Exhibit 99.1

DEPI, Dominion Reserves and DTI Exploration

and Production

Combined Financial Statements for the years ended December 31, 2009, 2008 & 2007

and

Independent Auditors’ Report

CONTENTS

	Page Number
Independent Auditors’ Report	3
Combined Statements of Income for the years ended December 31, 2009, 2008 and 2007	4
Combined Balance Sheets at December 31, 2009 and 2008	5
Combined Statements of Cash Flows for the years ended December 31, 2009, 2008 and 2007	7
Combined Statements of Shareholders’ Equity and Comprehensive Income at December 31, 2009, 2008 and 2007 and for the years then ended	8
Notes to Combined Financial Statements	9

2

INDEPENDENT AUDITORS’ REPORT

To the Board of Directors and Shareholders of

Dominion Resources, Inc.

Richmond, VA

We have audited the accompanying combined balance sheet of Dominion Exploration and Production Inc. and subsidiaries, Dominion Reserves Inc. and subsidiaries, and the producing business of Dominion Transmission Inc. (collectively “the Combined Companies”), all of which are under common ownership and common management, as of December 31, 2009 and December 31, 2008, and the related combined statements of income and shareholders’ equity and comprehensive income and of cash flows for each of the three years in the period ended December 31, 2009. These combined financial statements are the responsibility of the Combined Companies’ management. Our responsibility is to express an opinion on these combined financial statements based on our audits.

We conducted our audits in accordance with generally accepted auditing standards as established by the Auditing Standards Board (United States) and in accordance with the auditing standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Combined Companies were not required to have, nor were we engaged to perform, an audit of their internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Combined Companies’ internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, such combined financial statements present fairly, in all material respects, the combined financial position of the Combined Companies as of December 31, 2009 and December 31, 2008, and the combined results of their operations and their combined cash flows for each of the three years then ended in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 3 to the combined financial statements, the Combined Companies changed its methods of accounting to adopt new accounting standards for oil and gas accounting and reporting in 2009 and fair value measurements in 2008.

/s/ Deloitte & Touche LLP

Richmond, Virginia

March 14, 2010

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Dominion Exploration & Production

Combined Statements of Income

Year Ended December 31,	2009			2008			2007
(thousands)
Operating Revenue
Affiliated sales, net	$	298,599		$	361,907		$	415,635
Other(1)		44,358			(314	)		211,119
Total operating revenue	$	342,957		$	361,593		$	626,754
Operating Expenses
Purchased commodities:
Affiliated suppliers		—			—			39,664
Other		—			—			45,060
Production (lifting)		66,115			69,815			248,441
General and administrative:
Affiliated services		19,648			22,975			54,271
Other		16,740			29,920			131,518
Ceiling test impairment		282,775			—			—
Depreciation, depletion and amortization		72,497			84,350			295,656
Total operating expenses		457,775			207,060			814,610
Gain on sale of non-Appalachian E&P business		—			—			(3,175,618	)
Income (loss) from operations		(114,818	)		154,533			2,987,762
Other Expense
Net interest expense (income):
Affiliated		35,125			36,687			42,368
Other		(941	)		(1,800	)		(14,018	)
Total other expense		34,184			34,887			28,350
Income (loss) before income taxes		(149,002	)		119,646			2,959,412
Income taxes		(61,394	)		41,856			1,111,125
Net Income (Loss)	$	(87,608	)	$	77,790		$	1,848,287

(1) The Other losses in 2008 are due to losses on derivative positions with non-affiliates of $28 million.

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

4

Dominion Exploration & Production

Combined Balance Sheets

At December 31,	2009			2008
(thousands)
ASSETS
Current Assets
Cash and cash equivalents	$	36		$	3
Accounts receivables:
Customer		8,665			11,718
Affiliate		27,534			37,775
Other receivables (less allowance for doubtful accounts of $4,909 and $4,410)		3,392			42,036
Affiliated advances		—			362,100
Derivative assets:
Affiliate		45,655			56,398
Non-affiliate		—			19,612
Prepayments		7,309			18,063
Other		3,405			16,461
Total current assets		95,996			564,166
Investments		925			828
Property, Plant and Equipment (full cost method)
Proved properties		1,668,586			1,515,633
Unproved properties		8,416			10,838
Other		6,344			19,282
Total property, plant and equipment		1,683,346			1,545,753
Accumulated depreciation, depletion and amortization		(678,476	)		(329,628	)
Net property, plant and equipment		1,004,870			1,216,125
Deferred Charges and Other Assets
Affiliated employer benefit assets		20,240			20,790
Affiliated derivative assets		3,131			20,589
Noncurrent income taxes receivable and other assets		32,069			21,530
Total deferred charges and other assets		55,440			62,909
Total assets	$	1,157,231		$	1,844,028

