Edgar Filing: DOMINION RESOURCES INC /VA/

Dominion Resources Inc. 1Q06 10Q

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, 2006

____ 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

DOMINION RESOURCES, INC.

(Exact name of registrant as specified in its charter)

VIRGINIA (State or other jurisdiction of incorporation or organization)	54-1229715 (I.R.S. Employer Identification No.)

120 TREDEGAR STREET RICHMOND, VIRGINIA (Address of principal executive offices)	23219 (Zip Code)

(804) 819-2000 (Registrant's telephone number)

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

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

Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨

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, 2006, the latest practicable date for determination, 347,542,012 shares of common stock, without par value, of the registrant were outstanding.

PAGE 2

DOMINION RESOURCES, INC.

INDEX

		Page Number
PART I. Financial Information
Item 1.	Consolidated Financial Statements
	Consolidated Statements of Income - Three Months Ended March 31, 2006 and 2005	3
	Consolidated Balance Sheets - March 31, 2006 and December 31, 2005	4
	Consolidated Statements of Cash Flows - Three Months Ended March 31, 2006 and 2005	6
	Notes to Consolidated Financial Statements	7
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	23
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	36
Item 4.	Controls and Procedures	38
	PART II. Other Information
Item 1.	Legal Proceedings	39
Item 1A.	Risk Factors	40
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	42
Item 4.	Submission of Matters to a Vote of Security Holders	43
Item 6.	Exhibits	45

PAGE 3

DOMINION RESOURCES, INC.

PART I. FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended March 31,
	2006	2005
	(millions, except per share amounts)
Operating Revenue	$4,957	$4,736

Operating Expenses
Electric fuel and energy purchases	766	841
Purchased electric capacity	123	134
Purchased gas	1,378	1,222
Other energy-related commodity purchases	400	324
Other operations and maintenance	768	831
Depreciation, depletion and amortization	381	346
Other taxes	181	165
Total operating expenses	3,997	3,863

Income from operations	960	873

Other income	43	51

Interest and related charges:
Interest expense	234	217
Interest expense - junior subordinated notes payable to affiliated trusts	27	26
Subsidiary preferred dividends	4	4
Total interest and related charges	265	247

Income before income tax expense	738	677
Income tax expense	204	248

Net Income	$ 534	$ 429

Earnings Per Common Share - Basic	$1.54	$1.26

Earnings Per Common Share - Diluted	$1.53	$1.25

Dividends paid per common share	$0.69	$0.67

____________

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

PAGE 4

DOMINION RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

ASSETS	March 31, 2006	December 31, 2005⁽¹⁾
	(millions)
Current Assets
Cash and cash equivalents	$ 69	$ 146
Accounts receivable:
Customer (less allowance for doubtful accounts of $24 and $38)	2,646	3,335
Other (less allowance for doubtful accounts of $9 at both dates)	263	226
Inventories	888	1,167
Derivative assets	2,483	3,429
Deferred income taxes	639	928
Assets held for sale	1,172	4
Other	847	894
Total current assets	9,007	10,129

Investments
Nuclear decommissioning trust funds	2,597	2,534
Available for sale securities	287	287
Other	677	680
Total investments	3,561	3,501

Property, Plant and Equipment
Property, plant and equipment	41,890	42,063
Accumulated depreciation, depletion and amortization	(13,065)	(13,123)
Total property, plant and equipment, net	28,825	28,940

Deferred Charges and Other Assets
Goodwill	4,298	4,298
Prepaid pension cost	1,894	1,915
Derivative assets	1,296	1,915
Regulatory assets	459	758
Other	1,204	1,204
Total deferred charges and other assets	9,151	10,090
Total assets	$50,544	$52,660

____________

(1)	The Consolidated Balance Sheet at December 31, 2005 has been derived from the audited Consolidated Financial Statements at that date.

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

PAGE 5

DOMINION RESOURCES, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

LIABILITIES AND SHAREHOLDERS' EQUITY	March 31, 2006	December 31, 2005⁽¹⁾
	(millions)
Current Liabilities
Securities due within one year	$ 2,378	$ 2,330
Short-term debt	1,403	1,618
Accounts payable	1,953	2,756
Accrued interest, payroll and taxes	639	694
Derivative liabilities	4,369	6,087
Liabilities held for sale	459	--
Other	842	995
Total current liabilities	12,043	14,480

Long-Term Debt
Long-term debt	13,617	13,237
Junior subordinated notes payable to affiliated trusts	1,398	1,416
Total long-term debt	15,015	14,653

Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits	5,129	4,984
Asset retirement obligations	2,246	2,249
Derivative liabilities	2,751	3,971
Regulatory liabilities	589	607
Other	1,073	1,062
Total deferred credits and other liabilities	11,788	12,873
Total liabilities	38,846	42,006

Commitments and Contingencies (see Note 16)

Subsidiary Preferred Stock Not Subject to Mandatory Redemption	257	257

Common Shareholders' Equity
Common stock - no par⁽²⁾	11,295	11,286
Other paid-in capital	127	125
Retained earnings	1,844	1,550
Accumulated other comprehensive loss	(1,825)	(2,564)
Total common shareholders’ equity	11,441	10,397
Total liabilities and shareholders’ equity	$50,544	$52,660

____________

⁽¹⁾ The Consolidated Balance Sheet at December 31, 2005 has been derived from the audited Consolidated Financial Statements at that date.

⁽²⁾ 500 million shares authorized; 348 million shares outstanding at March 31, 2006 and 347 million shares outstanding at December 31, 2005.

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

PAGE 6

DOMINION RESOURCES, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2006	2005
	(millions)
Operating Activities
Net income	$ 534	$ 429
Adjustments to reconcile net income to net cash provided by operating activities:
Net realized and unrealized derivative (gains)/losses	(241)	54
Depreciation, depletion and amortization	414	380
Deferred income taxes and investment tax credits, net	187	70
Charges related to pending sale of gas distribution subsidiaries	172	--
Other adjustments to net income	(49)	19
Changes in:
Accounts receivable	412	(126)
Inventories	262	287
Deferred fuel and purchased gas costs, net	125	100
Accounts payable, trade	(659)	(142)
Accrued interest, payroll and taxes	(22)	145
Deferred revenues	(79)	(76)
Margin deposit assets and liabilities	(206)	(172)
Other operating assets and liabilities	134	271
Net cash provided by operating activities	984	1,239

Investing Activities
Plant construction and other property additions	(439)	(363)
Additions to gas and oil properties, including acquisitions	(484)	(377)
Proceeds from sale of gas and oil properties	--	580
Acquisition of businesses, net of cash acquired	(91)	(642)
Proceeds from sale of securities	273	126
Purchases of securities	(281)	(350)
Other	36	68
Net cash used in investing activities	(986)	(958)

Financing Activities
Issuance (repayment) of short-term debt, net	(215)	376
Issuance of long-term debt	1,000	--
Repayment of long-term debt	(609)	(462)
Issuance of common stock	3	216
Repurchase of common stock	--	(247)
Common dividend payments	(240)	(230)
Other	(10)	(24)
Net cash used in financing activities	(71)	(371)

Decrease in cash and cash equivalents	(73)	(90)
Cash and cash equivalents at beginning of period	146	361
Cash and cash equivalents at end of period⁽¹⁾	$ 73	$ 271

Noncash Financing Activities
Exchange of debt securities	$330	--
Issuance of long-term debt and establishment of trust	47	--
Assumption of debt related to acquisition of non-utility generating facility	--	$62

____________

(1)	2006 amount includes $4 million of cash classified as held for sale on the Consolidated Balance Sheet

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

PAGE 7

DOMINION RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1. Nature of Operations

Dominion Resources, Inc. (Dominion) is a fully integrated gas and electric holding company headquartered in Richmond, Virginia. Our principal subsidiaries are Virginia Electric and Power Company (Virginia Power), Consolidated Natural Gas Company (CNG), Dominion Energy, Inc. (DEI) and Virginia Power Energy Marketing, Inc. (VPEM).

Virginia Power is a regulated public utility that generates, transmits and distributes electricity within an area of approximately 30,000 square miles in Virginia and northeastern North Carolina. Virginia Power serves approximately 2.3 million retail customer accounts, including governmental agencies and wholesale customers such as rural electric cooperatives and municipalities. On May 1, 2005, Virginia Power became a member of PJM Interconnection, LLC (PJM), a regional transmission organization (RTO). As a result, Virginia Power integrated its control area into the PJM energy markets.

CNG operates in all phases of the natural gas business, explores for and produces gas and oil and provides a variety of energy marketing services. Its regulated gas distribution subsidiaries serve approximately 1.7 million residential, commercial and industrial gas sales and transportation customer accounts in Ohio, Pennsylvania and West Virginia and its nonregulated retail energy marketing businesses serve approximately 1.2 million residential and commercial customer accounts in the Northeast, Mid-Atlantic and Midwest. CNG also operates an interstate gas transmission pipeline system and underground natural gas storage system in the Northeast, Mid-Atlantic and Midwest and a liquefied natural gas (LNG) import and storage facility in Maryland. Its producer services operations involve the aggregation of natural gas supply and related wholesale activities. CNG’s exploration and production operations are located in several major gas and oil producing basins in the United States, both onshore and offshore.

DEI is involved in merchant generation, energy marketing and price risk management activities and natural gas and oil exploration and production.

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

We have substantially exited the core operating businesses of Dominion Capital, Inc. (DCI) whose primary business was financial services, including loan administration, commercial lending and residential mortgage lending.

We manage our daily operations through four primary operating segments: Dominion Delivery, Dominion Energy, Dominion Generation and Dominion Exploration & Production (E&P). In addition, we report a Corporate segment that includes our corporate, service company and other functions. Our assets remain wholly owned by our legal subsidiaries.

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

Note 2. Significant Accounting Policies

As permitted by the rules and regulations of the Securities and Exchange Commission (SEC), our accompanying unaudited Consolidated Financial Statements contain certain condensed financial information and exclude certain footnote disclosures normally included in annual audited consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). These unaudited Consolidated Financial Statements should be read in conjunction with our Consolidated Financial Statements and Notes in our Annual Report on Form 10-K for the year ended December 31, 2005.

In our opinion, the accompanying unaudited Consolidated Financial Statements contain all adjustments, including normal recurring accruals, necessary to present fairly our financial position as of March 31, 2006, and our results of operations and cash flows for the three months ended March 31, 2006 and 2005.

PAGE 8

DOMINION RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

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, the accounts of Dominion and all majority-owned subsidiaries, and those variable interest entities (VIEs) where Dominion has been determined to be the primary beneficiary.

We report certain contracts and instruments at fair value in accordance with GAAP. Market pricing and indicative price information from external sources are used to measure fair value when available. In the absence of this information, we estimate fair value based on near-term and historical price information and statistical methods. For individual contracts, the use of differing assumptions could have a material effect on the contract’s estimated fair value. See Note 2 to our Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2005 for a more detailed discussion of our estimation techniques.

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

Certain amounts in our 2005 Consolidated Financial Statements and Notes have been reclassified to conform to the 2006 presentation.

Note 3. Newly Adopted Accounting Standards

SFAS No. 123R

Effective January 1, 2006, we adopted Statement of Financial Accounting Standards (SFAS) No. 123 (revised 2004), Share-Based Payment (SFAS No. 123R), which requires that compensation expense relating to share-based payment transactions be recognized in the financial statements based on the fair value of the equity or liability instruments issued. SFAS No. 123R covers a wide range of share plans, performance-based awards, share appreciation rights and employee share purchase plans. We adopted SFAS No. 123R using the modified prospective application transition method. Under this transition method, compensation cost is recognized (a) based on the requirements of SFAS No. 123R for all share-based awards granted subsequent to January 1, 2006 and (b) based on the original provisions of SFAS No. 123, Accounting for Stock-Based Compensation, for all awards granted prior to January 1, 2006, but not vested as of that date. Results for prior periods will not be restated.

