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. As of September 30, 2006, Virginia Power served 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 wholesale electricity 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. As of September 30, 2006, its regulated gas distribution subsidiaries served 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 served approximately 1.4 million residential and commercial customer accounts in the Northeast, Mid-Atlantic and Midwest regions of the United States. CNG also operates an interstate gas transmission pipeline system, underground natural gas storage system and gathering and extraction facilities in the Northeast, Mid-Atlantic and Midwest states 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 us and our legal subsidiaries.

The terms “Dominion,” “Company,” “we,” “our” and “us” are used throughout this report and, depending on the context of their use, may represent any of the following: the legal entity, Dominion Resources, Inc., one 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 and our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2006 and June 30, 2006.

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 September 30, 2006, our results of operations for the three and nine months ended September 30, 2006 and 2005, and our cash flows for the nine months ended September 30, 2006 and 2005.

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

Our accompanying unaudited Consolidated Financial Statements include, after eliminating intercompany transactions and balances, our accounts and those of our majority-owned subsidiaries and those variable interest entities (VIEs) where we have 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 were not 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 and nine months ended September 30, 2005, if we had applied the fair value recognition provisions of SFAS No. 123 to stock-based employee compensation:

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. Approximately $2 million of excess tax benefits were realized for the nine months ended September 30, 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 and nine months ended September 30, 2006, we recognized approximately $1 million and $4 million, respectively, of compensation cost related to awards previously granted to retirement eligible employees. At September 30, 2006 unrecognized compensation cost for restricted stock awards held by retirement eligible employees totaled approximately $7 million.

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 and to facilitate gas transportation. In September 2005, the Financial Accounting Standards Board (FASB) ratified the Emerging Issues Task Force’s (EITF) consensus on Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty , that requires 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. We adopted the provisions of EITF 04-13 on April 1, 2006 for new arrangements entered into, and modifications or renewals of existing arrangements after that date. As a result, a significant portion of our activity related to buy/sell arrangements is presented on a net basis in our Consolidated Statement of Income for the three months and nine months ended September 30, 2006; however, there was no impact on our results of operations or cash flows. Pursuant to the transition provisions of EITF 04-13, activity related to buy/sell arrangements that were entered into prior to April 1, 2006 and have not been modified or renewed after that date continue to be reported on a gross basis and are summarized below:

(1)   Included in other energy-related commodity purchases expense and purchased gas expense on our Consolidated Statements of Income.

Note 4.     Recently Issued Accounting Standards

SFAS No. 158

In September 2006, the FASB issued SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans . SFAS No. 158 requires an employer to recognize the overfunded or underfunded status of their benefit plans as an asset or liability in its balance sheet and to recognize changes in that funded status in the year in which the changes occur as a component of other comprehensive income. The funded status is measured as the difference between the fair value of the plan’s assets and its benefit obligation. In addition, SFAS No. 158 requires an employer to measure benefit plan assets and obligations that determine the funded status of a plan as of the end of its fiscal year, which we already do. The prospective requirement to recognize the funded status of a benefit plan and to provide the required disclosures will become effective for us on December 31, 2006. The adoption of SFAS No. 158 will have no impact on our results of operations or cash flows. Application of this standard at December 31, 2006, is expected to reduce common shareholders' equity, however the amount of the impact will depend on the measurement of pension and other postretirement benefit plan assets and liabilities at that date.

SAB 108

In September 2006, the SEC issued Staff Accounting Bulletin (SAB) No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements . SAB 108 provides guidance on how prior year misstatements should be taken into consideration when quantifying misstatements in current year financial statements for purposes of determining whether the current year’s financial statements are materially misstated. The provisions of SAB 108 are required to be applied beginning December 31, 2006. We do not expect the adoption of SAB 108 to impact our Consolidated Financial Statements.

SFAS No. 155

In February 2006, the 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.

FIN 48

In July 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes (FIN 48). FIN 48 establishes standards for measurement and recognition in financial statements of positions taken by an entity in its income tax returns. In addition, FIN 48 requires new disclosures about positions taken by an entity in its tax returns that are not recognized in its financial statements, information about potential significant changes in estimates related to tax positions and descriptions of open tax years by major jurisdiction. The provisions of FIN 48 will become effective for us beginning January 1, 2007, with the cumulative effect of the change in accounting principle recorded as an adjustment to retained earnings. We are currently evaluating the impact that FIN 48 will have on our results of operations and financial condition.

SFAS No. 157

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements , which defines fair value, establishes a framework for measuring fair value and expands disclosures related to fair value measurements. SFAS No. 157 clarifies that fair value should be based on assumptions that market participants would use when pricing an asset or liability and establishes a fair value hierarchy of three levels that prioritizes the information used to develop those assumptions. The fair value hierarchy gives the highest priority to quoted prices in active markets and the lowest priority to unobservable data. SFAS No. 157 requires fair value measurements to be separately disclosed by level within the fair value hierarchy. The provisions of SFAS No. 157 will become effective for us beginning January 1, 2008. Generally, t he provisions of this statement are to be applied prospectively. Certain situations, however, require retrospective application as of the beginning of the year of adoption through the recognition of a cumulative effect of accounting change. Such retrospective application is required for financial instruments, including derivatives and certain hybrid instruments with limitations on initial gains or losses under EITF Issue 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities , and SFAS No. 155 , Accounting for Certain Hybrid Financial Instruments . We are currently evaluating the impact that SFAS No. 157 will have on our results of operations and financial condition.