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

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At December 31,	2009			2008
(thousands)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	36,282		$	43,591
Payables to affiliates		2,090			233,879
Affiliated current borrowings		115,579			182,374
Accrued interest, payroll and taxes		40,723			38,815
Deferred income taxes		9,212			29,752
Other		19,981			55,466
Total current liabilities		223,867			583,877
Long-Term Debt
Affiliated notes payable		528,530			530,460
Total long-term debt		528,530			530,460
Deferred Credits and Other Liabilities
Deferred income taxes		266,079			333,652
Asset retirement obligations		122,587			113,805
Affiliated employer benefit liabilities		26,990			26,347
Other		23,949			21,421
Total deferred credits and other liabilities		439,605			495,225
Total liabilities		1,192,002			1,609,562
Commitments and Contingencies (see Note 14)
Common Shareholders’ Equity
Common equity		115,608			233,665
Parent investment in DTI producing activities		(27,457	)		(22,903	)
Retained deficit		(151,827	)		(29,898	)
Accumulated other comprehensive income		28,905			53,602
Total common shareholders’ equity		(34,771	)		234,466
Total liabilities and shareholders’ equity	$	1,157,231		$	1,844,028

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

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Dominion E&P

Combined Statements of Cash Flows

Year Ended December 31,	2009			2008			2007
(thousands)
Operating Activities
Net income (loss)	$	(87,608	)	$	77,790		$	1,848,287
Adjustments to reconcile net income (loss) to net cash from operating activities:
Impairment of gas and oil properties		282,775			—			—
Gain on sale of non-Appalachian E&P business		—			—			(3,175,618	)
Charges related to termination of VPP agreements		—			—			77,266
Net change in realized and unrealized derivative (gains) losses		4,396			47,230			(166,176	)
Depreciation, depletion and amortization		72,497			84,350			295,656
Deferred income taxes		(70,999	)		(7,837	)		(716,615	)
Other adjustments		3,314			5,936			(798	)
Changes in:
Accounts receivable		41,697			66,632			206,014
Affiliated accounts receivable and payable		(25,586	)		(22,005	)		480,618
Inventories		(49	)		(284	)		(5,231	)
Prepayments		10,753			(13,546	)		38,922
Accounts payable		744			(110,800	)		(126,266	)
Accrued interest, payroll and taxes		1,908			(197,110	)		180,845
Margin deposit assets and liabilities		—			(81,776	)		75,480
Other operating assets and liabilities		(21,375	)		(48,644	)		158,473
Net cash provided by (used in) operating activities		212,467			(200,064	)		(829,143	)
Investing Activities
Oil and natural gas property and other expenditures		(175,119	)		(238,873	)		(1,065,694	)
Proceeds from assignment of natural gas drilling rights		—			342,917			—
Advances to affiliates, net of repayment		—			174,532			(2,854,778	)
Proceeds from sale of non-Appalachian E&P business		—			—			7,046,432
Proceeds from sale of gas and oil properties		22,239			—			—
Other		—			77			(5,546	)
Net cash provided by (used in) investing activities		(152,880	)		278,653			3,120,414
Financing Activities
Issuance (repayment) of affiliated current borrowings, net		4,766			16,032			(1,874,414	)
Repayment of affiliated notes payable		(1,930	)		(187	)		(223,073	)
Common dividend payments		(43,468	)		(66,636	)		(162,061	)
Capital distribution		(18,875	)		(29,105	)		(36,692	)
Other		(47	)		296			(1,096	)
Net cash used in financing activities		(59,554	)		(79,600	)		(2,297,336	)
Increase (decrease) in cash and cash equivalents		33			(1,011	)		(6,065	)
Cash and cash equivalents at beginning of year		3			1,014			7,079
Cash and cash equivalents at end of year	$	36		$	3		$	1,014
Supplemental Cash Flow Information:
Cash paid during the year for:
Interest and related charges, excluding capitalized amounts	$	34,349		$	37,471		$	27,807
Income taxes		7,316			271,026			1,533,611
Significant noncash investing and financing activities:
Accrued capital expenditures		3,977			14,369			19,779
Conversion of short-term and long-term borrowings, advances and payables to equity		94,578			(44,690	)		2,846,322