Prior to January 1, 2006, we accounted for our stock-based compensation plans under the measurement and recognition provisions of Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. Under this method, stock option awards generally did not result in compensation expense since their exercise price was typically equal to the market price of our common stock on the date of grant. Accordingly, stock-based compensation expense was included as a pro forma disclosure in the footnotes to our financial statements.

The following table illustrates the pro forma effect on net income and earnings per share (EPS) for the three months ended March 31, 2005, if we had applied the fair value recognition provisions of SFAS No. 123 to stock-based employee compensation:

	Three Months Ended March 31, 2005
	(millions)
Net income, as reported	$429
Add: actual stock-based compensation expense, net of tax	3
Deduct: pro forma stock-based compensation expense, net of tax	(3)
Net income, pro forma	$429

Basic EPS - as reported	$1.26
Basic EPS - pro forma	$1.26

Diluted EPS - as reported	$1.25
Diluted EPS - pro forma	$1.25

PAGE 9

DOMINION RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Prior to the adoption of SFAS No. 123R, we presented the benefits of tax deductions resulting from the exercise of stock-based compensation as an operating cash flow in our Consolidated Statements of Cash Flows. SFAS No. 123R requires the benefits of tax deductions in excess of the compensation cost recognized for stock-based compensation (excess tax benefits) to be classified as a financing cash flow. Excess tax benefits of approximately $1 million were realized for the three months ended March 31, 2006.

Restricted stock awards granted prior to January 1, 2006 contain terms that accelerate vesting upon retirement. Our previous practice was to recognize compensation cost for these awards over the stated vesting term unless vesting was actually accelerated by retirement. Following our adoption of SFAS No. 123R, we continue to recognize compensation cost over the stated vesting term for existing restricted stock awards, but are now required to recognize compensation cost over the shorter of the stated vesting term or period from the date of grant to the date of retirement eligibility for newly issued or modified restricted stock awards with similar terms. In the three months ended March 31, 2006, we recognized approximately $1 million of compensation cost related to awards previously granted to retirement eligible employees. At March 31, 2006 unrecognized compensation cost for restricted stock awards held by retirement eligible employees totaled $8 million.

Note 4. Recently Issued Accounting Standards

SFAS No. 155

In February 2006, the Financial Accounting Standards Board (FASB) issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments. SFAS No. 155 permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that would otherwise require bifurcation. We will adopt the provisions of this standard prospectively beginning January 1, 2007 and do not expect the adoption to have a material impact on our results of operations and financial condition.

EITF 04-13

We enter into buy/sell and related agreements primarily as a means to reposition our offshore Gulf of Mexico crude oil production to more liquid marketing locations onshore. We typically enter into either a single or a series of buy/sell transactions in which we sell our crude oil production at the offshore field delivery point and buy similar quantities at Cushing, Oklahoma for sale to third parties. We are able to enhance profitability by selling to a wide array of refiners and/or trading companies at Cushing, one of the largest crude oil markets in the world, versus restricting sales to a limited number of refinery purchasers in the Gulf of Mexico.

Under the primary guidance of Emerging Issue Task Force (EITF) Issue No. 99-19, Reporting Revenue Gross as a Principal versus Net as an Agent, we present the sales and purchases related to our crude oil buy/sell arrangements on a gross basis in our Consolidated Statements of Income. These transactions require physical delivery of the crude oil and the risks and rewards of ownership are evidenced by title transfer, assumption of environmental risk, transportation scheduling and counterparty nonperformance risk. Sale activity included in operating revenue was $232 million and $93 million for the three months ended March 31, 2006 and 2005, respectively. Purchase activity included in other energy-related commodity purchases expense was $224 million and $89 million for the three months ended March 31, 2006 and 2005, respectively.

In September 2005, the FASB ratified the EITF’s consensus on Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty, that will require buy/sell and related agreements to be presented on a net basis in the Consolidated Statements of Income if they are entered into in contemplation of one another. This new guidance is required to be applied to all new arrangements entered into, and modifications or renewals of existing arrangements, beginning April 1, 2006. We adopted EITF 04-13 on April 1, 2006, and as a result, a portion of our future activity related to buy/sell arrangements will be presented on a net basis in our Consolidated Statements of Income; however, there will be no impact on our results of operations or cash flows.

Note 5. Acquisition

In February 2006, we completed the acquisition of Pablo Energy LLC (Pablo) for approximately $92 million in cash. Pablo holds producing and other properties located in the Texas Panhandle area. The operations of Pablo are included in our Dominion E&P operating segment.

PAGE 10

DOMINION RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Note 6. Sale of Regulated Gas Distribution Subsidiaries

On March 1, 2006, we entered into an agreement with Equitable Resources, Inc., to sell two of our wholly-owned regulated gas distribution subsidiaries, The Peoples Natural Gas Company (Peoples) and Hope Gas, Inc. (Hope), for approximately $970 million plus adjustments to reflect capital expenditures and changes in working capital. Peoples and Hope serve approximately 500,000 customer accounts in Pennsylvania and West Virginia. The transaction is expected to close by the first quarter of 2007, subject to state regulatory approvals in Pennsylvania and West Virginia, as well as approval under the federal Hart-Scott-Rodino Act. The carrying amounts of the major classes of assets and liabilities classified as held for sale in our Consolidated Balance Sheet are as follows:

	March 31, 2006
	(millions)
ASSETS

Current Assets
Cash	$ 4
Customer accounts receivable	243
Unrecovered gas costs	59
Other	32
Total current assets	338

Property, Plant and Equipment
Property, plant and equipment	1,100
Accumulated depreciation, depletion and amortization	(385)
Total property, plant and equipment, net	715

Deferred Charges and Other Assets
Regulatory assets	107
Other	8
Total deferred charges and other assets	115

Assets held for sale	$1,168

LIABILITIES

Current Liabilities
Accounts payable, trade	$ 61
Provision for gas inventory replacement	52
Payables to affiliates	30
Accrued taxes	26
Deferred income taxes	24
Other	37
Total current liabilities	230

Deferred Credits and Other Liabilities
Asset retirement obligations	32
Deferred income taxes	160
Regulatory liabilities	26
Other	11
Total deferred credits and other liabilities	229

Liabilities held for sale	$ 459

PAGE 11

DOMINION RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

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

	Three Months Ended March 31,
	2006	2005
	(millions)
Operating Revenue	$357	$316

Income (loss) before income taxes	(128)	45

In March 2006, we recognized a $159 million ($94 million after-tax) charge, recorded in other operations and maintenance expense in our Consolidated Statements of Income, resulting from the write-off of certain regulatory assets related to the pending sale of Peoples and Hope, since the recovery of those regulatory assets is no longer probable. We also established $141 million of deferred tax liabilities on our Consolidated Balance Sheet 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. EITF 93-17 requires that the deferred tax impact of the excess of financial reporting basis over the tax basis of a parent’s investment in a subsidiary be recognized when it is apparent that the temporary difference will reverse in the foreseeable future. We recorded an adjustment since the financial reporting basis of our investment in Peoples and Hope exceeded our tax basis. This temporary difference and related deferred taxes will reverse and will partially offset current tax expense recognized upon closing of the sale.

EITF Issue No. 03-13, Applying the Conditions of Paragraph 42 of FASB Statement No. 144 in Determining Whether to Report Discontinued Operations, provides that the results of operations of a component of an entity that has been disposed of or is classified as held for sale shall be reported in discontinued operations if both of the following conditions are met: (a) the operations and cash flows of the component have been (or will be) eliminated from the ongoing operations of the entity as a result of the disposal transaction and (b) the entity will not have any significant continuing involvement in the operations of the component after the disposal transaction. While we do not expect to have significant continuing involvement with Peoples or Hope after their disposal, we do expect to have continuing cash flows related primarily to our sale to them of natural gas production from our exploration and production operations, as well as natural gas transportation and storage services provided to them by our transmission operations. Due to these expected significant continuing cash flows, the results of Peoples and Hope have not been reported as discontinued operations in our Consolidated Statements of Income. We will continue to assess the level of our involvement and continuing cash flows with Peoples and Hope for one year after the date of sale and if circumstances change, we may be required to reclassify the results of Peoples and Hope as discontinued operations in our Consolidated Statements of Income.

Note 7. Operating Revenue

Our operating revenue consists of the following:

	Three Months Ended March 31,
	2006	2005
Operating Revenue	(millions)
Electric sales:
Regulated	$1,298	$1,322
Nonregulated	600	714
Gas sales:
Regulated	800	778
Nonregulated	882	745
Other energy-related commodity sales	493	396
Gas transportation and storage	285	275
Gas and oil production	532	411
Other	67	95
Total operating revenue	$4,957	$4,736

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DOMINION RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Note 8. Income Taxes

The statutory U.S. Federal income tax rate reconciles to our effective income tax rate as follows:

	Three Months Ended March 31,
	2006	2005

U.S. statutory rate	35.0%	35.0%

Increases (decreases) resulting from:
Amortization of investment tax credits	(0.4)	(0.5)
Employee pension and other benefits	(0.4)	(0.3)
Employee stock ownership plan and restricted stock dividends	(0.4)	(0.3)
Other benefits and taxes - foreign operations	--	(1.4)
State taxes, net of federal benefit	5.0	3.8
Other, net	(1.2)	0.3
Subtotal	37.6	36.6
Changes in valuation allowances	(29.1)	--
Recognition of deferred taxes - stock of subsidiaries held for sale	19.1	--
Effective tax rate	27.6%	36.6%

Our effective tax rate for the three months ended March 31, 2006 reflects a $222 million tax benefit from the partial reversal of previously recorded valuation allowances on certain federal and state tax loss carryforwards, since these carryforwards are expected to be utilized to offset capital gain income generated from the pending sale of Peoples and Hope. This benefit was partially offset by the establishment of $141 million of deferred tax liabilities 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, as discussed in Note 6.

Note 9. Earnings Per Share

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

	Three Months Ended March 31,
	2006	2005
	(millions, except EPS)
Net income	$534	$429

Basic EPS
Average shares of common stock outstanding - basic	346.5	340.3
Net income	$1.54	$1.26

Diluted EPS
Average shares of common stock outstanding	346.5	340.3
Net effect of potentially dilutive securities ⁽¹⁾	1.6	2.0
Average shares of common stock outstanding - diluted	348.1	342.3
Net income	$1.53	$1.25

(1) Potentially dilutive securities consist of options, restricted stock, equity-linked securities, contingently convertible senior notes and shares that were issuable under a forward equity sale agreement.

Potentially dilutive securities with the right to acquire approximately 1.4 million and 1.5 million common shares for the three months ended March 31, 2006 and 2005, respectively, 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.

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DOMINION RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Note 10. Comprehensive Income

The following table presents total comprehensive income (loss):

	Three Months Ended March 31,
	2006	2005
	(millions)
Net income	$ 534	$ 429
Other comprehensive income (loss):
Net other comprehensive income (loss) associated with effective portion of the changes in fair value of derivatives designated as cash flows hedges, net of taxes and amounts reclassified to earnings⁽¹⁾	719	(888)
Other⁽²⁾	20	(37)
Other comprehensive income (loss)	739	(925)
Total comprehensive income (loss)	$1,273	$(496)

(1) Principally due to changes in the fair value of certain commodity derivatives resulting from fluctuations in commodity prices.

(2) Primarily reflects unrealized gains and losses on investments held in nuclear decommissioning trusts.

