximum Term
(millions)
Commodities:
Gas	$	(8	)	$	(9	)	51 months
Electricity		558			381		33 months
Natural gas liquids		110			43		33 months
Other		5			2		74 months
Interest rate		(7	)		(4	)	381 months
Foreign currency		1			1		56 months

Total	$	659		$	414

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.

PAGE 14

Fair Value and Gains and Losses on Derivative Instruments

The following table presents the fair values of our derivatives as of March 31, 2009 and where they are recorded on our Consolidated Balance Sheet:


	Fair Value – Derivatives under Hedge Accounting		Fair Value – Derivatives not under Hedge Accounting		Total Fair Value
(millions)
ASSETS
Current Assets
Commodity	$	1,078	$	497	$	1,575
Interest rate		20		—		20

Total current derivative assets		1,098		497		1,595

Noncurrent Assets
Commodity		501		120		621
Interest rate		3		—		3

Total noncurrent derivative assets⁽¹⁾		504		120		624

Total derivative assets		1,602		617		2,219

LIABILITIES
Current Liabilities
Commodity		402		547		949
Interest rate		20		—		20

Total current derivative liabilities		422		547		969

Noncurrent Liabilities
Commodity		72		131		203
Interest rate		13		—		13

Total noncurrent derivative liabilities⁽²⁾		85		131		216

Total derivative liabilities	$	507	$	678	$	1,185

(1)	Noncurrent derivative assets are recorded in other deferred charges and other assets on our Consolidated Balance Sheet.

(2)	Noncurrent derivative liabilities are recorded in other deferred credits and other liabilities on our Consolidated Balance Sheet.

The following tables present the gains and losses on our derivatives for the period ended March 31, 2009, as well as where the associated activity is presented on our Consolidated Balance Sheet and Statement of Income:


Derivatives in SFAS No. 133 Fair Value Hedging Relationships	Amount of Gain (Loss) Recognized in Income on Derivatives, Hedged Item and Regulatory Assets/Liabilities
(millions)
Commodity⁽¹⁾	$	(3	)

Total	$	(3	)

(1)	Amounts recorded include $(4) million in purchased gas and $1 million in electric fuel and other energy-related purchases in our Consolidated Statement of Income.

PAGE 15


Derivatives in SFAS No. 133 Cash Flow Hedging Relationships	Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)⁽¹⁾			Amount of Gain (Loss) Reclassified from AOCI into Income			Amount of Gain (Loss) on Derivatives Subject to Regulatory Treatment⁽²⁾
(millions)
Derivative Type and Location of Gains (Losses)
Commodity
Operating revenue				$	238
Purchased gas					(48	)
Electric fuel and other energy-related purchases					(5	)
Purchased electric capacity					2

Total commodity	$	431			187		$	11

Interest rate⁽³⁾		(14	)		(1	)		11
Foreign currency⁽⁴⁾		—			1			(2	)

Total	$	417		$	187		$	20

(1)	Amounts deferred into AOCI have no associated effect in our Consolidated Statement of Income.

(2)	Represents net derivative activity deferred into and amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in our Consolidated Statement of Income.

(3)	Amounts recorded in our Consolidated Statement of Income are classified in interest expense.

(4)	Amounts recorded in our Consolidated Statement of Income are classified in electric fuel and other energy-related purchases.


Derivatives not designated as hedging instruments under SFAS No. 133	Amount of Gain (Loss) Recognized in Income on Derivatives⁽¹⁾
(millions)
Derivative Type and Location of Gains (Losses)
Commodity
Operating revenue	$	33
Purchased gas		(32	)
Electric fuel and other energy-related purchases		(51	)

Total	$	(50	)

(1)	Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect on our Consolidated Statement of Income.

See Note 9 for further information about fair value measurements and associated valuation methods for derivatives under SFAS No. 157.

Note 11. 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%, assuming period-end hedge-adjusted prices. If net capitalized costs exceed the ceiling at the end of any quarterly period, then a permanent write-down of the assets must be recognized in that period.

Approximately 4% of our anticipated production is hedged by qualifying cash flow hedges, for which hedge-adjusted prices were used to calculate estimated future net revenue. At March 31, 2009, due to declines in natural gas and oil prices, we recorded a ceiling test impairment charge of $455 million ($272 million after-tax) in other operations and maintenance expense in our Consolidated Statement of Income. Excluding the effects of hedge-adjusted prices in calculating the ceiling limitation, the impairment would have been $631 million ($378 million after-tax).

PAGE 16

Note 12. Variable Interest Entities

As discussed in Note 16 to the Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2008, certain variable pricing terms in some of our long-term power and capacity contracts cause them to be considered variable interests in the counterparties in accordance with FIN 46R.

We have long-term power and capacity contracts with four non-utility generators with an aggregate generation capacity of approximately 940 Mw. These contracts contain certain variable pricing mechanisms in the form of partial fuel reimbursement that we consider to be variable interests. After an evaluation of the information provided to us by these entities, we were unable to determine whether they were variable interest entities (VIEs). However, the information they provided, as well as our knowledge of generation facilities in Virginia, enabled us to conclude that, if they were VIEs, we would not be the primary beneficiary. This conclusion was based primarily on a qualitative assessment of our variable interests as compared to the operations, commodity price and other risks retained by the equity and debt holders during the remaining terms of our contracts and for the years the entities are expected to operate after our contractual relationships expire. 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 $1.9 billion as of March 31, 2009. We paid $53 million and $52 million for electric capacity and $41 million and $47 million for electric energy to these entities for the three months ended March 31, 2009 and 2008, respectively.

Note 13. 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 interim 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.

Our credit facility commitments are with a large consortium of banks, which included Lehman Brothers Holdings Inc. (Lehman). In September 2008, Lehman filed for protection under Chapter 11 of the federal Bankruptcy Code in the United States Bankruptcy Court in the Southern District of New York. In February 2009, we assigned $35 million of Lehman’s commitment to another bank. In March 2009, we executed a consent agreement with the bank syndicates to reduce Lehman’s remaining commitment to zero in each of our credit facilities in which it had participated.

At March 31, 2009, we had committed lines of credit totaling $5.2 billion. These lines of credit support commercial paper borrowings, bank loans and letter of credit issuances. At March 31, 2009, we had the following commercial paper, bank loans and letters of credit outstanding and capacity available under our 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⁾	$	2,872	$	536	$	—	$	249	$	2,087
Five-year Dominion credit facility⁽²⁾		1,700		113		970		13		604
Five-year Dominion bilateral facility⁽³⁾		200		—		—		89		111
364-day Dominion credit facility⁽⁴⁾		467		—		—		—		467

Totals	$	5,239	$	649	$	970	$	351	$	3,269

(1)	This credit facility was entered into in February 2006 and terminates in February 2011. This 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)	This credit facility was entered into in August 2005 and terminates in August 2010. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances.

(3)	This facility was entered into in December 2005 and terminates in December 2010. This facility can be used to support bank borrowings, commercial paper and letter of credit issuances.