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

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Dominion E&P

Combined Statements of Shareholders’ Equity and Comprehensive Income

	Common Equity			Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (loss)(1)			Parent Investment in DTI-E&P			Total
(thousands, except shares)
Balance at December 31, 2006	$	1,043,681		$	316,389		$	(307,544	)	$	(10,387	)	$	1,042,139
Comprehensive income:
Net Income					1,828,038						20,249			1,848,287
Net deferred gains (losses) on derivatives-hedging activities, net of $60,795 tax								(93,926	)					(93,926	)
Net derivative (gains) losses reclassified to net income-hedging activities, net of $(240,367) tax								409,274						409,274
Total comprehensive income					1,828,038			315,348			20,249			2,163,635
Stock repurchase and retirement		(190,230	)											(190,230	)
Capital distribution		(532,950	)		(2,123,561	)					(36,692	)		(2,693,203	)
Dividends		(145,848	)		(16,213	)								(162,061	)
Tax effect of stock awards		1,693												1,693
Cumulative effect of change in accounting principle					(204	)								(204	)
Balance at December 31, 2007		176,346			4,449			7,804			(26,830	)		161,769
Comprehensive income:
Net Income					44,758						33,032			77,790
Net deferred gains (losses) on derivatives-hedging activities, net of $(22,345) tax								32,648						32,648
Net derivative (gains) losses reclassified to net income-hedging activities, net of $(9,156) tax								13,150						13,150
Total comprehensive income					44,758			45,798			33,032			123,588
Capital contribution (distribution)		123,795			(79,105	)					(29,105	)		15,585
Dividends		(66,636	)											(66,636	)
Tax effect of stock awards		160												160
Balance at December 31, 2008		233,665			(29,898	)		53,602			(22,903	)		234,466
Comprehensive income:
Net Income (loss)					(101,929	)					14,321			(87,608	)
Net deferred gains (losses) on derivatives-hedging activities, net of $(37,050) tax								55,401						55,401
Net derivative (gains) losses reclassified to net income-hedging activities, net of $54,164 tax								(80,098	)					(80,098	)
Total comprehensive income (loss)					(101,929	)		(24,697	)		14,321			(112,305	)
Capital distribution		(74,578	)		(20,000	)					(18,875	)		(113,453	)
Dividends		(43,468	)											(43,468	)
Tax effect of stock awards		(11	)											(11	)
Balance at December 31, 2009	$	115,608		$	(151,827	)	$	28,905		$	(27,457	)	$	(34,771	)

(1) All AOCI for 2007, 2008 and 2009 relates to derivatives and hedging activities.

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

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Note 1. Business Description and Basis of Presentation

Dominion Exploration & Production Inc. (DEPI), Dominion Reserves, Inc, and Dominion Transmission Inc. (DTI) are wholly-owned subsidiaries of Dominion Resources, Inc. (Dominion), one of the nation’s largest producers and transporters of energy. Our combined financial statements include the entirety of these wholly-owned subsidiaries, other than DTI, for which these financial statements only include the exploration and production (E&P) business of DTI (DTI-E&P). DEPI’s capital structure includes 70,000 shares of $10,000 par value common stock authorized for issuance. As of December 31, 2009 and 2008, there were 24,877 shares of DEPI common stock outstanding. DEPI’s consolidated financial statements include the wholly-owned subsidiaries Dominion Coal Bed Methane Inc. (DCBM) and DEPI Texas Holdings, LLC. Dominion Reserves, Inc’s capital structure includes 100 shares of common stock – no par value authorized for issuance. As of December 31, 2009 and 2008, there were 10 shares of Dominion Reserves, Inc. common stock outstanding. Dominion Reserves, Inc’s consolidated financial statements include the wholly-owned subsidiaries Dominion Appalachian Development Properties LLC, Dominion Appalachian Development LLC, Carthage Energy Services, LLC, Dominion Midwest Energy LLC, and Dominion Gas Processing MI, Inc. Together, the wholly-owned subsidiaries and DTI-E&P are referred to as the “Companies”, “Dominion E&P”, “we” or “us”.