Note 11. Hedge Accounting Activities

We are exposed to the impact of market fluctuations in the price of natural gas, electricity and other energy-related products marketed and purchased as well as currency exchange and interest rate risks of our business operations. We use derivative instruments to mitigate our exposure to these risks and designate certain derivative instruments as fair value or cash flow hedges for accounting purposes as allowed by SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. Selected information about our hedge accounting activities follows:

	Three Months Ended March 31,
	2006	2005
Portion of gains (losses) on hedging instruments determined to be ineffective and included in net income:	(millions)
Fair value hedges	$ (7)	$ 4
Cash flow hedges	19	(6)
Net ineffectiveness	$ 12	$(2)

Gains and losses on hedging instruments that were excluded from the measurement of effectiveness and included in net income for the three months ended March 31, 2006 and 2005 were not material.

As a result of a delay in reaching anticipated production levels in the Gulf of Mexico, we discontinued hedge accounting for certain cash flow hedges in March 2005 since it became probable that the forecasted sales of oil would not occur. The discontinuance of hedge accounting for these contracts resulted in the reclassification of $30 million ($19 million after-tax) of losses from AOCI to earnings in March 2005.

PAGE 14

DOMINION RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

The following table presents selected information related to cash flow hedges included in accumulated other comprehensive income (loss) (AOCI) in our Consolidated Balance Sheet at March 31, 2006:

	AOCI After-Tax	Portion Expected to be Reclassified to Earnings during the Next 12 Months After-Tax	Maximum Term
	(millions)
Commodities:
Gas	$ (987)	$ (568)	57 months
Oil	(570)	(339)	33 months
Electricity	(509)	(318)	45 months
Interest rate	(15)	6	243 months
Foreign currency	23	10	20 months
Total	$(2,058)	$(1,209)

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

Note 12. Ceiling Test

We follow the full cost method of accounting for gas and oil exploration and production 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, assuming period-end hedge-adjusted prices. Approximately 10% of our anticipated production is hedged by qualifying cash flow hedges, for which hedge-adjusted prices were used to calculate estimated future net revenue. Whether period-end market prices or hedge-adjusted prices were used for the portion of production that is hedged, there was no ceiling test impairment as of March 31, 2006.

Note 13. Variable Interest Entities

Certain variable pricing terms in some of our long-term power and capacity contracts cause them to be considered potential variable interests in the counterparties. As discussed in Note 16 to our Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2005, three potential VIEs, with which we have existing power purchase agreements (signed prior to December 31, 2003), have not provided sufficient information for us to perform our Financial Accounting Standards Board (FASB) Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, (FIN 46R) evaluation.

As of March 31, 2006, the requested information has not been received from the three remaining potential VIEs. We will continue our efforts to obtain information and will complete an evaluation of our relationship with each of these potential VIEs if sufficient information is ultimately obtained. We have remaining purchase commitments with these three potential VIE supplier entities of $2.0 billion at March 31, 2006. We paid $50 million and $54 million for electric generation capacity and $36 million and $46 million for electric energy to these entities in the three months ended March 31, 2006 and 2005, respectively.

PAGE 15

DOMINION RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

During 2005, we entered into four long-term contracts with unrelated limited liability corporations (LLCs) to purchase synthetic fuel produced from coal. Certain variable pricing terms in the contracts protect the equity holders from variability in the cost of their coal purchases, and therefore, the LLCs were determined to be VIEs. After completing our FIN 46R analysis, we concluded that although our interests in the contracts, as a result of their pricing terms, represent variable interests in the LLCs, we are not the primary beneficiary. We paid $111 million and $22 million to the LLCs for coal and synthetic fuel produced from coal during the three months ended March 31, 2006 and 2005, respectively. We are not subject to any risk of loss from the contractual arrangements, as our only obligation to the VIEs is to purchase the coal and synthetic fuel that the VIEs provide according to the terms of the applicable purchase contracts.

In accordance with FIN 46R, we consolidate certain variable interest lessor entities through which we have financed and leased several power generation projects as well as our corporate headquarters and aircraft. Our Consolidated Balance Sheets as of March 31, 2006 and December 31, 2005 reflect net property, plant and equipment of $936 million and $943 million, respectively and $1.1 billion of debt related to these entities. The debt is nonrecourse to us and is secured by the entities’ property, plant and equipment.

Note 14. Significant Financing Transactions

Credit Facilities and Short-Term Debt

We use short-term debt, primarily commercial paper, to fund working capital requirements, as a bridge to long-term debt financing and as bridge financing for acquisitions, if applicable. The levels of borrowing may vary significantly during the course of the year, depending upon the timing and amount of cash requirements not satisfied by cash from operations. In addition, 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 the credit quality of our companies and their counterparties. In February 2006, we entered into a $3.0 billion five-year credit facility that replaced our $2.5 billion five-year joint revolving credit facility dated May 2005. Also in February 2006, CNG amended and restated its $1.75 billion five-year revolving credit facility dated August 2005 with the facility limit reduced to $1.70 billion and entered into a $1.05 billion 364-day credit facility. At March 31, 2006, we had committed lines of credit totaling $5.75 billion. These lines of credit support commercial paper borrowings and letter of credit issuances. At March 31, 2006, we had the following commercial paper and letters of credit outstanding and capacity available under credit facilities:

	Facility Limit	Outstanding Commercial Paper	Outstanding Letters of Credit	Facility Capacity Available
(millions)
Five-year revolving credit facility⁽¹⁾	$3,000	$1,356	$ 631	$1,013
Five-year CNG credit facility⁽²⁾	1,700	---	1,068	632
364-day CNG credit facility⁽³⁾	1,050	---	---	1,050
Totals	$5,750	$1,356	$1,699	$2,695

(1) The $3.0 billion five-year credit facility was entered into in February 2006 and terminates in February 2011. This credit facility can also be used to support up to $1.5 billion of letters of credit.

(2) The $1.70 billion five-year credit facility is used to support the issuance of letters of credit and commercial paper by CNG to fund collateral requirements under its gas and oil hedging program. The facility was entered into in February 2006 and terminates in August 2010.

(3) The $1.05 billion 364-day credit facility is used to support the issuance of letters of credit and commercial paper by CNG to fund collateral requirements under its gas and oil hedging program. The facility was entered into in February 2006 and terminates in February 2007.

We have also entered into several bilateral credit facilities in addition to the facilities above in order to provide collateral required on derivative contracts used in our price risk management strategies for merchant generation and gas and oil production operations, respectively. At March 31, 2006, we had the following letter of credit facilities:

PAGE 16

DOMINION RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Company		Facility Limit		Outstanding Letters of Credit		Facility Capacity Remaining	Facility Inception Date	Facility Maturity Date
(millions)
CNG	$	100	$	100	$	--	June 2004	June 2007
CNG		100		100		--	August 2004	August 2009
CNG⁽¹⁾		150		--		150	October 2004	April 2006
CNG⁽²⁾		200		--		200	December 2005	December 2010
Dominion Resources, Inc.⁽¹⁾		215		40		175	October 2005	April 2006
Totals	$	765	$	240	$	525

(1)	We did not renew these facilities prior to their maturity.

(2)	This facility can also be used to support commercial paper borrowings.

Long-Term Debt

In January 2006, Virginia Power issued $450 million of 5.4% senior notes that mature in 2016 and $550 million of 6.0% senior notes that mature in 2036. We used the proceeds from this issuance to repay short-term debt incurred to redeem Virginia Power’s $512 million callable mortgage bonds, and a portion of Virginia Power’s maturing long-term debt.

In February 2006, Dominion Energy Brayton Point, LLC borrowed $47 million in connection with the Massachusetts Development Finance Agency’s issuance of its Solid Waste Disposal Revenue Bonds (Dominion Energy Brayton Point Issue) Series 2006, which mature in 2036 and bear a coupon rate of 5%. The bonds were issued pursuant to a trust agreement whereby funds are withdrawn from the trust as improvements are made at our Brayton Point Station located in Somerset, Massachusetts. We have withdrawn $33 million from the trust as of March 31, 2006.

In February 2006, we successfully remarketed $330 million of 5.75% Series A senior notes related to our equity-linked debt securities. The senior notes, which will mature in 2008, now carry an annual interest rate of 5.687%. We expect to receive proceeds of $330 million in May 2006 from the issuance of common stock in connection with the settlement of the related stock purchase contracts.

We repaid $609 million of long-term debt during the three months ended March 31, 2006.

Convertible Securities

In December 2003, we issued $220 million of contingent convertible senior notes that are convertible by holders into a combination of cash and shares of our common stock under certain circumstances. At March 31, 2006, since none of these conditions had been met, these senior notes were not yet subject to conversion. In 2004 and 2005, we entered into exchange transactions with respect to these contingent convertible senior notes in contemplation of EITF Issue No. 04-8, The Effect of Contingently Convertible Instruments on Diluted Earnings per Share. We exchanged the outstanding notes for new notes with a conversion feature that requires that the principal amount of each note be repaid in cash. The notes are valued at a conversion rate of 13.5865 shares of common stock per $1,000 principal amount of senior notes, which represents a conversion price of $73.60. 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.

The new notes have been included in the diluted EPS calculation using the method described in EITF 04-8. Under this method, the number of shares included in the denominator of the diluted EPS calculation is calculated as the net shares issuable for the reporting period based upon the average market price for the period. This resulted in an increase in the average shares outstanding used in the calculation of our diluted EPS since the conversion price of $73.60 included in the notes was lower than the average market price of our common stock over this period.

PAGE 17

DOMINION RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Issuance of Common Stock

We maintain Dominion Direct (a dividend reinvestment and open enrollment direct stock purchase plan) and a number of employee savings plans through which employer and employee contributions may be invested in Dominion common stock. These shares may either be newly issued or purchased on the open market with proceeds contributed to these plans by employees and us.

Since February 2005, Dominion Direct and the Dominion employee savings plans have been purchasing Dominion common stock on the open market with the proceeds received through these programs, rather than having additional new common shares issued. In May 2006, we will begin issuing additional new common shares in consideration of proceeds received through these programs, rather than the plans making open market purchases of such shares.

Note 15. Stock-Based Awards

In April 2005, our shareholders approved the 2005 Incentive Compensation Plan (2005 Incentive Plan) for employees and the Non-Employee Directors Compensation Plan (Non-Employee Directors Plan). Both plans permit stock-based awards that include restricted stock, performance grants, goal-based stock, and stock options under the 2005 Incentive Plan and restricted stock and stock options under the Non-Employee Directors Plan. Under provisions of both plans, employees and non-employee directors may be granted options to purchase common stock at a price not less than its fair market value at the date of grant with a maximum term of eight years. Option terms are set at the discretion of either the Organization, Compensation and Nominating Committee of the Board of Directors or the Board of Directors itself, as provided under each individual plan. At March 31, 2006, approximately 15.3 million shares were available for future grants under these plans. Prior to April 2005, we had an incentive compensation plan that provided stock options and restricted stock awards to directors, executives and other key employees with vesting periods from one to five years. Stock options generally had contractual terms from six and one half to ten years in length.

Our results for both of the three month periods ended March 31, 2006 and 2005 include $4.3 million of stock-based compensation cost reported in other operations and maintenance expense in our Consolidated Statements of Income and $1.7 million of income tax benefits related to stock-based awards.

Stock Options

The following table provides a summary of stock options outstanding for the three months ended March 31, 2006.