Note 5.   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:

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	September 30, 2006
(millions)
ASSETS
Current Assets
Cash	$    2
Customer accounts receivable	93
Unrecovered gas costs	28
Other	126
Total current assets	249
Investments	2
Property, Plant and Equipment
Property, plant and equipment	1,119
Accumulated depreciation, depletion and amortization	(379)
Total property, plant and equipment, net	740
Deferred Charges and Other Assets
Regulatory assets	100
Other	1
Total deferred charges and other assets	101
Assets held for sale	$1,092
LIABILITIES
Current Liabilities
Accounts payable	$   68
Payables to affiliates	23
Deferred income taxes	13
Other	95
Total current liabilities	199
Deferred Credits and Other Liabilities
Asset retirement obligations	33
Deferred income taxes	166
Regulatory liabilities	26
Other	11
Total deferred credits and other liabilities	236
Liabilities held for sale	$  435

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

In the nine months ended September 30, 2006, we recognized a $167 million ($103 million after-tax) charge, recorded in other operations and maintenance expense in our Consolidated Statement 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 assets is no longer probable. We also established $136 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 the financial reporting basis over the tax basis of a parent’s investment in a subsidiary be recognized when it is apparent that this difference will reverse in the foreseeable future. We recorded an adjustment since the financial reporting basis of our investment in Peoples and Hope exceeds our tax basis. This 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 E&P 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 in accordance with EITF 03-13, 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.

For the three months ended September 30, 2005, the income tax benefit and negative effective tax rate primarily reflected the effects of the substantial decrease in income before income taxes and the items identified above that result in differences in the reported provision for income taxes, as compared to the amount calculated at the U.S. statutory rate.

For the nine months ended September 30, 2006, the reduction in valuation allowances reflects the expected utilization of federal and state tax loss carryforwards to offset capital gain income that will be generated from the pending sale of Peoples and Hope, partially offset by valuation allowance increases primarily associated with the deferred tax asset recognized as a result of the impairment of a DCI investment, as discussed in Note 20. The effect of the decrease to valuation allowances was partially offset by the establishment 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 93-17.

(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 4.3 million common shares for the three months ended September 30, 2005 and 1.0 million and 2.9 million common shares for the nine months ended September 30, 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. There were no such anti-dilutive securities outstanding during the three months ended September 30, 2006.

(1)	Largely due to the settlement of certain commodity derivative contracts and favorable changes in fair value, primarily resulting from a decrease in electricity and gas prices.

(2)	Principally due to unfavorable changes in the fair value of certain commodity derivatives resulting from an increase in commodity prices.

(3)	Primarily reflects the impact of both unrealized gains and losses on investments held in nuclear decommissioning trusts and foreign currency translation adjustments.

 

(1)	Represents hedge ineffectiveness, primarily due to changes in the fair value differential between the delivery location and commodity specifications of derivatives held by our E&P operations and the delivery location and commodity specifications of our forecasted gas and oil sales.

Gains and losses on hedging instruments that were excluded from the measurement of effectiveness and included in net income for the three and nine months ended September 30, 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 accumulated other comprehensive income (loss) (AOCI) to earnings in March 2005.

Additionally, due to interruptions in Gulf of Mexico and south Louisiana   gas and   oil production caused by Hurricanes Katrina and Rita, we discontinued hedge accounting for certain cash flow hedges in August and September 2005 since it became probable that the forecasted sales of gas and oil would not occur. In connection with the discontinuance of hedge accounting for these contracts, we reclassified $423 million ($272 million after-tax) of losses from AOCI to earnings in the third quarter of 2005.

The following table presents selected information related to c ash flow hedges included in AOCI in our Consolidated Balance Sheet at September 30, 2006:  

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 11.     Ceiling Test

We follow the full cost method of accounting for gas and oil E&P activities prescribed by the SEC. Under the full cost method, capitalized costs are subject to a quarterly ceiling test. Under the ceiling test, amounts capitalized are limited to the present value of estimated future net revenues to be derived from the anticipated production of proved gas and oil reserves, assuming period-end hedge-adjusted prices. The ceiling test is prepared on a separate country basis for our U.S. and Canadian cost centers.

Approximately 9% of our U.S. 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 for our U.S. cost center as of September 30, 2006.

Approximately 9% of our anticipated Canadian production is hedged by qualifying cash flow hedges, for which hedge-adjusted prices were used to calculate estimated future net revenue. There was no ceiling test impairment for our Canadian cost center as of September 30, 2006, using hedge-adjusted prices. Calculation of the Canadian cost center ceiling without qualifying cash flow hedges would yield an impairment against book value of approximately $3 million after tax.