(4)	This credit facility was entered into in July 2008 and terminates in July 2009. This credit facility can be used to support bank borrowings and the issuance of commercial paper.

In addition to the credit facility commitments of $5.2 billion disclosed above, we also have a $182 million five-year credit facility that supports certain Virginia Power tax-exempt financings.

PAGE 17

Long-Term Debt

We repaid $4 million of long-term debt during the three months ended March 31, 2009.

Convertible Securities

We have $202 million of outstanding contingent convertible senior notes that are convertible by holders into a combination of cash and shares of our common stock under certain circumstances. The conversion feature requires that the principal amount of each note be repaid in cash, while 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, 2009, the conversion rate has been adjusted to 27.831 shares of common stock per $1,000 principal amount of senior notes, primarily due to individual dividend payments above the level paid at issuance.

As of December 31, 2008, the closing price of our common stock was not equal to $43.28 per share or higher for at least 20 out of the last 30 consecutive trading days. Therefore, the senior notes were not eligible for conversion during the first quarter of 2009. As of March 31, 2009, the closing price of our common stock was not equal to $43.12 per share or higher for at least 20 out of the last 30 consecutive trading days, therefore, the senior notes are not eligible for conversion during the second quarter of 2009.

Issuance of Common Stock

During the three months ended March 31, 2009, we issued 4.6 million shares of common stock and received cash proceeds of $147 million. We issued 2.8 million shares through at-the-market issuances under our sales agency agreements and received cash proceeds of $89 million, net of fees and commissions paid of $1 million. The remainder of the shares issued and cash proceeds received during the three months ended March 31, 2009 were through Dominion Direct^®, employee savings plans and the exercise of employee stock options.

In February 2009, we also issued approximately 1.6 million shares of common stock to an existing holder of our senior notes, in a privately negotiated transaction, in exchange for approximately $56 million of the principal of two series of our outstanding senior notes, which were retired. The transaction was exempt from registration pursuant to Section 3(a)(9) of the Securities Act and no commission or remuneration was paid in connection with the exchange.

In April 2009, we issued 3.3 million shares of common stock through at-the-market issuances under our sales agency agreements and received cash proceeds of $102 million, net of fees and commissions paid of $1 million. Following these issuances, we have $207 million of remaining stock issuance authorization under sales agency agreements; however, we expect remaining 2009 equity needs to be met by proceeds from Dominion Direct^®, employee savings plans and the exercise of employee stock options.

Note 14. Stock-Based Awards

Our results for the three months ended March 31, 2009 and 2008 include $11 million and $7 million, respectively, of compensation costs and $4 million and $2 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.

PAGE 18

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, 2009:


	Shares		Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Life	Aggregated Intrinsic Value⁽¹⁾
	(thousands)				(years)	(millions)
Outstanding and exercisable at January 1, 2009	5,558		$	30.53
Exercised	(74	)		24.36		$	1
Forfeited/expired	(10	)		33.02

Outstanding and exercisable at March 31, 2009	5,474		$	30.61	1.94	$	8

(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 $4 million and $8 million in the three months ended March 31, 2009 and 2008, 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, 2009:


	Shares		Weighted-Average Grant Date Fair Value
	(thousands)
Nonvested at January 1, 2009	1,756		$	38.55
Granted	378			34.96
Vested	(99	)		31.87
Cancelled and forfeited	(2	)		43.31
Converted from goal-based stock to restricted stock	185			44.18

Nonvested at March 31, 2009	2,218		$	38.71

As of March 31, 2009, unrecognized compensation cost related to nonvested restricted stock awards totaled approximately $33 million and is expected to be recognized over a weighted-average period of 1.6 years.

Goal-Based Stock

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

The actual number of shares issued will vary between zero and 200% of 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. Goal-based stock awards granted to key non-officer employees convert to restricted stock at the end of the two-year performance period and generally vest three years from the original grant date. Awards to officers vest at the end of the two-year performance period. All goal-based stock awards are settled by issuing new shares. Current outstanding goal-based shares include awards granted in April 2008 and February 2009.

After the performance period for the April 2007 grants ended on December 31, 2008, the Compensation, Governance and Nominating Committee determined the actual performance against metrics established for those awards. For awards to key non-officer employees, 127 thousand shares of the outstanding goal-based stock awards granted in April 2007 were converted to 185 thousand shares of restricted stock for the remaining term of the vesting period ending in April 2010. For awards to officers, 27 thousand shares of the outstanding goal-based stock awards were converted to 38 thousand non-restricted shares and issued to the officers.

PAGE 19

For remaining goal-based stock awards, at March 31, 2009, the targeted number of shares to be issued is 177 thousand. The following table provides a summary of goal-based stock activity for the three months ended March 31, 2009:


	Targeted Number of Shares		Weighted-Average Grant Date Fair Value
	(thousands)
Nonvested at January 1, 2009	315		$	42.56
Granted	16			35.18
Vested	(27	)		44.46
Converted from goal-based stock to restricted stock	(127	)		44.18

Nonvested at March 31, 2009	177		$	40.42

At March 31, 2009, unrecognized compensation cost related to nonvested goal-based stock awards totaled approximately $8 million and is expected to be recognized over a weighted-average period of 1.4 years.

Cash-Based Performance Grant

The actual payout of our cash-based performance grants will vary between zero and 200% of the targeted amount based on the level of performance metrics achieved.

The targeted amount of the cash-based performance grant made to officers in April 2007 was $11 million, but the actual payout of the award in February 2009 determined by the Compensation, Governance and Nominating Committee was $16 million, based on the level of performance metrics achieved. At December 31, 2008, a liability of $16 million had been accrued for this award.

In April 2008, a cash-based performance grant was made to officers. Payout of the performance grant will occur by March 15, 2010 and is based on the achievement of three performance metrics during 2008 and 2009: return on invested capital, book value per share and total shareholder return relative to that of a peer group of companies. At March 31, 2009, the targeted amount of the grant was $12 million and a liability of $7 million had been accrued for this award.

In February 2009, a cash-based performance grant was made to officers. Payout of the performance grant will occur by March 15, 2011 and is based on the achievement of three performance metrics during 2009 and 2010: return on invested capital, book value per share and total shareholder return relative to that of a peer group of companies. At March 31, 2009, the targeted amount of the grant was $12 million and a liability of $1 million had been accrued for this award.

Note 15. Commitments and Contingencies

Other than the following matters, there have been no significant developments regarding the commitments and contingencies disclosed in Note 23 to the Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2008, nor have any significant new matters arisen during the three months ended March 31, 2009.

Electric Regulation in Virginia

2007 Virginia Regulation Act

Pursuant to the Virginia Electric Utility Restructuring Act (the Regulation Act), the Virginia Commission entered an order in January 2009 initiating reviews of the base rates and terms and conditions of all investor-owned electric utilities in Virginia. Possible outcomes of the 2009 rate review, according to the Regulation Act, include a rate increase, a rate decrease, or a partial refund of 2008 earnings more than 50 basis points above the authorized Return on Equity (ROE).