	Shares	Weighted-Average Exercise Price	Weighted-Average Remaining Contractual Life	Aggregate intrinsic value⁽¹⁾
	(thousands)		(years)	(millions)
Outstanding and exercisable at January 1, 2006	8,214	$60.43
Granted	--	--
Exercised	(60)	55.76		$ 1
Forfeited/expired	--	--
Outstanding and exercisable at March 31, 2006	8,154	60.46	4.0	79

(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. In the three months ended March 31, 2006 and 2005, we received cash proceeds of $3.1 million and $206.8 million, respectively, from the exercise of stock options.

PAGE 18

DOMINION RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

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, 2006.

	Shares	Weighted-Average Grant Date Fair Value
	(thousands)
Nonvested at January 1, 2006	1,131	$63.28
Granted	3	76.07
Vested	(142)	58.84
Cancelled and forfeited	(3)	63.35
Nonvested at March 31, 2006	989	63.96

As of March 31, 2006, unrecognized compensation cost related to nonvested restricted stock awards totaled $30 million and is expected to be recognized over a weighted-average period of 2.2 years. In the three months ended March 31, 2006, the fair value of restricted stock awards that vested totaled $11 million.

Note 16. Commitments and Contingencies

Other than the matters discussed below, 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, 2005, nor have any significant new matters arisen during the three months ended March 31, 2006.

Income Taxes

As a matter of course, we are regularly audited by federal and state tax authorities. We establish liabilities for probable tax-related contingencies in accordance with SFAS No. 5, Accounting for Contingencies, and review them in light of changing facts and circumstances. Although the results of these audits are uncertain, we believe that the ultimate outcome will not have a material adverse effect on our financial position. At March 31, 2006 and December 31, 2005, our Consolidated Balance Sheets reflect $153 million and $144 million, respectively, of income tax-related contingent liabilities, including accrued interest.

Lease Commitment

During the three months ended March 31, 2006, we signed several contracts to lease onshore drilling rigs. The terms of the contracts range from two to three years. Our total minimum commitment under the agreements is approximately $194 million.

Environmental Matters

In 1987, we and a number of other entities were identified by the Environmental Protection Agency (EPA) as potentially responsible parties (PRPs) at two Superfund sites located in Kentucky and Pennsylvania. In 2003, the EPA issued its Certificate of Completion of remediation for the Kentucky site. Future costs for the Kentucky site will be limited to minor operations and maintenance expenditures. Regarding the Pennsylvania site, in March, 2006, a federal district court approved three consent decrees between the United States and the PRPs, under which we and certain other PRPs, all of which are utilities, will perform the site remediation. The remediation costs are expected to be in the range of $11 million to $18 million, the majority of which are to be paid by the non-utility site owners. We currently have an accrued reserve of $2 million to meet our potential obligations at these two sites. We generally seek to recover our costs associated with environmental remediation from third party insurers. At March 31, 2006, no pending or possible insurance claims were recognized as an asset or offset against obligations.

PAGE 19

DOMINION RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Guarantees

At March 31, 2006, we had issued $31 million of guarantees to support third parties, equity method investees and employees affected by Hurricane Katrina. In addition, in 2005, we, along with two other gas and oil exploration and production companies, entered into a four-year drilling contract related to a new, ultra-deepwater drilling rig that is expected to be delivered in mid-2008. The contract has a four-year primary term, plus four one-year extension options. Our minimum commitment under the agreement is for approximately $99 million over the four-year term; however, we are jointly and severally liable for up to $394 million to the contractor if the other parties fail to pay the contractor for their obligations under the primary term of the agreement, which we view as highly unlikely. We have not recognized any significant liabilities related to any of these guarantee arrangements.

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. No such liabilities have been recognized as of March 31, 2006. 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, 2006, we had issued the following subsidiary guarantees:

	Stated Limit	Value⁽¹⁾
(millions)
Subsidiary debt⁽²⁾	$1,320	$1,320
Commodity transactions⁽³⁾	3,766	1,762
Lease obligation for power generation facility⁽⁴⁾	898	898
Nuclear obligations⁽⁵⁾	375	303
Offshore drilling commitments⁽⁶⁾	--	493
Other	594	422
Total	$6,953	$5,198

(1)

Represents the estimated portion of the guarantee’s stated limit that is utilized as of March 31, 2006 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 Dominion Resources Services (DRS), and certain DEI and CNG 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 CNG and DEI. These guarantees were provided to counterparties in order to facilitate physical and financial transactions in gas, oil, electricity, pipeline capacity, transportation and related commodities and services. If 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 the Fairless Energy power station.

(5)

Guarantees related to Virginia Power’s and certain DEI subsidiaries’ potential retrospective premiums that could be assessed if there is a nuclear incident under our nuclear insurance programs and includes guarantees for Virginia Power’s commitment to buy nuclear fuel. Also, as part of satisfying certain NRC requirements concerned with ensuring adequate funding for the operations of the Millstone Power Station, we have also agreed to provide up to $150 million to a DEI subsidiary, if requested by such subsidiary, to pay Millstone’s operating expenses.

(6)	There is no stated limit for this guarantee.

Surety Bonds and Letters of Credit

As of March 31, 2006, we had also purchased $70 million of surety bonds and authorized the issuance of standby letters of credit by financial institutions of $1.9 billion. We enter into these arrangements to facilitate commercial transactions by our subsidiaries with third parties.

PAGE 20

DOMINION RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Note 17. Credit Risk

Credit risk is our risk of financial loss if counterparties fail to perform their contractual obligations. In order to minimize overall credit risk, we maintain credit policies, including the evaluation of counterparty financial condition, collateral requirements and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. We maintain a provision for credit losses based on factors surrounding the credit risk of our customers, historical trends and other information. We believe, based on our credit policies and our March 31, 2006 provision for credit losses, that it is unlikely that a material adverse effect on our financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.

As a diversified energy company, we transact with major companies in the energy industry and with commercial and residential energy consumers. Except for gas and oil exploration and production business activities, these transactions principally occur in the Northeast, Mid-Atlantic and Midwest regions of the United States. 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 sales of gas and oil production and 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. At March 31, 2006, gross credit exposure related to these transactions totaled $1.09 billion, reflecting the unrealized gains for contracts carried at fair value plus any outstanding receivables (net of payables, where netting agreements exist), prior to the application of collateral. After the application of collateral, our credit exposure is reduced to $1.05 billion. Of this amount, investment grade counterparties represent 77% and no single counterparty exceeded 6%.

Note 18. Employee Benefit Plans

The following table illustrates the components of the provision for net periodic benefit cost for our pension and other postretirement benefit plans:

	Pension Benefits		Other Postretirement Benefits
Three Months Ended March 31,	2006	2005	2006	2005
	(millions)
Service cost	$35	$29	$21	$16
Interest cost	58	54	23	20
Expected return on plan assets	(99)	(93)	(17)	(13)
Curtailment loss⁽¹⁾	6	--	--	--
Amortization of prior service cost (credit)	1	1	(1)	--
Amortization of transition obligation	--	--	1	1
Amortization of net loss	25	21	8	5
Net periodic benefit cost	$26	$12	$35	$29

(1)	Relates to the pending sale of Peoples and Hope discussed in Note 6.

Employer Contributions

We made no contributions to our defined benefit pension plans or other postretirement benefit plans during the three months ended March 31, 2006. We expect to contribute at least $35 million to our other postretirement benefit plans during the remainder of 2006. 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 in 2006 will be determined at that time.

PAGE 21

DOMINION RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

Note 19. Operating Segments

Our Company is organized primarily on the basis of products and services sold in the United States. We manage our operations through the following segments:

Dominion Delivery includes our regulated electric and gas distribution and customer service business, as well as nonregulated retail energy marketing operations.

Dominion Energy includes our tariff-based electric transmission, natural gas transmission pipeline and underground natural gas storage businesses and an LNG facility. It also includes certain natural gas production and producer services, which consist of aggregation of gas supply, market-based services related to gas transportation and storage and associated gas trading.

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

Dominion E&P includes our gas and oil exploration, development and production operations. Operations are located in several major producing basins in the lower 48 states, including the outer continental shelf and deepwater areas of the Gulf of Mexico, and Western Canada.

Corporate includes our corporate, service company and other functions (including unallocated debt), corporate-wide enterprise commodity price risk management and optimization services and the remaining assets of DCI. In addition, the contribution to net income by our primary operating segments is determined based on a measure of profit that executive management believes represents the segments’ core earnings. As a result, certain specific items attributable to those segments are not included in profit measures evaluated by executive management in assessing the segment’s performance or allocating resources among the segments and are instead reported in the Corporate segment. In the three months ended March 31, 2006 and 2005, we reported net expenses of $94 million and $54 million, respectively, in the Corporate segment attributable to our operating segments. The net expenses in 2006 primarily related to the impact of a $159 million ($94 million after-tax) charge resulting from the write-off of certain regulatory assets related to the pending sale of Peoples and Hope, attributable to the Dominion Delivery segment.

The net expenses in 2005 related to the following items attributable to the Dominion Generation segment:

·	A $77 million ($47 million after-tax) charge related to our interest in a long-term power tolling contract that was divested in 2005 and the termination of a long-term power purchase agreement; and

·	An $11 million ($6 million after-tax) charge primarily related to our interest in a long-term power tolling contract that was divested in 2005.

Intersegment sales and transfers are based on underlying contractual arrangements and agreements and may result in intersegment profit or loss.

PAGE 22

DOMINION RESOURCES, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Continued)

The following table presents segment information pertaining to our operations:

	Dominion Delivery	Dominion Energy	Dominion Generation	Dominion E&P	Corporate	Adjustments/ Eliminations	Consolidated Total
Three Months Ended March 31,	(millions)
2006
Operating Revenue:
External customers	$1,672	$598	$1,659	$872	$ (37)	$ 193	$4,957
Intersegment	3	276	42	68	195	(584)	--
Total operating revenue	1,675	874	1,701	940	158	(391)	4,957
Net income (loss)	156	107	132	230	(91)	--	534
2005
Operating Revenue:
External customers	$1,531	$484	$1,867	$635	$ (2)	$ 221	$4,736
Intersegment	18	227	55	43	149	(492)	--
Total operating revenue	1,549	711	1,922	678	147	(271)	4,736
Net income (loss)	184	99	145	112	(111)	--	429

PAGE 23

DOMINION RESOURCES, INC.

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Contents of MD&A

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

·	Forward-Looking Statements

·	Accounting Matters

·	Results of Operations

·	Segment Results of Operations

·	Selected Information — Energy Trading Activities

·	Sources and Uses of Cash

·	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” 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, production delays and property damage to our facilities;

·	State and federal legislative and regulatory developments, including deregulation and changes in environmental and other laws and regulations to which we are subject;

·	Cost of environmental compliance;

·	Risks associated with the operation of nuclear facilities;

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

·	Counterparty credit risk;

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

·	Fluctuations in interest rates;

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

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

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

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

·	Changes in our ability to recover investments made under traditional regulation through rates;

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

·	Realization of expected business interruption insurance proceeds and decreased availability of business interruption insurance on commercially reasonable terms;

·	Transitional issues related to the transfer of control over our electric transmission facilities to a regional transmission organization;

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

·	Completing the divestiture of investments held by our financial services subsidiary, DCI.

PAGE 24

DOMINION RESOURCES, INC.

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

(Continued)

Additionally, other risks that could cause actual results to differ from predicted results are set forth in Part II, Item 1A. Risk Factors in this report and in our Annual Report on Form 10-K for the year ended December 31, 2005.

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, 2006, 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, 2005. The policies disclosed included the accounting for derivative contracts at fair value, goodwill and long-lived asset impairment testing, asset retirement obligations, employee benefit plans, regulated operations, gas and oil operations, and income taxes.