The Dominion E&P business generates income from the sale of natural gas and oil it produces from its reserves in the Appalachian Basin of the U.S. and its non-Appalachian reserves prior to their sale during 2007 (See Note 4), including production from fixed-term overriding royalty interests formerly associated with its volumetric production payment (VPP) agreements, which terminated in June 2007. At December 31, 2009, the Companies own approximately 1.3 trillion cubic feet equivalent of proved natural gas and oil reserves and produce approximately 137 million cubic feet equivalent (mcf) of natural gas and oil per day from our leasehold acreage and facility investments in Appalachia.

During March 2010, Dominion began exploring a potential transaction to sell the majority of its remaining Dominion E&P operations. In preparation for the potential transaction, the accompanying Combined Financial Statements and Notes were prepared from the historical accounting records of the Companies for the purpose of complying with Rule 3-05 of Regulation S-X of the Securities and Exchange Commission (SEC). The accompanying Combined Financial Statements and Notes are not necessarily indicative of the financial condition or results of operations of the gas and oil properties going forward because of changes in the business and the exclusion of certain corporate-related expenses such as corporate governance, investor relations, and legal fees related to debt issuances.

Note 2. Significant Accounting Policies

Principles of Consolidation

Our combined financial statements include, after eliminating intercompany transactions and balances, the accounts of our respective wholly-owned subsidiaries and of the exploration and production business of DTI.

Use of Estimates

We make certain estimates and assumptions in preparing our combined financial statements in accordance with accounting principles generally accepted in the United States of America (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.

DTI-E&P Allocations

Historically, the DTI-E&P business was not operated or accounted for as a legal entity but was an integrated part of DTI. For accounts that are not specific to the DTI-E&P business, certain allocation methodologies were

9

used to allocate these DTI-E&P accounts to our Combined Financial Statements. Significant DTI-E&P allocations include:

• Trade accounts payable, which is allocated based on DTI-E&P’s operations and maintenance (O&M) expenses as a percentage of DTI’s total O&M expenses.

• Notes payable to affiliates, which is allocated based on DTI-E&P’s net property, plant and equipment as a percentage of DTI’s total net property, plant and equipment.

• Accrued payroll, which is allocated based on DTI-E&P’s employee salaries and benefits as a percentage of DTI’s total employee salaries and benefits.

• Long-term debt, which is allocated based on DTI-E&P’s net property, plant and equipment as a percentage of DTI’s total net property, plant and equipment.

• Affiliated employer benefit assets and liabilities, which are allocated based on DTI-E&P’s employee salaries and benefits as a percentage of DTI’s total employee salaries and benefits.

Cash and Cash Equivalents

Current banking arrangements generally do not require checks to be funded until they are presented for payment. At December 31, 2009 and 2008, the Companies’ accounts payable included $6 million and $9 million, respectively, of checks outstanding but not yet presented for payment. For purposes of the Combined Balance Sheets and Combined Statements of Cash Flows, cash and cash equivalents include cash on hand, cash in banks and temporary investments purchased with an original maturity of three months or less.

Allowance for Doubtful Accounts

We establish provisions for losses on accounts receivable if we determine that we will not collect all or part of the outstanding balance. We regularly review collectability and establish or adjust our allowance as necessary using the specific identification method.

Property, Plant and Equipment

We follow the full cost method of accounting for gas and oil E&P activities prescribed by the SEC. Under the full cost method, all direct costs of property acquisition, exploration and development activities are capitalized. These capitalized costs are subject to a quarterly ceiling test. Under the ceiling test, amounts capitalized are limited to the present value of estimated future net revenues to be derived from the anticipated production of proved gas and oil reserves, discounted at 10%, using trailing twelve month average natural gas and oil prices adjusted for cash flow hedges in place. Prior to adoption of the SEC’s Final Rule, Modernization of Oil and Gas Reporting, effective December 31, 2009, period-end gas and oil prices were used when performing the full cost ceiling test calculation; however, subsequent commodity prices could be utilized to reduce or eliminate any impairment in accordance with SEC guidelines. If net capitalized costs exceed the ceiling test at the end of any quarterly period, then a permanent write-down of the assets must be recognized in that period. At December 31, 2009, approximately 3% of our anticipated production is hedged by qualifying cash flow hedges, for which hedge-adjusted prices were used to calculate estimated future net revenue. Using trailing twelve month average prices, adjusted for cash flow hedges in place, there was no ceiling test impairment at December 31, 2009. Excluding the effects of hedge-adjusted prices in calculating the ceiling test limitation would have resulted in an approximately $66 million ($39 million after-tax) ceiling test impairment at December 31, 2009.