In March 2009, we submitted our base rate filing and accompanying schedules to the Virginia Commission. Our filing proposed to increase our Virginia jurisdictional base rates by approximately $298 million annually. We also proposed a 12.5% ROE, plus an additional 100 basis point performance incentive pursuant to the Regulation Act based on our generating plant performance, customer service and operating efficiency, resulting in a total ROE request of 13.5%. In April 2009, we submitted a revised filing that corrected certain plant balances. The corrected plant balances and related adjustments reduced our annual revenue requirement by

PAGE 20

approximately $9 million, to approximately $289 million. We proposed that the base rate increase become effective on an interim basis on September 1, 2009, subject to refund and adjustment by the Virginia Commission. The proposed rate increase would increase a typical 1,000 kWh Virginia jurisdictional residential customer’s bill by approximately $6.10 per month.

In March 2009, we filed with the Virginia Commission, pursuant to the Regulation Act, a petition to recover from Virginia jurisdictional customers an annual net increase of approximately $78 million in costs related to FERC-approved transmission charges and PJM demand response programs. This amount also includes a portion of costs discussed further in the RTO Start-up Costs and Administrative Fees section. If approved by the Virginia Commission, the rate adjustment clause would become effective September 1, 2009, and is expected to increase a typical 1,000 kWh Virginia jurisdictional residential customer’s bill by approximately $1.26 per month.

In March 2009, we also filed with the Virginia Commission a revised notice of intent to file a petition for approval of a portfolio of thirteen demand side management (DSM) programs and a related rate adjustment clause on or after July 1, 2009. Our notice stated that, based on current projections and program assumptions, the revenue requirement for the DSM programs for the period January 1, 2010 through December 31, 2010 would be between $20 million and $30 million. If we file for the programs on or about July 1, 2009, by statute the Virginia Commission would have until March 1, 2010 to approve or disapprove of the rate adjustment clause for such programs.

We are unable to predict the outcome of the Virginia Commission’s future rate actions, including actions relating to our 2009 rate review, our recovery of Virginia fuel expenses and our additional rate adjustment clause filings discussed under Utility Generation Expansion below; however an unfavorable outcome could adversely affect our results of operations, financial condition and cash flows.

Virginia Fuel Expenses

In March 2009, we filed our Virginia fuel factor application with the Virginia Commission. The application requested an annual decrease in fuel expense recovery of approximately $236 million for the period July 1, 2009 through June 30, 2010, a decrease from 3.893 cents per kWh to 3.529 cents per kWh. The revised fuel factor includes recovery of approximately $505 million of our previous deferral balance that is eligible for recovery during the 2009 through 2010 fuel factor period pursuant to the fuel factor statute, as amended in 2007. This leaves approximately $23 million of the deferral balance to be collected during the 2010 through 2011 fuel factor period beginning July 1, 2010. If approved by the Virginia Commission, the revised fuel factor would become effective on July 1, 2009 and would decrease the typical 1,000 kWh Virginia jurisdictional residential customer’s average monthly bill by approximately $3.64 for the 2009 through 2010 fuel factor period.

Utility Generation Expansion

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, a 585 Mw (nominal) carbon-capture compatible, clean-coal powered electric generation facility (Virginia City Hybrid Energy Center) located in Wise County, Virginia. In July 2008, the Southern Environmental Law Center, on behalf of four environmental groups, filed a Petition for Appeal of the Final Order with the Supreme Court of Virginia. In April 2009, the Virginia Supreme Court affirmed the Virginia Commission’s Final Order.

In March 2009, we filed with the Virginia Commission our first annual update to the rate adjustment clause for the Virginia City Hybrid Energy Center requesting an increase of approximately $99 million for financing costs to be recovered through rates in 2010. As part of this filing we requested that the 13.5% ROE proposed in our March 31, 2009 base rate filing be applied to the Virginia City Hybrid Energy Center rate adjustment clause, plus the 100 basis point enhancement for construction of a new coal-fired generation facility as previously authorized by the Virginia Commission pursuant to the Regulation Act, for a requested total ROE of 14.5%. If approved by the Virginia Commission, the revised rate adjustment clause has been requested to become effective on January 1, 2010 and would increase a typical 1,000 kWh Virginia jurisdictional residential customer’s bill by $1.78 per month.

In March 2009, the Virginia Commission authorized construction and operation of our proposed Bear Garden facility, a 580 Mw (nominal) natural gas- and oil-fired combined-cycle electric generating facility and associated transmission interconnection facilities in Buckingham County, Virginia, estimated to cost $619 million, excluding financing costs. In March 2009, we also filed a petition with the Virginia Commission for the initiation of a rate adjustment clause for recovery of approximately $77 million in financing costs related to construction of the Bear Garden facility to be recovered through rates in 2010. As part of this filing we requested that the 13.5% ROE proposed in our March 31, 2009 base rate filing be applied to the Bear Garden facility rate adjustment clause, with a

PAGE 21

100 basis point enhancement for construction of a combined-cycle facility, as authorized in the Regulation Act, for a requested total ROE of 14.5%. If approved by the Virginia Commission, the rate adjustment clause has been requested to become effective January 1, 2010 and would increase a typical 1,000 kWh Virginia jurisdictional residential customer’s bill by $1.40 per month.

Regional Transmission Expansion Plan

In June 2006, PJM authorized construction of numerous electric transmission upgrades through 2011, one of which is an approximately 270-mile 500-kilovolt transmission line that begins in southwestern Pennsylvania, crosses West Virginia, and terminates in northern Virginia, of which we will construct approximately 65 miles in Virginia (Meadow Brook-to-Loudoun line) and a subsidiary of Allegheny Energy, Inc. (Trans-Allegheny Interstate Line Company) will construct the remainder. In October 2008, the Virginia Commission authorized construction of the Meadow Brook-to-Loudoun line and affirmed the 65-mile route we proposed for the line which is adjacent to, or within, existing transmission line right-of-ways. The Virginia Commission’s approval of the Meadow Brook-to-Loudoun line was conditioned on the respective state commission approvals of both the West Virginia and Pennsylvania portions of the transmission line. The West Virginia Commission’s approval of Trans-Allegheny Interstate Line Company’s application became effective in February 2009 and the Pennsylvania Commission granted approval in December 2008. In March 2009, the Sierra Club filed an appeal and request for stay of the West Virginia Commission’s approval, which was subsequently denied by the Supreme Court of West Virginia in April 2009. In February 2009, Petitions for Appeal of the Virginia Commission’s approval of the Meadow Brook-to-Loudoun line were filed with the Supreme Court of Virginia by the Piedmont Environmental Council and others. As required by Virginia law, the Virginia Supreme Court issued orders in April 2009, accepting the appeals for rehearing. The Meadow Brook-to-Loudoun line is expected to cost approximately $255 million and is expected to be completed in June 2011.