Other

EITF 04-13

We enter into buy/sell and related agreements primarily as a means to reposition our offshore Gulf of Mexico crude oil production to more liquid marketing locations onshore. As discussed in Note 4 to our Consolidated Financial Statements, in September 2005, the FASB ratified the EITF’s consensus on Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty, that will require buy/sell and related agreements to be presented on a net basis in the Consolidated Statements of Income if they are entered into in contemplation of one another. This new guidance is required to be applied to all new arrangements entered into, and modifications or renewals of existing arrangements, beginning April 1, 2006. We adopted EITF 04-13 on April 1, 2006, and as a result, a portion of our future activity related to buy/sell arrangements will be presented on a net basis in our Consolidated Statements of Income; however, there will be no impact on our results of operations or cash flows.

Accounting for Pensions and Other Postretirement Benefits

In late 2005, the FASB added a two-phase comprehensive project to its technical agenda to reconsider the accounting for pensions and other postretirement benefits. In March 2006, the FASB issued an Exposure Draft, Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R), representing the first phase of the project. In this phase, the FASB is proposing to require that entities recognize the current economic over-funded or under-funded status of their defined benefit postretirement plans in their balance sheets effective December 31, 2006, with retrospective application required unless it is deemed impracticable. The FASB’s goal is to issue a final Statement by September 2006. We are currently assessing the impact that this new guidance will have on our results of operations and financial condition, if it is issued as drafted.

Results of Operations

Presented below is a summary of our consolidated results for the quarter ended March 31, 2006 and 2005:

First Quarter	2006	2005	$ Change

Net income (millions)	$ 534	$ 429	$ 105
Diluted EPS	1.53	1.25	0.28

Overview

Net income for the first quarter of 2006 increased 24% to $534 million. The improvement in our first quarter results is largely attributable to a higher contribution from our exploration and production operations as a result of increased oil production, higher realized prices for gas and oil and the impact of favorable price changes on derivatives that were de-designated as hedges following Hurricanes Katrina and Rita in 2005.

PAGE 25

DOMINION RESOURCES, INC.

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

(Continued)

Analysis of Consolidated Operations

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

First Quarter	2006	2005	$ Change
(millions)

Operating Revenue	$4,957	$4,736	$221

Operating Expenses
Electric fuel and energy purchases	766	841	(75)
Purchased electric capacity	123	134	(11)
Purchased gas	1,378	1,222	156
Other energy-related commodity purchases	400	324	76
Other operations and maintenance	768	831	(63)
Depreciation, depletion and amortization	381	346	35
Other taxes	181	165	16

Other income	43	51	(8)
Interest and related charges	265	247	18
Income tax expense	204	248	(44)

An analysis of our results of operations for the first quarter of 2006 compared to the first quarter of 2005 follows:

Operating Revenue increased 5% to $5.0 billion, primarily reflecting:

A $137 million increase in nonregulated gas sales revenue predominantly due to a $104 million increase from gas aggregation activities and a $102 million increase from nonregulated retail energy marketing activities both primarily reflecting higher prices. These increases were partially offset by a $48 million decrease due to the impact of losses on derivatives associated with certain transportation contracts. The increase in nonregulated gas sales was largely offset by a corresponding increase in Purchased gas expense;

A $121 million increase in gas and oil production revenue, reflecting a $98 million increase in sales of oil production, primarily due to higher volumes ($77 million) and increased prices ($21 million) and a $23 million increase from gas production sales, primarily due to higher average realized prices;

·	A $97 million increase in other energy-related commodity sales, primarily reflecting the following:

·	A $138 million increase in sales of purchased oil under buy/sell arrangements by exploration and production operations resulting from higher prices ($48 million) and increased sales volumes ($90 million);

·	A $28 million increase in sales of extracted products, primarily due to a contractual change for a portion of our gas production processed by third parties. We now take title to and market the natural gas liquids extracted from this gas; partially offset by

·	A $62 million decline in nonutility coal sales resulting primarily from lower realized coal prices ($44 million) and sales volumes ($18 million).

These benefits were partially offset by:

·	A $114 million decrease in nonregulated electric sales revenue, primarily reflecting:

The effects on revenue of price risk management activities associated with our merchant generation assets, including lower volumes for requirements-based sales contracts ($178 million). We realized higher overall average margins for our merchant generation assets through financial and physical hedges and spot pool activity, the effects of which are also included in the decreases in Electric fuel and energy purchases expense and Other operations and maintenance expense; partially offset by

·	A $47 million increase related to the acquisition in July 2005 of the 556-megawatt Kewaunee nuclear power station (Kewaunee); and

·	A $21 million increase in revenue from nonregulated retail energy marketing operations due to higher customer contract sales rates.

PAGE 26

DOMINION RESOURCES, INC.

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

(Continued)

·	A $28 million decrease in other revenue, largely reflecting a $44 million decrease due to the absence of business interruption insurance revenue recognized in 2005 associated with Hurricane Ivan, partially offset by an increase in miscellaneous service revenue and fees of approximately $16 million.

Operating Expenses and Other Items

Electric fuel and energy purchases expense decreased 9% to $766 million, primarily reflecting the combined effects of:

·	A $160 million decrease related to merchant generation operations and price risk management activities associated with these assets as discussed above in Operating Revenue; and

An $87 million increase related to our utility generation operations, primarily due to higher commodity prices, including purchased power and congestion costs associated with PJM, and the purchase of replacement power in connection with a nuclear refueling outage. This increase was partially offset by lower customer usage associated with milder weather.

Purchased electric capacity expense decreased 8% to $123 million, as a result of the termination of a long-term power purchase agreement in connection with the acquisition of the related generating facility in February 2005.

Purchased gas expense increased 13% to $1.4 billion, principally resulting from a $87 million increase related to gas aggregation activities discussed in Operating Revenue and a $44 million increase attributable to regulated gas distribution operations reflecting higher prices ($174 million) partially offset by lower volumes ($130 million).

Other energy-related commodity purchases expense increased 23% to $400 million due predominantly to a $136 million increase in purchases of oil under buy/sell arrangements by our exploration and production operations, partially offset by a $56 million decrease in nonutility coal purchased for resale, both of which are discussed in Operating Revenue.

Other operations and maintenance expense decreased 8% to $768 million, resulting from:

·	A $135 million benefit primarily from price risk management activities, associated with our merchant generation assets as discussed in Operating Revenue;

·	A $118 million benefit resulting from favorable changes in the fair value of certain gas and oil derivatives that were de-designated as hedges following the 2005 hurricanes;

·	A $28 million benefit related to financial transmission rights (FTRs) granted by PJM to our utility generation operations to offset congestion costs associated with PJM spot market activity; and

·	A benefit resulting from the net impact of the following items recognized in 2005:

·	A $77 million charge resulting from the termination of a long-term power purchase agreement; and

·	A $49 million loss related to the discontinuance of hedge accounting for certain oil derivatives primarily resulting from a delay in reaching anticipated production levels in the Gulf of Mexico, and subsequent changes in the fair value of those derivatives; partially offset by

·	A $24 million net benefit recognized by regulated utility operations resulting from the establishment of certain regulatory assets and liabilities in connection with settlement of a North Carolina rate case.

These benefits were partially offset by:

·	A $159 million charge from the write off of certain regulatory assets related to the pending sale of Peoples and Hope;

·	A $36 million increase due to higher salaries, wages and benefits expenses;

·	A $32 million increase attributable to maintenance costs primarily related to scheduled outages at our generation facilities;

·	A $27 million increase due to the addition of Kewaunee in July 2005;

·	A $27 million increase due to higher production and transportation costs for gas and oil production operations;

·	A $25 million increase in expenses for regulated gas operations related to low income home energy assistance programs. These expenditures for regulated gas operations are recovered through rates and do not impact our net income; and

·	A $15 million increase in insurance costs for exploration and production operations primarily due to higher insurance premiums following the 2005 hurricanes.

Depreciation, depletion and amortization expense (DD&A) increased 10% to $381 million, largely due to the impact of higher exploration and production finding and development costs, as well as increased oil production.

PAGE 27

DOMINION RESOURCES, INC.

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

(Continued)

Other taxes increased 10% to $181 million, primarily due to higher payroll taxes resulting from incentive-based compensation paid in 2006 and higher severance taxes associated with increased commodity prices.

Interest and related charges increased 7% to $265 million resulting principally from higher interest rates on variable rate debt.

Income tax expense reflects a decrease in our effective tax rate to 27.6% resulting primarily from a net income tax benefit recorded in connection with our planned sale of Peoples and Hope, as discussed in Note 8 to our Consolidated Financial Statements.

Segment Results of Operations

Segment results include the impact of intersegment revenues and expenses, which may result in intersegment profit and loss. Presented below is a summary of contributions by operating segments to net income for the quarter ended March 31, 2006 and 2005:

	Net Income			Diluted EPS
First Quarter	2006	2005	$ Change	2006	2005	$ Change
(millions, except EPS)
Dominion Delivery	$156	$184	$ (28)	$0.45	$0.54	$(0.09)
Dominion Energy	107	99	8	0.31	0.29	0.02
Dominion Generation	132	145	(13)	0.38	0.42	(0.04)
Dominion Exploration & Production	230	112	118	0.66	0.33	0.33
Primary operating segments	625	540	85	1.80	1.58	0.22

Corporate	(91)	(111)	20	(0.27)	(0.33)	0.06
Consolidated	$534	$429	$ 105	$1.53	$1.25	$ 0.28

Dominion Delivery

Dominion Delivery includes our regulated electric and gas distribution and customer service business, as well as nonregulated retail energy marketing operations. Presented below are operating statistics related to our Dominion Delivery operations:

First Quarter	2006	2005	% Change
Electricity delivered (million mwhrs)	19.5	19.9	(2)%
Degree days (electric service area):
Cooling⁽¹⁾	13	--	100
Heating⁽²⁾	1,796	2,111	(15)
Electric delivery customer accounts⁽³⁾	2,318	2,277	2
Gas throughput (bcf):
Gas sales	50	63	(21)
Gas transportation	87	92	(5)
Heating degree days (gas service area)⁽²⁾	2,580	3,022	(15)
Gas delivery customer accounts⁽³⁾:
Gas sales	996	1,071	(7)
Gas transportation	704	635	11
Nonregulated retail energy marketing customer accounts⁽³⁾	1,199	1,131	6

mwhrs = megawatt hours

bcf = billion cubic feet

(1)	Cooling degree days are the differences between the average temperature for each day and 65 degrees, assuming the average temperature is greater than 65 degrees.

(2)	Heating degree days are the differences between the average temperature for each day and 65 degrees, assuming the average temperature is less than 65 degrees.

(3)	In thousands, at period end.

PAGE 28

DOMINION RESOURCES, INC.

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

(Continued)

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

	First Quarter
	2006 vs. 2005
	Increase
	(Decrease)
	Amount	EPS
(millions, except EPS)
Regulated gas sales - weather	$(12)	$(0.04)
Regulated electric sales:
Weather	(9)	(0.03)
Customer growth	3	0.01
Economy and other margins⁽¹⁾	(8)	(0.02)
Interest expense⁽²⁾	(7)	(0.02)
North Carolina rate case settlement	(6)	(0.02)
Nonregulated retail energy marketing operations⁽³⁾	10	0.03
Other	1	--
Share dilution	--	--
Change in net income contribution	$(28)	$(0.09)

(1)	Reflects reduced customer usage, due in part to sensitivity to rising gas prices.

(2)	An increase resulting from additional borrowings, as well as increased rates on intercompany borrowings.

(3)	Largely reflects higher electric and gas margins.

Dominion Energy

Dominion Energy includes our tariff-based electric transmission, natural gas transmission pipeline and storage businesses and an LNG facility. It also includes certain natural gas production and producer services, which consist of aggregation of gas supply, market-based services related to gas transportation and storage and associated gas trading. Presented below are operating statistics related to our Dominion Energy operations.