In 2009, we recorded a ceiling test impairment charge of $283 million ($169 million after-tax) in our Combined Statement of Income. Excluding the effects of hedge-adjusted prices in calculating the ceiling limitation, the impairment would have been $459 million ($275 million after-tax). Future cash flows associated with settling asset retirement obligations (AROs) that have been accrued in our Combined Balance Sheets are excluded from our calculations under the full cost ceiling test. Decreases in commodity prices, as well as changes

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in production levels, reserve estimates, future development costs, lifting costs and other factors could result in future ceiling test impairments.

Depletion of gas and oil producing properties is computed using the units-of-production method. Under the full cost method, the depletable base of costs subject to depletion also includes estimated future costs to be incurred in developing proved gas and oil reserves, as well as capitalized asset retirement costs, net of projected salvage values. The costs of investments in unproved properties including associated exploration-related costs are initially excluded from the depletable base. Until the properties are evaluated, a ratable portion of the capitalized costs is periodically reclassified to the depletable base, determined on a property by property basis, over terms of underlying leases. Once a property has been evaluated, any remaining capitalized costs are then transferred to the depletable base. In addition, gains or losses on the sale or other disposition of gas and oil properties are not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of natural gas and oil attributable to a cost pool. As discussed in Note 4, in 2007, we recognized gains from the sales of our U.S. non-Appalachian E&P businesses.

All other property, plant and equipment, including additions and replacements, is recorded at original cost, including labor, materials, asset retirement costs and other direct and indirect costs including capitalized interest. Intangible assets with finite lives are amortized over their estimated useful lives or as consumed. The cost of repairs and maintenance, including minor additions and replacements, is charged to expense as incurred. In 2009, 2008 and 2007, we capitalized interest costs of $0.5 million, $0.5 million, and $15 million, respectively. Depreciation of property, plant and equipment is computed on the straight-line method, based on projected service lives. In 2009, 2008 and 2007, depreciation and depletion expense was $72 million, $84 million and $284 million, respectively.

We perform an evaluation for impairment whenever events or changes in circumstances indicate that the carrying amount of long-lived assets or intangible assets with finite lives may not be recoverable. A long-lived or intangible asset is written down to fair value if the sum of its expected future undiscounted cash flows is less than its carrying amount.

Revenue Recognition

Gas and oil production revenue is recognized based on actual volumes of gas and oil sold to purchasers, is reported net of royalties and includes amounts yet to be billed to purchasers. Sales require delivery of the product to the purchaser, passage of title, and probability of collection of purchaser amounts owed. Revenue from sales of gas production includes the sale of Company produced gas and the recognition of revenue from the VPP transactions described in Note 4. We use the sales method of accounting for gas imbalances related to gas production. An imbalance is created when Company volumes of gas sold pertaining to a property do not equate to the volumes to which we are entitled based on our interest in the property. A liability is recognized when our excess sales over entitled volumes exceeds our net remaining property reserves.

Prior to the sale of our non-Appalachian E&P business, we entered into buy/sell and related agreements primarily as a means to reposition our offshore Gulf of Mexico crude oil production to more liquid onshore marketing locations and to facilitate gas transportation. Activity related to buy/sell and related agreements was reported on a gross basis prior to the adoption of new accounting guidance for purchases and sales of inventory with the same counterparty in April 2006. Following the adoption of this guidance, a significant portion of our activity related to buy/sell and related agreements was presented on a net basis in our Combined Statements of Income if the agreements were entered into in contemplation of one another; however, there was no impact on our results of operations or cash flows. Following the sale of our non-Appalachian E&P business in 2007, this activity did not have a material effect in our Combined Statements of Income.

Derivatives

We use derivative instruments such as futures, swaps, forwards and options to manage the commodity price risks of our natural gas and oil production.