RTO Start-up Costs and Administrative Fees

In December 2008, FERC approved our electric utility’s Deferral Recovery Charge (DRC) request to become effective January 1, 2009, as requested, which would allow us to recover approximately $153 million of RTO costs that are being deferred due to a statutory rate cap established under Virginia law. However, recovery of RTO costs through the DRC will not commence until the date established by the Virginia Commission that permits us to implement such recovery. In January 2009, requests for rehearing of the FERC order were filed and rehearing is pending. We cannot predict the outcome of the rehearing.

Guarantees

At March 31, 2009, we had issued $417 million of guarantees to support third parties and equity method investees (issued guarantees). This includes $186 million of guarantees to support our investment in a joint venture with Shell WindEnergy Inc. (Shell), which owns a wind-turbine facility in Grant County, West Virginia (NedPower). These NedPower guarantees are primarily comprised of a limited-scope guarantee and indemnification for one-half of the project-level financing for phases one and two of the NedPower wind farm, which would require us to pay 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. This litigation-related 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 this litigation-related guarantee totaled $159 million as of March 31, 2009. Shell has provided an identical guarantee for the other one-half of NedPower’s borrowings.

Issued guarantees also include $176 million of guarantees to support our investment in a joint venture with BP Alternative Energy (BP) 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 was $25 million as of March 31, 2009 and will largely decline during 2009, 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. The Phase One project (300 Mw) achieved full commercial operations in March 2009.

PAGE 22

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, 2009, we had issued the following subsidiary guarantees:


	Stated Limit		Value⁽¹⁾
(millions)
Subsidiary debt⁽²⁾	$	75	$	75
Commodity transactions⁽³⁾		3,001		288
Lease obligation for power generation facility⁽⁴⁾		864		864
Nuclear obligations⁽⁵⁾		433		315
Cove Point LNG facility⁽⁶⁾		770		700
Other		235		135

Total	$	5,378	$	2,377

(1)

Represents the estimated portion of the guarantee’s stated limit that is utilized as of March 31, 2009 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 certain DEI subsidiaries. In the event of default by the subsidiaries, we would be obligated to repay such amounts.

(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 other energy-related commodities and services. If any of 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 Fairless 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 commitments to buy nuclear fuel. Excludes our agreement to provide up to $150 million and $60 million to two DEI subsidiaries, to pay the operating expenses of Millstone power station (Millstone) and Kewaunee power station (Kewaunee), 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.

(6)	Includes a $700 million payment and performance guarantee related to the expansion of our Cove Point LNG facility.

Surety Bonds and Letters of Credit

As of March 31, 2009, we had purchased $163 million of surety bonds and authorized the issuance of standby letters of credit by financial institutions of $351 million to facilitate commercial transactions by our subsidiaries with third parties.

Spent Nuclear Fuel

As discussed in Note 23 to the Consolidated Financial Statements in our Annual Report on Form 10-K, we and certain of our direct and indirect subsidiaries filed lawsuits in the U.S. Court of Federal Claims against the Department of Energy (DOE) requesting damages in connection with its failure to commence accepting spent nuclear fuel. In October 2008, the Court issued an opinion and order for us in the amount of approximately $155 million for our spent fuel-related costs through June 30, 2006, at Surry power station, North Anna power station (North Anna) and Millstone, and judgment was entered by the Court. In December 2008, the government appealed the judgment to the U. S. Court of Appeals for the Federal Circuit and the appeal was docketed. In March 2009, the Federal Circuit granted the government’s request to stay the appeal. With the exception of one case, the Federal Circuit has issued such stays in all other currently pending spent fuel appeals. Once the stay is lifted, briefing on the appeal will take place. Payment of any damages will not occur until the appeal process has been resolved. We cannot predict the outcome of this matter; however, in the event that we recover damages, such recovery, including amounts attributable to joint owners, is not expected to have a material impact on our results of operations. A lawsuit was also filed for Kewaunee, and that lawsuit is presently stayed through September 30, 2009. We will continue to manage our spent fuel until it is accepted by the DOE.

PAGE 23

Note 16. 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, 2009 provision for credit losses, that it is unlikely 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 primarily 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. and Texas. 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 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, 2009, our gross credit exposure totaled $1.7 billion. After the application of collateral, our credit exposure was reduced to approximately $1.1 billion. Of this amount, investment grade counterparties, including those internally rated, represented 97%. Two counterparty exposures are greater than 10% of our total exposure, one representing 30% and the other 11%, both of which are with large financial institutions.

The majority of our derivative instruments contain credit-related contingent provisions. These provisions require us to provide collateral upon the occurrence of specific events, primarily a credit downgrade. If the credit-related contingent features underlying these instruments that are in a liability position and not fully collateralized with cash were fully triggered as of March 31, 2009, we would be required to post an additional $45 million of collateral to our counterparties. The collateral that would be required to be posted includes the impacts of any offsetting asset positions and any amounts already posted for derivatives, non-derivative contracts and derivatives elected under the normal purchases and normal sales exception, per contractual terms. As of March 31, 2009, we have posted $153 million in collateral, including $132 million of letters of credit, related to derivatives with credit-related contingent provisions that are in a liability position and not fully collateralized with cash. The collateral posted includes any amounts paid related to non-derivative contracts and derivatives elected under the normal purchases and normal sales exception, per contractual terms. The aggregate fair value of all derivative instruments with credit-related contingent provisions that are in a liability position and not fully collateralized with cash as of March 31, 2009 is $195 million and does not include the impact of any offsetting asset positions. See Note 10 for further information about our derivative instruments.

Note 17. Employee Benefit Plans

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


	Pension Benefits						Other Postretirement Benefits
Three Months Ended March 31,	2009			2008			2009			2008
(millions)
Service cost	$	26		$	27		$	15		$	13
Interest cost		63			64			25			20
Expected return on plan assets		(101	)		(111	)		(14	)		(16	)
Amortization of prior service cost (credit)		1			1			(2	)		(1	)
Amortization of net loss		9			2			7			1

Net periodic benefit cost (credit)	$	(2	)	$	(17	)	$	31		$	17

PAGE 24

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, if any, 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, 2009. No contributions to our pension plans are currently expected in 2009, but we do expect to contribute approximately $61 million to our other postretirement benefit plans through Voluntary Employees’ Beneficiary Associations (VEBAs) during the remainder of 2009.

Note 18. 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 transmission, distribution and customer service operations, as well as our nonregulated retail energy marketing 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 Appalachian E&P operations. Dominion Energy also includes producer services, which aggregates natural gas supply, engages in natural gas trading and marketing activities and natural gas supply management and provides price risk management services to Dominion affiliates.

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.

Corporate and Other includes our corporate, service company and other functions (including unallocated debt). This segment also includes our regulated gas distribution subsidiaries 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 segments’ performance or allocating resources among the segments and are instead reported in the Corporate and Other segment. In the three months ended March 31, 2009 and 2008, our Corporate and Other segment included $336 million and $16 million, respectively, of after-tax expenses attributable to our operating segments.