First Quarter	2006	2005	% Change
Gas transmission throughput (bcf)	234	301	(22)%

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

	First Quarter
	2006 vs. 2005
	Increase
	(Decrease)
	Amount	EPS
(millions, except EPS)
Producer services⁽¹⁾	$15	$0.04
RTO start-up and integration costs⁽²⁾	4	0.01
Gas transmission rate settlement⁽³⁾	(9)	(0.03)
Other	(2)	--
Share dilution	--	--
Change in net income contribution	$ 8	$0.02

(1)	Higher gains resulting from the impact of favorable price changes on gas marketing activities associated with certain contractual assets.

(2)	A benefit from the absence of a 2005 charge incurred by our electric utility operations for the write-off of certain previously deferred start-up and integration costs associated with joining an RTO that were primarily allocable to Virginia non-jurisdictional and wholesale customers.

(3)	Represents lower natural gas transportation and storage revenues as a result of a rate settlement effective July 2005.

PAGE 29

DOMINION RESOURCES, INC.

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

(Continued)

Dominion Generation

Dominion Generation includes the generation operations of our electric utility and merchant fleet, utility energy supply activities and energy marketing and price risk management activities associated with the optimization of generation assets. Presented below are operating statistics related to our Dominion Generation operations.

First Quarter	2006	2005	% Change
Electricity supplied (million mwhrs)
Utility	19.5	19.9	(2)%
Merchant	11	10	10

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

	First Quarter
	2006 vs. 2005
	Increase
	(Decrease)
	Amount	EPS
(millions, except EPS)
Fuel expenses in excess of rate recovery	$(32)	$(0.09)
Outage costs	(19)	(0.05)
Regulated electric sales:
Weather	(19)	(0.05)
Customer growth	6	0.02
North Carolina rate case settlement	(10)	(0.03)
Interest expense⁽¹⁾	(9)	(0.03)
Merchant generation margins	76	0.22
RTO start-up and integration costs	3	0.01
Other	(9)	(0.03)
Share dilution	--	(0.01)
Change in net income contribution	$(13)	$(0.04)

(1)	Increase related to higher interest rates on variable rate debt.

PAGE 30

DOMINION RESOURCES, INC.

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

(Continued)

Dominion E&P

Dominion E&P manages our gas and oil exploration, development and production business. Operations are located in several major producing basins in the lower 48 states, including the outer continental shelf and deepwater areas of the Gulf of Mexico and Western Canada. Presented below are operating statistics related to our E&P operations.

First Quarter	2006	2005	% Change
Gas production (bcf)	72	74	(3)%
Oil production (million bbls)	6.1	3.8	61
Average realized prices with hedging results
Gas (per mcf)⁽¹⁾	$ 4.99	$ 4.18	19
Oil (per bbl)	38.82	28.91	34
Average realized prices without hedging results
Gas (per mcf)⁽¹⁾	7.99	6.19	29
Oil (per bbl)	53.35	44.72	19
DD&A (unit of production rate per mcfe)	$1.66	$1.42	17

bbl(s) = barrel(s)

mcf = thousand cubic feet

mcfe = thousand cubic feet equivalent

(1)	Excludes $79 million and $76 million of revenue recognized in first quarter of 2006 and 2005, respectively under the volumetric production payment (VPP) agreements described in Note 12 to our Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2005.

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

	First Quarter
	2006 vs. 2005
	Increase
	(Decrease)
	Amount	EPS
(millions, except EPS)
Operations and maintenance⁽¹⁾	$80	$0.23
Gas and oil ¾ prices	61	0.18
Gas and oil ¾ production⁽²⁾	49	0.14
DD&A	(30)	(0.09)
Business interruption insurance	(28)	(0.08)
Change in state income tax estimate⁽³⁾	(10)	(0.03)
Other	(4)	(0.01)
Share dilution	--	(0.01)
Change in net income contribution	$118	$0.33

(1)	Lower operations and maintenance expenses, primarily resulting from favorable changes in the fair value of certain gas and oil hedges that were de-designated following the 2005 hurricanes, partially offset by increased production costs.

(2)

Represents an increase in oil production primarily resulting from deepwater oil production at the Gulf of Mexico Devils Tower, Triton and Goldfinger projects, partially offset by lower gas production as compared to 2005, largely due to a reduction associated with VPP required deliveries and continued interruptions caused by the 2005 hurricanes.

(3)	Reflects increased income tax expense largely due to the effect of a revision to estimated state income tax apportionment percentages on accumulated deferred income taxes during the first quarter of 2006.

PAGE 31

DOMINION RESOURCES, INC.

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

(Continued)

Included below are the volumes and weighted average prices associated with economic hedges in place as of March 31, 2006 by applicable time period. Prior cash flow hedges for which hedge accounting was discontinued due to production interruptions caused by Hurricanes Katrina and Rita, and for which amounts were reclassified from AOCI to earnings upon the discontinuance of hedge accounting, are excluded from the following table:


	Natural Gas		Oil
Year	Hedged production (bcf)	Average hedge price (per mcf)	Hedged production (million bbls)	Average hedge price (per bbl)
2006	170.4	$4.63	10.4	$25.05
2007	212.3	5.76	10.0	33.41
2008	113.5	7.73	5.0	49.36

Corporate

Corporate includes our corporate, service company and other functions (including unallocated debt), corporate-wide enterprise commodity risk management and optimization services and the remaining assets of DCI. Presented below are the Corporate segment’s after-tax results:

	First Quarter
	2006	2005	$ Change
(millions, except EPS)
Specific items attributable to operating segments	$ (94)	$ (54)	$ (40)
DCI operations	(1)	(3)	2
Other corporate operations	4	(54)	58
Total net expense	$ (91)	$ (111)	$ 20

Earnings per share impact	$(0.27)	$(0.33)	$0.06

Other Corporate Operations

We reported a net benefit of $4 million in 2006 associated with other corporate operations as compared to net expense of $54 million in 2005 primarily reflecting a net tax benefit recorded in 2006 as a result of the pending sale of Peoples and Hope. We recognized a $201 million tax benefit from the partial reversal of previously recorded valuation allowances on deferred tax assets, representing certain federal and state tax loss carryforwards, since these carryforwards are expected to be utilized to offset capital gain income generated from the sale. This benefit was partially offset by the establishment of $141 million of deferred tax liabilities in accordance with EITF Issue No. 93-17, as discussed in Note 6 to our Consolidated Financial Statements.

Specific Items Attributable to Operating Segments

We reported expenses of $94 million and $54 million in 2006 and 2005, respectively, in the Corporate segment that are attributable to our operating segments. The net expenses in 2006 primarily reflect a $159 million ($94 million after-tax) charge resulting from the write-off of certain regulatory assets related to the pending sale of Peoples and Hope, attributable to the Dominion Delivery segment. In addition, we recognized a $21 million tax benefit from the partial reversal of previously recorded valuation allowances on certain federal and state tax loss carryforwards (attributable to Dominion Generation), since these carryforwards are expected to be utilized to offset capital gain income generated from the sale of Peoples and Hope.

The net expenses in 2005 largely resulted from:

·	A $77 million ($47 million after-tax) charge resulting from the termination of a long-term power purchase agreement, attributable to Dominion Generation; and

·	An $11 million ($6 million after-tax) charge related to our interest in a long-term power tolling contract that was divested in 2005, attributable to Dominion Generation.

PAGE 32

DOMINION RESOURCES, INC.

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

(Continued)

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, 2005 for a discussion of our energy trading, hedging and marketing activities and related accounting policies. For additional discussion of trading activities, see Market Risk Sensitive Instruments and Risk Management in Item 3.

A summary of the changes in the unrealized gains and losses recognized for our energy-related derivative instruments held for trading purposes during the three months ended March 31, 2006 follows:

	Amount
	(millions)
Net unrealized loss at December 31, 2005	$ (7)
Contracts realized or otherwise settled during the period	33
Net unrealized gain at inception of contracts initiated during the period	--
Changes in valuation techniques	--
Other changes in fair value	(31)
Net unrealized loss at March 31, 2006	$ (5)

The balance of net unrealized gains and losses recognized for our energy-related derivative instruments held for trading purposes at March 31, 2006, is summarized in the following table based on the approach used to determine fair value and contract settlement or delivery dates:

	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 ⁽¹⁾	$23	$(19)	$ (2)	$ 3	--	$ 5
Other external sources ⁽²⁾	--	(9)	2	(2)	$(1)	(10)
Total	$23	$(28)	$ --	$ 1	$(1)	$ (5)

______________________

⁽¹⁾ Exchange-traded and over-the-counter contracts.

⁽²⁾ Values based on prices from over-the-counter broker activity and industry services and, where applicable, conventional option pricing models.

Sources and Uses of Cash

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 the cash provided by operations are generally satisfied with proceeds from short-term borrowings. Long-term cash needs are met through sales of securities and additional long-term financing.

At March 31, 2006, we had cash and cash equivalents of $73 million (including $4 million classified as held for sale on our Consolidated Balance Sheet) and $3.2 billion of unused capacity under our credit facilities. As discussed in Note 14 to our Consolidated Financial Statements, the $3.2 billion of unused capacity is comprised of approximately $2.7 billion under our core credit facilities and $525 million available under bilateral credit facilities.

Operating Cash Flows

As presented on our Consolidated Statements of Cash Flows, net cash flows provided by operating activities were $984 million and $1.2 billion for the first quarter of 2006 and 2005, respectively. Management believes that our operations provide a stable source of cash flow sufficient to contribute to planned levels of capital expenditures and maintain or grow the dividend on common shares.

Our operations are subject to risks and uncertainties that may negatively impact the timing or amounts of operating cash flow. See the discussion of such factors in Operating Cash Flows in the MD&A of our Annual Report on Form 10-K for the year ended December 31, 2005.

PAGE 33

DOMINION RESOURCES, INC.

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

(Continued)

Credit Risk

Our exposure to potential concentrations of credit risk results primarily from our energy marketing and price risk management activities and sales of gas and oil production. Presented below is a summary of our gross credit exposure as of March 31, 2006 for these activities. We calculate our gross credit exposure for each counterparty as the unrealized fair value of derivative contracts plus any outstanding receivables (net of payables, where netting agreements exist), prior to the application of collateral.


		Gross Credit Exposure
		(millions)
Investment grade⁽¹⁾		$ 736
Non-investment grade⁽²⁾		20
No external ratings:
Internally rated - investment grade⁽³⁾		113
Internally rated - non-investment grade⁽⁴⁾		224
Total		$ 1,093

_______________________

(1) Designations as investment grade are based on minimum credit ratings assigned by Moody’s Investor Services (Moody’s) and Standard & Poor’s Rating Group (Standard & Poor’s). The five largest counterparty exposures, combined, for this category represented approximately 15% of the total gross credit exposure.

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

(3) The five largest counterparty exposures, combined, for this category represented approximately 10% of the total gross credit exposure.

(4) The five largest counterparty exposures, combined, for this category represented approximately 5% of the total gross credit exposure.

Investing Cash Flows

In the first quarter of 2006 and 2005, investing activities resulted in net cash outflows of $986 million and $958 million, respectively. Significant investing activities in the first quarter of 2006 included:

·	$484 million of capital expenditures for the purchase and development of gas and oil producing properties, drilling and equipment costs and undeveloped lease acquisitions;

·	$439 million of capital expenditures for the construction and expansion of generation facilities, environmental upgrades, purchase of nuclear fuel, and construction and improvements of gas and electric transmission and distribution assets;

·	$281 million for the purchase of securities; and

·	$91 million related to the acquisition of Pablo Energy LLC, net of cash acquired; partially offset by

·	$273 million from the sale of securities.