•

The expenses in 2009 primarily reflect:

•

A $455 million ($272 million after-tax) ceiling test impairment charge related to the carrying value of our E&P properties, attributable to Dominion Energy; and

•

An $83 million ($50 million after-tax) net loss on investments held in nuclear decommissioning trust funds, attributable to Dominion Generation.

•

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.

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

PAGE 25

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,
2009
Total revenue from external customers	$	989	$	947	$	2,262	$	290		$	290		$	4,778
Intersegment revenue		63		321		66		186			(636	)		—

Total operating revenue		1,052		1,268		2,328		476			(346	)		4,778
Net income (loss)		115		172		369		(408	)		—			248

2008
Total revenue from external customers	$	929	$	898	$	1,932	$	315		$	279		$	4,353
Intersegment revenue		70		352		16		158			(596	)		—

Total operating revenue		999		1,250		1,948		473			(317	)		4,353
Net income		118		182		336		44			—			680

PAGE 26

DOMINION RESOURCES, INC.

ITEM 2. MANAGEMENT’S DISCUSSION AND 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

Our MD&A consists of the following information:

•

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, greenhouse gases and other emissions, 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 the availability of credit and our ability to obtain financing on reasonable terms;

•

Price risk due to marketable 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 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;

•

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 new and evolving capacity models;

PAGE 27

•

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

•

Changes to rates for our regulated electric utility operations, including the outcome of our 2009 rate filings, and the timing of our fuel cost recoveries;

•

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

•

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

•

Completing the divestiture of Peoples and Hope; and

•

Adverse outcomes in litigation matters.

Additionally, other risks that could cause actual results to differ from predicted results are set forth in Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2008.

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, 2009, 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, 2008. 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 Note 3 to our Consolidated Financial Statements for a discussion of newly adopted accounting standards. See Note 9 to our Consolidated Financial Statements for information on our fair value measurements.

Results of Operations

Presented below is a summary of our consolidated results for the quarters ended March 31, 2009 and 2008:


	2009		2008		$ Change
(millions, except EPS)
First Quarter
Net income	$	248	$	680	$	(432	)
Diluted EPS		0.42		1.18		(0.76	)

Overview

Net income decreased by 64% to $248 million. Unfavorable drivers include an impairment charge related to the carrying value of our E&P properties due to declines in gas and oil prices, the absence of a benefit recognized in the first quarter of 2008 from the reversal of deferred tax liabilities associated with the planned sale of Peoples and Hope and higher net losses (net of investment income) on nuclear decommissioning trust investments. Favorable drivers include a higher contribution from our merchant generation operations and the absence of an impairment charge recorded in the first quarter of 2008 related to a DCI investment which was subsequently sold in April 2008.

PAGE 28

Analysis of Consolidated Operations

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


	First Quarter
	2009			2008			$ Change
(millions)
Operating Revenue	$	4,778		$	4,353		$	425
Operating Expenses
Electric fuel and other energy-related purchases		1,141			781			360
Purchased electric capacity		108			107			1
Purchased gas		1,138			1,155			(17	)
Other operations and maintenance		1,250			843			407
Depreciation, depletion and amortization		279			254			25
Other taxes		157			154			3
Other income (loss)		(66	)		(3	)		(63	)
Interest and related charges		224			219			5
Income tax expense		167			157			10

An analysis of our results of operations for the first quarter of 2009 as compared to 2008 follows:

Operating Revenue increased 10% to $4.8 billion, primarily reflecting:

•

A $329 million increase in revenue from our electric utility operations resulting primarily from an increase in fuel revenue largely due to the impact of a comparatively higher fuel rate in certain customer jurisdictions, including the recovery of previously deferred fuel expenses;

•

A $71 million increase for merchant generation operations primarily due to higher sales volumes for fossil operations;

•

A $66 million increase in electricity sales by retail energy marketing operations primarily due to the acquisition of a retail energy marketing business in September 2008;

•

A $40 million increase in our producer services business due to favorable price changes on economic hedging positions ($98 million), partially offset by the net impact of a decrease in prices ($74 million) and an increase in volumes ($16 million), all associated with natural gas aggregation, marketing and trading activities; and

•

A $27 million increase in nonregulated gas sales by our gas distribution operations primarily resulting from an increase in volumes.

These increases were partially offset by:

•

An $86 million decrease in regulated gas sales by our gas distribution operations resulting largely from a decrease in volume due to the migration of customers to energy choice programs; and

•

A $23 million decrease in sales of gas production from our E&P operations primarily reflecting the expiration of fixed-term overriding royalty interests associated with our former volumetric production payment (VPP) agreements.

Operating Expenses and Other Items

Electric fuel and other energy-related purchases expense increased 46% to $1.1 billion, primarily reflecting the combined effects of:

•

A $295 million increase for our utility generation operations primarily reflecting a comparatively higher fuel rate in certain customer jurisdictions including amortization of previously deferred fuel expenses;

•

A $25 million increase from retail energy marketing operations due to increased expenses resulting from the acquisition of a retail energy marketing business ($50 million) partially offset by lower commodity prices ($25 million); and

•

A $19 million increase for our merchant generation operations reflecting increased consumption ($43 million) partially offset by lower commodity prices ($24 million) at certain fossil generation facilities.

PAGE 29

Other operations and maintenance expense increased 48% to $1.3 billion, primarily reflecting the combined effects of:

•

A $455 million ceiling test impairment charge related to the carrying value of our E&P properties due to declines in natural gas and oil prices; partially offset by

•

The absence of a $62 million charge related to the impairment of a DCI investment sold in 2008.

DD&A increased 10% to $279 million, principally due to higher depreciation from property additions and higher amortization due to increased consumption of emissions allowances, partially offset by decreased DD&A reflecting lower gas and oil production at our E&P properties.

Other loss increased to $66 million, primarily due to higher net losses (net of investment income) on our nuclear decommissioning trust investments ($59 million) and a $23 million impairment loss on an equity method investment, partially offset by an increase in earnings from our other equity method investments ($9 million).

Income tax expense increased by 6% to $167 million although pre-tax income decreased by 50%, largely due to the absence of the benefit from 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.

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 our operating segments to net income for the quarters ended March 31, 2009 and 2008:


	Net Income								Diluted EPS
First Quarter	2009			2008		$ Change			2009			2008		$ Change
(millions, except EPS)
DVP	$	115		$	118	$	(3	)	$	0.20		$	0.20	$	—
Dominion Energy		172			182		(10	)		0.29			0.32		(0.03	)
Dominion Generation		369			336		33			0.63			0.58		0.05

Primary operating segments		656			636		20			1.12			1.10		0.02
Corporate and Other		(408	)		44		(452	)		(0.70	)		0.08		(0.78	)

Consolidated	$	248		$	680	$	(432	)	$	0.42		$	1.18	$	(0.76	)

DVP

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


	First Quarter
	2009	2008	% Change
Electricity delivered (million mwhrs)	21.3	20.8	2	%
Degree days (electric distribution service area):
Cooling⁽¹⁾	4	3	33
Heating⁽²⁾	2,163	1,810	20
Average electric distribution customer accounts (thousands)⁽³⁾	2,400	2,380	1
Average retail energy marketing customer accounts (thousands)⁽³⁾	1,631	1,584	3

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

(2)	Heating degree days are units measuring the extent to which the average daily temperature is less than 65 degrees, and are calculated as the difference between 65 degrees and the average temperature for that day.

(3)	Period average.

PAGE 30

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


	First Quarter 2009 vs. 2008 Increase (Decrease)
	Amount			EPS
(millions, except EPS)
Retail energy marketing operations	$	(15	)	$	(0.02	)
Regulated electric sales:
Weather		16			0.03
Customer growth		2			—
Other⁽¹⁾		(7	)		(0.01	)
Other		1			—
Share dilution		—			—

Change in net income contribution	$	(3	)	$	—

(1)	Decrease primarily reflects the impact of unfavorable economic conditions on customer usage, and other factors.

Dominion Energy

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


	First Quarter
	2009		2008		% Change
Gas distribution throughput (bcf):
Sales		21		26	(19	)%
Transportation		84		91	(8	)
Heating degree days (gas distribution service area)		3,151		3,172	(1	)
Average gas distribution customer accounts (thousands)⁽¹⁾:
Sales		341		410	(17	)
Transportation		868		807	8
Production⁽²⁾ (bcfe):		14.4		17.9	(20	)
Average realized prices without hedging results (per mcfe)	$	5.04	$	7.92	(36	)
Average realized prices with hedging results (per mcfe)		7.90		8.80	(10	)
DD&A (unit of production rate per mcfe)		1.90		1.92	(1	)
Average production (lifting) cost⁽³⁾ (per mcfe)		1.24		1.19	4

(1)	Period average.

(2)	Includes natural gas, natural gas liquids and oil. Production includes 2.3 bcfe and 6.3 bcfe for the quarters ended March 31, 2009 and 2008, respectively, 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 $1.11 and $0.91 for the quarters ended March 31, 2009 and 2008, respectively.

PAGE 31

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


	First Quarter 2009 vs. 2008 Increase (Decrease)
	Amount			EPS
(millions, except EPS)
Gas and oil – production⁽¹⁾	$	(19	)	$	(0.03	)
Change in state tax legislation⁽²⁾		(16	)		(0.03	)
Producer services⁽³⁾		26			0.04
Other		(1	)		—
Share dilution		—			(0.01	)

Change in net income contribution	$	(10	)	$	(0.03	)

(1)	Principally due to the expiration of fixed-term overriding royalty interests associated with our former VPP agreements.

(2)	Reflects the absence of a 2008 benefit resulting from the reduction of deferred tax liabilities related to the enactment of West Virginia income tax rate reductions in March 2008.

(3)	Largely due to colder than normal weather throughout the mid-Atlantic and Northeast market areas and the utilization of firm transportation, storage rights and field services optimization.

Included below are the volumes and weighted-average prices associated with hedges in place for our E&P operations as of March 31, 2009, by applicable time period:


	Natural Gas
Year	Hedged Production (bcf)	Average Hedge Price (per mcf)
2009	23.5	$	8.88
2010	14.8		8.62
2011	1.4		7.36

Dominion Generation

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


	First Quarter
	2009	2008	% Change
Electricity supplied (million mwhrs):
Utility	21.3	20.8	2	%
Merchant	12.6	11.3	12
Degree days (electric utility service area):
Cooling	4	3	33
Heating	2,163	1,810	20

PAGE 32

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


	First Quarter 2009 vs. 2008 Increase (Decrease)
	Amount			EPS
(millions, except EPS)
Merchant generation margin⁽¹⁾	$	41		$	0.07
Regulated electric sales:
Weather		28			0.05
Rate adjustment clause⁽²⁾		14			0.02
Customer growth		3			—
Other⁽³⁾		(27	)		(0.04	)
Sales of emissions allowances		(7	)		(0.01	)
Depreciation and amortization		(12	)		(0.02	)
Other		(7	)		(0.01	)
Share dilution		—			(0.01	)

Change in net income contribution	$	33		$	0.05

(1)	Primarily attributable to higher volumes at certain fossil generation facilities.

(2)	Reflects the impact of a new rate adjustment clause associated with the recovery of financing costs for the Virginia City Hybrid Energy Center.

(3)	Decrease reflects the impact of unfavorable economic conditions on customer usage and other factors, as well as lower sales to wholesale customers.

Corporate and Other

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


	First Quarter
	2009			2008			$ Change
(millions, except EPS)
Specific items attributable to operating segments	$	(336	)	$	(16	)	$	(320	)
Peoples and Hope		26			31			(5	)
Other corporate operations		(98	)		29			(127	)

Total net benefit (expense)	$	(408	)	$	44		$	(452	)

EPS impact	$	(0.70	)	$	0.08		$	(0.78	)

Specific Items Attributable to Operating Segments

Corporate and Other includes specific items attributable to our operating segments that have been excluded from profit measures evaluated by management, either in assessing segment performance or in allocating resources among the segments. See Note 18 to our Consolidated Financial Statements for discussion of significant items.

Other Corporate Operations

Net expenses associated with other corporate operations were $98 million in 2009, as compared to a net benefit of $29 million in 2008, primarily due to a $28 million increase in our consolidating interim income tax provision, reflecting the estimated annual effective tax rate for our combined segments and the absence of the following items:

•

The reversal of $136 million of deferred tax liabilities associated with Peoples and Hope in the first quarter of 2008; partially offset by

•

A $38 million after-tax impairment charge recorded in the first quarter of 2008 related to a DCI investment that was subsequently 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, 2008 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.

PAGE 33

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, 2009 follows:


	Amount
(millions)
Net unrealized gain at December 31, 2008	$	43
Contracts realized or otherwise settled during the period		(38	)
Net unrealized gain at inception of contracts initiated during the period		—
Change in unrealized gains and losses		6
Changes in unrealized gains and losses attributable to changes in valuation techniques		—

Net unrealized gain at March 31, 2009	$	11

The fair values and categorization summarized below were determined in accordance with the requirements of 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, 2009, 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⁾	$	7		$	—		$	—	$	—	$	—	$	7
Other external sources – Level 2⁽²⁾		3			2			—		—		—		5
Models and other valuation methods – Level 3⁽³⁾		(2	)		(1	)		2		—		—		(1	)

Total	$	8		$	1		$	2	$	—	$	—	$	11

(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, 2009, we had $3.3 billion of unused capacity under our credit facilities.

A summary of our cash flows for the three months ended March 31, 2009 and 2008 is presented below:


	2009			2008
(millions)
Cash and cash equivalents at January 1,⁽¹⁾	$	71		$	287
Cash flows provided by (used in):
Operating activities		1,477			551
Investing activities		(874	)		(718	)
Financing activities		(527	)		(35	)

Net increase (decrease) in cash and cash equivalents		76			(202	)

Cash and cash equivalents at March 31,⁽²⁾	$	147		$	85

(1)	2009 and 2008 amounts include $5 million and $4 million, respectively, of cash classified as held for sale in our Consolidated Balance Sheets.