Financing Cash Flows and Liquidity

We rely on banks and capital markets as a significant source of funding for capital requirements not satisfied by cash provided by our operations. As discussed further in the Credit Ratings and Debt Covenants section below, 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 and, in the case of Virginia Power, obtaining regulatory approval from the Virginia State Corporation Commission (Virginia Commission).

In December 2005, the SEC adopted rules that modify the registration, communication and offering processes under the Securities Act of 1933 (Securities Act). The rules streamline the shelf registration process to provide registrants with more timely access to capital. Under the new rules, Dominion and Virginia Power meet the definition of a well-known seasoned issuer. This allows them to use an automatic shelf registration statement to register offerings of securities for cash proceeds. CNG meets the definition of a seasoned issuer, and as such their filings remain subject to review by the SEC.

PAGE 34

DOMINION RESOURCES, INC.

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

(Continued)

As presented on our Consolidated Statements of Cash Flows, net cash used in financing activities was $71 million and $371 million for the first quarter of 2006 and 2005, respectively.

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

Credit Ratings and Debt Covenants

Credit ratings are intended to provide banks and capital market participants with a framework for comparing the credit quality of securities and are not a recommendation to buy, sell or hold securities. In the Credit Ratings and Debt Covenants sections of MD&A in our Annual Report on Form 10-K for the year ended December 31, 2005, we discussed the use of capital markets by Virginia Power, CNG and us (the Dominion Companies), 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 the Dominion Companies’ debt. As of May 1, 2006, our credit ratings reflect Moody’s downgrade of its credit ratings for the Dominion Companies’ long-term debt and short-term commercial paper. Moody’s concluded that the reason for the downgrade was attributable to recent financial performance that was weaker than expected, a decline in funds from operations and higher than expected leverage as of December 31, 2005. In April 2006, Fitch Ratings (Fitch) affirmed its BBB+ rating of the Dominion Companies and defined the outlook for the Dominion Companies as stable. There have been no other changes in the Dominion Companies’ credit ratings nor changes to or events of default under our debt covenants.

Presented below is a summary of credit ratings for the Dominion Companies as of May 1, 2006:

	Fitch	Moody’s	Standard & Poor’s
Dominion Resources, Inc.
Senior unsecured debt securities	BBB+	Baa2	BBB
Preferred securities of affiliated trusts	BBB	Baa3	BB+
Commercial paper	F2	P-2	A-2
Virginia Power
Mortgage bonds	A	A3	A-
Senior unsecured (including tax-exempt) debt securities	BBB+	Baa1	BBB
Preferred securities of affiliated trust	BBB	Baa2	BB+
Preferred stock	BBB	Baa3	BB+
Commercial paper	F2	P-2	A-2
CNG
Senior unsecured debt securities	BBB+	Baa1	BBB
Preferred securities of affiliated trust	BBB	Baa2	BB+
Commercial paper	F2	P-2	A-2

Future Cash Payments for Contractual Obligations

As of March 31, 2006, there have been no material changes outside the ordinary course of business to the contractual obligations disclosed in MD&A in our Annual Report on Form 10-K for the year ended December 31, 2005.

Use of Off-Balance Sheet Arrangements

As of March 31, 2006, there have been no material changes related to the use of off-balance sheet arrangements disclosed in MD&A in our Annual Report on Form 10-K for the year ended December 31, 2005.

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DOMINION RESOURCES, INC.

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

(Continued)

Future Issues and Other Matters

The following discussion of future issues and other information includes current developments of previously disclosed matters and new issues arising during the period covered by and subsequent to our Consolidated Financial Statements. This section should be read in conjunction with Future Issues and Other Matters in our Annual Report on Form 10-K for the year ended December 31, 2005.

Virginia Fuel Factor

In April 2006, the Virginia General Assembly passed Senate Bill 262, a substitute energy bill with a provision that would change the way our Virginia jurisdictional fuel factor is set during the three and one-half year period beginning July 1, 2007.

The proposed fuel factor amendment:

·	Allows annual fuel rate adjustments for three twelve-month periods beginning July 1, 2007 and one six-month period beginning July 1, 2010 (unless capped rates are terminated earlier under the Virginia Restructuring Act);

·	Allows a “true-up” at the end of each of the twelve-month periods to account for differences between projections and actual recovery of fuel costs during the prior twelve months; and

·	Authorizes the Virginia Commission to defer up to 40% of any fuel factor increase approved for the first twelve-month period, with recovery of the deferred amount over the two and one-half year period beginning July 1, 2008 (under current law, such a deferral is not possible).

The amendment would not allow us to collect any unrecovered fuel expenses incurred prior to July 1, 2007. The Governor of Virginia has until May 19, 2006 to act on the bill. With the Governor’s signature, the bill would become law effective July 1, 2006.

Forward Capacity Market Settlement

Our New England generation plants participate in a market administered by the New England Independent System Operator (ISO-NE). In March 2006, ISO-NE and a broad cross-section of critical stakeholders from around the region filed a comprehensive settlement agreement at the FERC implementing a Forward Capacity Market in place of Locational Installed Capacity. The settlement agreement is contested and must be approved by FERC. The parties have requested such approval by June 30, 2006. If approved without modification, we expect the settlement to result in increased revenue opportunities for the December 2006 to June 2010 time period. We cannot, however, predict whether the settlement will be approved by FERC without modification nor can we predict whether FERC will implement the settlement by the date requested.

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DOMINION RESOURCES, INC.

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, Management’s Discussion and Analysis of Financial Condition and Results of Operations 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, foreign currency exchange rates and equity security prices as described below. Commodity price risk is present in our electric operations, gas and oil production and procurement operations, and energy marketing and trading operations due to the exposure to market shifts in prices received and paid for natural gas, oil, electricity and other commodities. We use derivative commodity contracts to manage price risk exposures for these operations. Interest rate risk is generally related to our outstanding debt. We are exposed to foreign currency exchange rate risks related to our purchases of fuel and fuel services denominated in foreign currencies. In addition, we are exposed to equity price risk through various portfolios of equity securities.

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

Commodity Price Risk

We manage price risk associated with purchases and sales of natural gas, oil, electricity and certain other commodities using commodity-based financial derivative instruments held for non-trading purposes. 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 risk are executed within established policies and procedures and include instruments such as futures, forwards, swaps and options that are sensitive to changes in the related commodity prices. For sensitivity analysis purposes, the fair value 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 actively quoted 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 $657 million and $691 million as of March 31, 2006 and December 31, 2005, respectively. A hypothetical 10% unfavorable change in commodity prices would have resulted in a decrease of approximately $26 million and $3 million in the fair value of our commodity-based financial derivative instruments held for trading purposes as of March 31, 2006 and December 31, 2005, 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 derivative commodity instruments used for hedging purposes, to the extent realized, will generally be offset by recognition of the hedged transaction, such as revenue from sales.

Interest Rate Risk

We manage our interest rate risk exposure predominantly by maintaining a balance of fixed and variable rate debt. We also enter into interest rate sensitive derivatives, including interest rate swaps and interest rate lock agreements. For financial instruments outstanding at March 31, 2006 and December 31, 2005, a hypothetical 10% increase in market interest rates would decrease annual earnings by approximately $19 million and $20 million, respectively.

In addition, we retain ownership of mortgage investments, including subordinated bonds and interest-only residual assets retained from securitizations of mortgage loans originated and purchased in prior years. Note 27 to our Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2005 discusses the impact of changes in value of these investments.

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DOMINION RESOURCES, INC.

ITEM 3. QUANTITATIVE AND QUALITATIVE

DISCLOSURES ABOUT MARKET RISK

(Continued)

Foreign Currency Exchange Risk

Our Canadian natural gas and oil exploration and production activities are relatively self-contained within Canada. As a result, our exposure to foreign currency exchange risk for these activities is limited primarily to the effects of translation adjustments that arise from including that operation in our Consolidated Financial Statements. We monitor this exposure and believe it is not material. In addition, we have foreign exchange risk exposure associated with anticipated future purchases of nuclear fuel and nuclear fuel processing services denominated in foreign currencies. We manage certain of these risks by utilizing currency forward contracts. As a result of holding these contracts as hedges, our exposure to foreign currency risk is minimal. A hypothetical 10% unfavorable change in relevant foreign exchange rates would have resulted in a decrease of approximately $6 million and $8 million in the fair value of currency forward contracts held by us at March 31, 2006 and December 31, 2005, respectively.

Investment Price Risk

We are subject to investment price risk due to marketable securities held as investments in decommissioning trust funds. These marketable securities are reported on our Consolidated Balance Sheets at fair value. We recognized net realized gains (including investment income) on nuclear decommissioning trust investments of $25 million for the three months ended March 31, 2006 and $67 million for the year ended December 31, 2005. We recorded, in AOCI, net unrealized gains on decommissioning trust investments of $38 million for the three months ended March 31, 2006 and $27 million for the year ended December 31, 2005.

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

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DOMINION RESOURCES, INC.

ITEM 4. CONTROLS AND PROCEDURES

Senior management, including the Chief Executive Officer and Chief Financial Officer, 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 Chief Executive Officer and Chief Financial Officer have concluded that Dominion’s disclosure controls and procedures are effective. There were no changes in Dominion’s internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, Dominion’s internal control over financial reporting.

In accordance with FIN 46R, we have included in our Consolidated Financial Statements certain VIEs through which we have financed and leased several power generation projects as well as our corporate headquarters and aircraft. Our Consolidated Balance Sheet as of March 31, 2006 reflects $592 million of net property, plant and equipment and deferred charges and $688 million of related debt attributable to the VIEs. As these VIEs are owned by unrelated parties, we do not have the authority to dictate or modify, and therefore cannot assess, the disclosure controls and procedures or internal control over financial reporting in place at these entities.

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DOMINION RESOURCES, INC.

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 and Environmental Matters in Note 16 to our Consolidated Financial Statements for discussions on various environmental and other regulatory proceedings to which we are a party.

In March 2006, Peoples and Equitable Resources, Inc. (Equitable) filed a joint petition with the Pennsylvania Public Utility Commission seeking approval of the purchase by Equitable of all of the stock of Peoples and Hope. In April 2006, Hope and Equitable filed a joint petition seeking West Virginia Public Service Commission approval of the purchase by Equitable of all of the stock of Hope.

Dominion Transmission Inc. (DTI) has reached an agreement in principle on a proposed Consent Order and Agreement (COA) with the Pennsylvania Department of Environmental Protection (PADEP) which would supersede a 1990 COA between the parties. The agreement in principle resolves longstanding groundwater contamination issues at several DTI compressor stations in Pennsylvania and includes a penalty of $850,000 to be paid to PADEP and the Pennsylvania Department of Conservation and Natural Resources to resolve alleged violations. Negotiations are ongoing with both agencies to finalize language and payment mechanisms. As of March 31, 2006, DTI has accrued $850,000 for the penalty.

In March 2004, the State of North Carolina filed a petition with the EPA under Section 126 of the Clean Air Act seeking additional nitrogen oxide and sulfur dioxide reductions from electrical generating units in thirteen states, claiming emissions from the electrical generating units in those states are contributing to air quality problems in North Carolina. We have electrical generating units in six of the thirteen states. In March 2006, the EPA issued a final rulemaking through which it denied the North Carolina petition on the basis that the implementation of the Clean Air Interstate Rule adequately addresses the air quality issues identified by North Carolina. Therefore, we do not anticipate additional expenditures in relation to this matter.