(2)	2009 and 2008 amounts include $6 million of cash classified as held for sale in our Consolidated Balance Sheets.

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Operating Cash Flows

For the three months ended March 31, 2009, net cash provided by operating activities increased by $926 million as compared to the three months ended March 31, 2008. The increase was due to favorable changes in working capital, higher cash contributions from our merchant generation business, lower collateral requirements related to commodity hedging activities, higher electric utility sales due to an increase in heating degree days and a positive impact from deferred fuel cost recoveries in our Virginia jurisdiction. 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 our Annual Report on Form 10-K for the year-ended December 31, 2008.

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, 2009, 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⁾	$	1,530	$	551	$	979
Non-investment grade⁽²⁾		12		—		12
No external ratings:
Internally rated—investment grade⁽³⁾		114		—		114
Internally rated—non-investment grade⁽⁴⁾		25		—		25

Total	$	1,681	$	551	$	1,130

(1)	Designations as investment grade are based upon minimum credit ratings assigned by Moody’s and Standard & Poor’s. The five largest counterparty exposures, combined, for this category represented approximately 56% of the total net credit exposure.

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

(3)	The five largest counterparty exposures, combined, for this category represented approximately 7% of the total net credit exposure.

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

Investing Cash Flows

For the three months ended March 31, 2009, net cash used in investing activities increased by $156 million as compared to the three months ended March 31, 2008, primarily due to an increase in capital expenditures related to our electric utility operations.

Financing Cash Flows and Liquidity

We rely on banks and capital markets as significant sources 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 Commission.

For the three months ended March 31, 2009, net cash used in financing activities increased by $492 million as compared to the three months ended March 31, 2008, primarily due to net repayments of short-term debt as compared to net issuances in 2008, partially offset by lower repayments of long-term debt and increased proceeds from common stock issuances.

See Note 13 to our Consolidated Financial Statements for further information regarding our credit facilities, liquidity and significant financing transactions.

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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, 2008, 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. As of March 31, 2009, there have been no changes in our credit ratings, nor have there been any changes to or events of default under our debt covenants. In April 2009, Moody’s revised its credit ratings outlook for Virginia Power to positive from stable.

Future Cash Payments for Contractual Obligations and Planned Capital Expenditures

As of March 31, 2009, 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, 2008.

Use of Off-Balance Sheet Arrangements

As of March 31, 2009, 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, 2008.

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 Item 1. Business and Future Issues and Other Matters in MD&A in our Annual Report on Form 10-K for the year ended December 31, 2008. In addition, see Note 15 to our Consolidated Financial Statements and Part II, Item 1. Legal Proceedings for additional information on various environmental, regulatory, legal and other matters that may impact our future results of operations and/or financial condition, including a discussion of electric regulation in Virginia.

Regulatory Approval of Sale of Peoples and Hope

In September 2008, Peoples, Dominion and a subsidiary of BBIFNA (the BBIFNA subsidiary) filed a joint petition with the Pennsylvania Commission seeking approval of the purchase by the subsidiary of BBIFNA of all of the stock of Peoples. In February and March 2009, we made a joint request with the BBIFNA subsidiary to the Pennsylvania Commission for a temporary suspension in the sale approval proceeding pending a potential change in the ownership structure of BBIFNA. Such proceeding has been temporarily suspended and is expected to resume in May or June 2009. In October 2008, Hope, Dominion and the BBIFNA subsidiary filed a joint petition seeking West Virginia Commission approval of the purchase by the BBIFNA subsidiary of all of the stock of Hope. In September 2008, Dominion and BBIFNA each filed a Premerger Notification and Report Form with the U.S. Department of Justice and the Federal Trade Commission under the Hart-Scott-Rodino Antitrust Improvements Act (HSR Act). In October 2008, the waiting period under the HSR Act related to the proposed sale of Peoples and Hope to the BBIFNA subsidiary expired. The transaction is expected to close in 2009, subject to state regulatory approvals in Pennsylvania and West Virginia as well as clearance under the Exon-Florio provision of the Omnibus Trade and Competitiveness Act.

Cove Point Expansion

In 2006, FERC approved the proposed expansion of our Cove Point terminal and DTI pipeline and the commencement of construction of such project. Such expansion included the installation of two new LNG storage tanks at our Cove Point terminal, each capable of storing 160,000 cubic meters of LNG, and expansion of our Cove Point pipeline to approximately 1.8 million dekatherms per day. In addition, we expanded our DTI gas pipeline and storage system by building 81 miles of pipeline, two compressor stations in Pennsylvania and other upgrades. The DTI facilities associated with the Cove Point expansion project were placed into service in December 2008, the Cove Point LNG terminal expansion was placed into service in January 2009 and the remainder of the expanded Cove Point facilities were placed into commercial service in March 2009. In March 2009, Washington Gas Light Company filed an appeal with the U.S. Court of Appeals for the District of Columbia requesting a review of FERC’s orders approving the Cove Point expansion.

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Wind Power Project

In January 2008, we acquired a 50% interest in a joint venture with BP to develop Fowler Ridge. The first phase consisting of 300 Mw achieved full commercial operations in March 2009. We have a long-term agreement with the joint venture to purchase 200 Mw of energy, capacity and environmental attributes from this first phase. We are currently in discussions with BP regarding development of the final 350 Mw phase. BP has developed an additional 100 Mw facility in which Dominion does not have an ownership interest.

North Anna Power Station

In January 2008, the NRC accepted and deemed complete our application for a Combined Construction Permit and Operating License (COL) that references a specific reactor design and which would allow us to build and operate a new nuclear unit at North Anna. In December 2008, we terminated a long-lead agreement with our vendor with respect to the reactor design identified in our COL application and certain related equipment. In March 2009, we commenced a competitive process to determine if vendors can provide an advanced technology reactor that could be licensed and built under terms acceptable to us. If, as a result of this process, we choose a different reactor design, we will amend our COL application, as necessary. We have not yet committed to building a new nuclear unit.

Collective Bargaining Agreement

The contract between Dominion and the Utility Workers’ Union of America, United Gas Workers’ Local G-555, AFL-CIO (Local G-555) will expire on June 15, 2009. The parties began negotiations in April 2009. Local G-555 represents about 1,200 employees in Ohio.

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.

Clean Water Act Compliance

In April 2008, the U.S. Supreme Court granted an industry request to review the question of whether Section 316b of the Clean Water Act authorizes the Environmental Protection Agency (EPA) to compare costs with benefits in determining the best technology available for minimizing “adverse environmental impact” at cooling water intake structures. The U.S. Supreme Court ruled in April 2009 that the EPA has the authority to consider costs versus environmental benefits in selecting best technology available for reducing impacts of cooling water intakes at power stations. It is currently unknown how the EPA will interpret the ruling in their ongoing rulemaking activity addressing cooling water intakes as well as how the states will implement this decision. We have sixteen facilities that are likely to be subject to these regulations. We cannot predict the outcome of the EPA and state regulatory processes, nor can we determine with any certainty what specific controls may be required.

In August 2006, the Connecticut Department of Environmental Protection (CTDEP) issued a notice of a Tentative Determination to renew our Millstone power station’s National Pollutant Discharge Elimination System permit, which included a draft copy of the revised permit. In October 2007, CTDEP issued a report to the hearing officer for the tentative determination stating the agency’s intent to further revise the draft permit. In December 2007, the CTDEP issued a new draft permit. An administrative hearing on the draft permit began in January 2009 and was completed in February 2009, with a Final Determination expected to be issued by the CTDEP later in 2009. Until the final permit is reissued, it is not possible to predict any financial impact that may result.

In October 2007, the Virginia State Water Control Board (Water Board) issued a renewed water discharge (VPDES) permit for North Anna. The Blue Ridge Environmental Defense League, and other persons, appealed the Water Board’s decision to the Richmond Circuit Court, challenging several permit provisions related to North Anna’s discharge of cooling water. In February 2009, the court remanded the permit to the Water Board for further review on a single issue regarding regulation of the thermal discharge from North Anna into the waste heat treatment facility. Once the court signs the final order, unless a stay of the order is issued, North Anna would operate pursuant to the previous VPDES permit until the Water Board reissues the permit or the court of appeals reverses the circuit court’s decision. We intend to appeal the court’s decision and ask for a stay of the court’s order. As a first step, we filed a motion for reconsideration with the court in February 2009 because one of the federal court cases the judge relied upon was recently overturned by the Fourth Circuit U.S. Court of Appeals. That motion is still pending. Until the final permit is reissued, it is not possible to predict any financial impact that may result.

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Global Climate Change

In April 2007, the U.S. Supreme Court ruled that the EPA has the authority to regulate greenhouse gas emissions, which could result in future EPA action. In April 2009, the EPA issued a proposed finding for new motor vehicles and motor vehicle engines that greenhouse gases may endanger public health or welfare. The proposed finding, which now moves to a public comment period, identified six greenhouse gases that pose a potential threat. The EPA has stated that the proposed finding, as well as any final finding that is made in the future, would not itself impose any requirements on industry or other entities. 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 emission reduction programs on our operations or our customers at this time.

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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 investment price risk through various portfolios of equity and debt securities.

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

Commodity Price Risk

To manage price risk, we primarily hold commodity-based financial derivative instruments held for non-trading purposes associated with purchases and sales of electricity, natural gas and 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 $160 million and $236 million as of March 31, 2009 and December 31, 2008, respectively. The decline in sensitivity is primarily due to a decrease in electricity prices. A hypothetical 10% unfavorable change in commodity prices would have resulted in a decrease of approximately $2 million and $5 million in the fair value of our commodity-based financial derivative instruments held for trading purposes as of March 31, 2009 and December 31, 2008, 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 physical sales of the commodity.

Interest Rate Risk

We manage our interest rate risk exposure predominantly by maintaining a balance of fixed and variable rate debt. We may also enter into interest-rate swaps when deemed appropriate to adjust our exposure based upon market conditions. At March 31, 2009 and December 31, 2008, a hypothetical 10% increase in market interest rates would have resulted in a decrease in annual earnings of approximately $3 million and $4 million, respectively.

Additionally, we may use forward-starting interest-rate swaps and treasury rate locks as anticipatory hedges. At March 31, 2009, we had $2.6 billion in aggregate notional amounts of these interest-rate derivatives outstanding. A hypothetical 10% decrease in market interest rates would have resulted in a decrease of approximately $74 million in the fair value of these interest-rate derivatives at March 31, 2009. We did not have a significant amount of these interest-rate derivatives outstanding at December 31, 2008.

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The impact of a change in market interest rates on these anticipatory hedges at a point in time is not necessarily representative of the results that will be realized when such contracts are settled. Net losses from interest-rate derivatives used for anticipatory hedging purposes, to the extent realized, will generally be amortized over the life of the respective debt issuance being hedged.

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.

We recognized net realized losses (net of investment income) on nuclear decommissioning trust investments of $138 million, $20 million and $192 million for the three months ended March 31, 2009 and 2008 and for the year ended December 31, 2008, respectively. Net realized losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. For the three months ended March 31, 2009, we recorded, in AOCI and regulatory liabilities, an increase in unrealized gains on these investments of $32 million. For the three months ended March 31, 2008 and for the year ended December 31, 2008, we recorded, in AOCI and regulatory liabilities, a reduction in unrealized gains on these investments of $129 million and $451 million, respectively.

We sponsor employee pension and other postretirement benefit plans, in which our employees participate, that hold investments in trusts to fund benefit payments. Investment-related declines in these trusts will result in future increases in the periodic cost recognized for such employee benefit plans and will be included in the determination of the amount of cash to be contributed to the employee benefit plans.

ITEM 4. CONTROLS AND PROCEDURES

Senior management, including our CEO and 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 February 2008, we received a request for information pursuant to Section 114 of the Clean Air Act from the EPA. The request concerns historical operating changes and capital improvements undertaken at our State Line and Kincaid power stations. In April 2009, we received a second request for information. We provided information in response to the first request and are in the process of gathering and compiling the information needed to respond to the second request. Also in April, we received a Notice and Finding of Violations from the EPA claiming new source review violations, new source performance standards violations, and Title V permit program violations pursuant to the Clean Air Act and the respective State Implementation Plans. We are evaluating the impact of the Notice and cannot estimate the financial impact of any adverse outcome at this time.

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, 2008, which should be taken into consideration when reviewing the information contained in this report. There have been no material changes with regard to the risk factors previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2008. 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.

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

Following is information on unregistered sales of 76,000 shares of Dominion common stock for aggregate consideration of $2.1 million during the first quarter of 2009. These shares were issued to officers and directors of the Company under a private placement exempt from registration pursuant to Section 4(2) of the Securities Act of 1933.


Date of Sale	# of Shares	Price per Share
3/3/09	10,000	$	28.42
3/4/09	30,000	$	28.23
3/5/09	36,000	$	27.88
Total	76,000

In February 2009, we issued approximately 1.6 million shares of common stock to an existing holder of our senior notes, in a privately negotiated transaction, in exchange for approximately $56 million of the principal of two series of our outstanding senior notes, which were retired. The transaction was exempt from registration pursuant to Section 3(a)(9) of the Securities Act and no commission or remuneration was paid in connection with the exchange.

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
1/1/09-1/31/09	55	$	35.84	N/A	53,971,148 shares/ $2.68 billion
2/1/09-2/28/09	29,707		33.63	N/A	53,971,148 shares/ $2.68 billion
3/1/09-3/31/09	815		30.18	N/A	53,971,148 shares/ $2.68 billion
Total	30,577	$	33.54	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		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.

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).

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

April 30, 2009		/s/ Thomas P. Wohlfarth
		Thomas P. Wohlfarth
		Senior Vice President and Chief Accounting Officer

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