Before being acquired by us, Louis Dreyfus Natural Gas Corp. (Louis Dreyfus) was one of numerous defendants in a lawsuit consolidated and pending in the 93^rd Judicial Court in Hidalgo County, Texas. The lawsuit alleged that gas wells and related pipeline facilities operated by Louis Dreyfus and other facilities operated by other defendants caused an underground hydrocarbon plume in McAllen, Texas. In April 2006, we entered into a settlement agreement with the plaintiffs resolving all of their claims against us. We remain subject, however, to a cross-claim and potential indemnity issues with certain of the other defendants that were not a part of the settlement. We do not expect the resolution of these remaining claims to have a material adverse effect on our results of operations or financial condition.

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DOMINION RESOURCES, INC.

PART II. OTHER INFORMATION

(Continued)

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, 2005, which factors should be taken into consideration when reviewing the information contained in this report. With the exception of the risk factors below, which have been modified to take into account certain recent changes to the Virginia fuel factor regulations, a March 2006 downgrade by Moody’s to our credit rating, as well as recent developments relating to business interruption insurance, there have been no material changes with regard to the risk factors previously disclosed in our most recent Form 10-K. For other factors that may cause actual results to differ materially from those indicated in any forward-looking statement or projection contained in this report, see Forward-Looking Statements in MD&A.

We are exposed to cost-recovery shortfalls because of capped base rates and amendments to the fuel factor statute in effect in Virginia. Under the Virginia Restructuring Act, as amended in 2004, our base rates (excluding, generally, a fuel factor with limited adjustment provisions, and certain other allowable adjustments) remain capped through December 31, 2010 unless modified or terminated consistent with the Virginia Restructuring Act. Although the Virginia Restructuring Act allows for the recovery of certain generation-related costs during the capped rates period, we remain exposed to numerous risks of cost-recovery shortfalls. These include exposure to stranded costs, future environmental compliance requirements, certain tax law changes, costs related to hurricanes or other weather events, inflation, the cost of obtaining replacement power during unplanned plant outages and increased capital costs.

In addition, under the 2004 amendments to the Virginia fuel factor statute, our current Virginia fuel factor provisions are locked-in until the earlier of July 1, 2007 or the termination of capped rates by order of the Virginia Commission, with no deferred fuel accounting. The 2004 amendments provide for a one-time adjustment of our fuel factor, effective July 1, 2007 through December 31, 2010 (unless capped rates are terminated earlier), with no adjustment for previously incurred over-recovery or under-recovery. In April 2006, the Virginia General Assembly approved Senate Bill 262 further amending the fuel factor statute. If signed by the Governor, Senate Bill 262 will institute annual fuel rate adjustments for three 12-month periods beginning July 1, 2007 and one six-month period beginning July 1, 2010. Beginning with the July 1, 2008 adjustment, the recalculation of the fuel factor would account for differences between projections and actual recovery of fuel costs during the preceding twelve-month period. As a result of the current locked-in fuel factor we are exposed to fuel price and other risks. These risks include exposure to increased costs of fuel, including purchased power costs, differences between our projected and actual power generation mix and generating unit performance (which affects the types and amounts of fuel we use) and differences between fuel price assumptions and actual fuel prices.

Changing rating agency requirements could negatively affect our growth and business strategy. As of May 1, 2006, Dominion’s senior unsecured debt is rated BBB, stable outlook, by Standard & Poor’s Rating Group (Standard & Poor’s); Baa2, stable outlook, by Moody’s Investors Services (Moody’s); and BBB+, stable outlook, by Fitch Ratings Ltd. (Fitch). In order to maintain our current credit ratings in light of existing or future requirements, we may find it necessary to take steps or change our business plans in ways that may adversely affect our growth and earnings per share. A reduction in Dominion’s credit ratings or the credit ratings of our Virginia Power and CNG subsidiaries by Standard & Poor’s, Moody’s or Fitch could increase our borrowing costs and adversely affect operating results and could require us to post additional collateral in connection with some of our trading and marketing activities.

Our exploration and production business is dependent on factors that cannot be predicted or controlled and that could damage facilities, disrupt production or reduce the book value of our assets. Factors that may affect our financial results include damage to or suspension of operations caused by weather, fire, explosion or other events to our or third party gas and oil facilities, fluctuations in natural gas and crude oil prices, results of future drilling and well completion activities and our ability to acquire additional land positions in competitive lease areas, as well as inherent operational risks that could disrupt production.

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DOMINION RESOURCES, INC.

PART II. OTHER INFORMATION

(Continued)

ITEM 1A. RISK FACTORS

(Continued)

Short-term market declines in the prices of natural gas and oil could adversely affect our financial results by causing a permanent write-down of our natural gas and oil properties as required by the full cost method of accounting. Under the full cost method, all direct costs of property acquisition, exploration and development activities are capitalized. If net capitalized costs exceed the present value of estimated future net revenues based on hedge-adjusted period-end prices from the production of proved gas and oil reserves (the ceiling test) at the end of any quarterly period, then a permanent write-down of the assets must be recognized in that period.

We maintain business interruption insurance for offshore operations associated with our exploration and production business. We have placed our insurers on notice that we have suffered substantial property damage and business interruption loss related to Hurricanes Katrina and Rita. We are aware that during the claim adjusting process, certain underwriters will take positions adverse to coverage for various parts of the claim. A failure to realize the full value of our claims could negatively affect our results of operations. Additionally, the increased level of hurricane activity in the Gulf of Mexico is likely to significantly increase the cost of business interruption insurance, reduce its availability and may make it unavailable on commercially reasonable terms. Inability to insure our offshore Gulf of Mexico operations, or the more limited coverage of alternative options, could adversely affect our results of operations.

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DOMINION RESOURCES, INC.

PART II. OTHER INFORMATION

(continued)

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

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

ISSUER PURCHASES OF EQUITY SECURITIES

Period	(a) Total Number of Shares (or Units) Purchased	(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 Program
1/1/06-1/31/06	1,970⁽¹⁾	$78.42	N/A	21,275,000 shares/ $1.72 billion
2/1/06-2/28/06	1,647⁽¹⁾	$75.03	N/A	21,275,000 shares/ $1.72 billion
3/1/06-3/31/06	199⁽¹⁾	$72.10	N/A	21,275,000 shares/ $1.72 billion
Total	3,816	$76.63	N/A	21,275,000 shares/ $1.72 billion

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

Issuance of Unregistered Securities

In February 2006, we issued 120 shares of common stock to a former employee as a deferred payment under a 1985 performance achievement plan. These shares were not registered under the Securities Act. The issuance of this stock did not involve a public offering, and is therefore exempt from registration under Section 4(2) of the Securities Act.

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DOMINION RESOURCES, INC.

PART II. OTHER INFORMATION

(continued)

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Our Annual Shareholders' Meeting was held on April 28, 2006. Results of items presented for voting are listed below.

Election of Directors

Directors were elected to the Board of Directors for a one-year term or until next year’s annual meeting.

Nominee	Votes For	Votes Withheld

Peter W. Brown	293,731,199	6,028,498
Ronald J. Calise	295,524,168	4,235,529
Thos. E. Capps	292,825,745	6,933,952
George A. Davidson, Jr.	294,452,466	5,307,231
Thomas F. Farrell, II	293,833,299	5,926,398
John W. Harris	295,492,426	4,267,271
Robert S. Jepson, Jr.	295,208,868	4,550,829
Mark J. Kington	295,459,674	4,300,023
Benjamin J. Lambert, III	293,922,380	5,837,317
Richard L. Leatherwood	294,100,159	5,659,538
Margaret A. McKenna	295,281,793	4,477,904
Frank S. Royal	290,434,617	9,325,080
S. Dallas Simmons	293,585,144	6,174,553
David A. Wollard	295,064,541	4,695,156

Appointment Of Auditors

The appointment of Deloitte & Touche LLP as our independent auditors for 2006 was ratified by shareholders as follows:

Votes For	Votes Against	Votes Abstained
294,932,317	2,544,876	2,282,504

Shareholder Proposals

Shareholders did not approve a proposal requesting that our articles of incorporation be amended to require director nominees be elected by majority vote of shareholders. The vote was as follows:

Votes For	Votes Against	Votes Abstained	Broker Non-Votes
116,145,914	133,655,710	4,997,247	44,960,826

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DOMINION RESOURCES, INC.

PART II. OTHER INFORMATION

(continued)

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

(continued)

Shareholders did not approve a proposal requesting a report to shareholders on how we are responding to regulatory and public pressure to reduce carbon dioxide and other emissions. The vote was as follows:

Votes For	Votes Against	Votes Abstained	Broker Non-Votes
52,266,689	179,459,569	23,074,000	44,959,439

Shareholders did not approve a proposal requesting that shareholders approve any future extraordinary retirement benefits for senior executives. The vote was as follows:

Votes For	Votes Against	Votes Abstained	Broker Non-Votes
72,023,771	177,932,789	4,843,665	44,959,472

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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).
	3.2	Bylaws as in effect on October 20, 2000 (Exhibit 3, Form 10-Q for the quarter ended September 30, 2000, File No. 1-8489, incorporated by reference).
	4	Dominion Resources, Inc. agrees to furnish to the Securities and Exchange Commission upon request any other instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of its total consolidated assets.
	10.1	$3.0 billion Five-Year Credit Agreement dated February 28, 2006 among Dominion Resources, Inc., Virginia Electric and Power Company, Consolidated Natural Gas Company, JPMorgan Chase Bank, N.A., as Administrative Agent, Citibank, N.A., as Syndication Agent and Barclays Bank PLC, The Bank of Nova Scotia and Wachovia Bank, National Association, as Co-Documentation Agents and other lenders named therein. (Exhibit 10.1, Form 8-K filed March 3, 2006, File No. 1-8489, incorporated by reference).
	10.2	$1.70 billion Amended and Restated Five-Year Credit Agreement dated February 28, 2006 among Consolidated Natural Gas Company, Barclays Bank PLC, as Administrative Agent, Barclays Bank PLC and KeyBank National Association, as Syndication Agents, and SunTrust Bank, The Bank of Nova Scotia and ABN AMRO Bank N.V., as Co-Documentation Agents and other lenders as named therein. (Exhibit 10.2, Form 8-K filed March 3, 2006, File No. 1-8489, incorporated by reference).
	10.3	$1.05 billion 364-Day Credit Agreement dated February 28, 2006 among Consolidated Natural Gas Company, Barclays Bank PLC, as Administrative Agent, Barclays Bank PLC and KeyBank National Association, as Syndication Agents, The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch and Mizuho Corporate Bank, Ltd., as Co-Documentation Agents and other lenders as named therein. (Exhibit 10.3, Form 8-K filed March 3, 2006, File No. 1-8489, incorporated by reference).
	10.4	2006 Long-Term Compensation Program - Form of Restricted Stock Grant (Exhibit 10.1, Form 8-K filed April 4, 2006, File No. 1-8489, incorporated by reference).
	10.5	2006 Long-Term Compensation Program - Form of Performance Grant (Exhibit 10.2, Form 8-K filed April 4, 2006, File No. 1-8489, incorporated by reference).
	12	Ratio of earnings to fixed charges (filed herewith).
	31.1	Certification by Registrant’s Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
	31.2	Certification by Registrant’s Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).
	32	Certification to the Securities and Exchange Commission by Registrant’s Chief Executive Officer and Chief Financial Officer, as required by Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).
	99	Condensed consolidated earnings statements (unaudited) (filed herewith).

SIGNATURE

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

	DOMINION RESOURCES, INC. Registrant

May 3, 2006	/s/ Steven A. Rogers
	Steven A. Rogers Senior Vice President and Controller (Principal Accounting Officer)