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All derivatives, except those for which an exception applies, are required to be reported on our Combined Balance Sheets at fair value. Derivative contracts representing unrealized gain positions are reported as derivative assets. Derivative contracts representing unrealized losses are reported as derivative liabilities. We classify our derivatives as either current or non-current assets or liabilities based on their anticipated settlement date.

We do not offset amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. At December 31, 2009 and 2008, we did not have any margin assets or liabilities related to cash collateral.

Derivative Instruments Not Designated as Cash Flow Hedging Instruments

We hold certain non-trading derivative instruments that are not designated as hedges for accounting purposes. However, to the extent we do not hold offsetting positions for such derivatives, we believe these instruments represent economic hedges that mitigate our exposure to fluctuations in commodity prices.

Statement of Income Presentation—Derivatives Not Held for Trading Purposes and Not Designated as Hedging Instruments: All unrealized changes in fair value and settlements are presented in operating revenue in our Statements of Income.

Derivative Instruments Designated as Cash Flow Hedging Instruments

We designate a substantial portion of our derivative instruments as cash flow hedges for accounting purposes. The cash flow hedging strategies are primarily used to hedge the variable price risk associated with the sale of natural gas and oil. For all derivatives designated as cash flow hedges, the relationship between the hedging instrument and the hedged item is formally documented, as well as the risk management objective and strategy for using the hedging instrument at the inception of the hedge. For transactions in which we are hedging the variability of cash flows, changes in the fair value of the derivative are reported in accumulated other comprehensive income (loss) (AOCI), to the extent effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. We assess whether the hedging relationship between the derivative and the hedged item is highly effective at offsetting changes in cash flows, both at the inception of the hedging relationship and on an ongoing basis. Any change in fair value of the derivative that is not effective at offsetting changes in the cash flows of the hedged item is recognized currently in earnings. Also, we may elect to exclude certain gains or losses on hedging instruments from the assessment of hedge effectiveness, such as gains or losses attributable to the time value of options, which are recognized currently in earnings. We discontinue hedge accounting prospectively for derivatives that have ceased to be highly effective hedges or for which the forecasted transaction is determined to be no longer probable. We reclassify any derivative gains or losses reported in AOCI to earnings when the forecasted item is included in earnings, if it should occur, or earlier, if it becomes probable that the forecasted transaction will not occur.

Statement of Income Presentation—Gains and losses on derivatives designated as hedges, when recognized, and gains and losses on hedging instruments determined to be ineffective are included in operating revenue in our Statements of Income.

Valuation Methods

See Note 7 for further information about fair value measurements and associated valuation methods for derivatives.

Fair Value of Financial Instruments

In accordance with GAAP, we report certain contracts and instruments at fair value. The carrying values of the Companies’ receivables and payables are estimated to be substantially the same as their fair values at

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December 31, 2009 and 2008. See Note 7 for fair value disclosures related to the Companies’ debt. See Notes 7 and 8 for details about the fair value of the Companies’ derivative financial instruments.

Income Taxes

Dominion E&P is included in the consolidated federal income tax return of Dominion and its subsidiaries. In addition, where applicable, Dominion E&P is included in combined state income tax returns of Dominion and its subsidiaries; otherwise, Dominion E&P files separate state income tax returns. In connection with being included in Dominion’s consolidated or combined income tax returns, Dominion E&P participates in an intercompany tax sharing agreement with Dominion and its subsidiaries. Under the tax sharing agreement, Dominion E&P’s current income taxes are based on its taxable income or loss, determined on a separate company basis. In addition, Dominion E&P recognizes an intercompany receivable from Dominion and is paid for net operating losses, if the tax benefit is realized by the consolidated group.

Accounting for income taxes involves an asset and liability approach. Deferred income tax assets and liabilities are provided, representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Dominion E&P establishes a valuation allowance when it is more likely than not that all, or a portion, of a deferred tax asset will not be realized.

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

If it is not more-likely-than-not that a tax position, or some portion thereof, will be sustained, the related tax benefits are not recognized in the financial statements. Unrecognized tax benefits may result in an increase in income taxes payable, a reduction of income tax refunds receivable or changes in deferred taxes. When uncertainty about the deductibility of an amount is limited to the timing of such deductibility, the increase in taxes payable (or reduction in tax refunds receivable) is accompanied by a decrease in deferred tax liabilities.

Dominion E&P’s policy is to recognize changes in interest payable on net underpayments and overpayments of income taxes in interest expense and penalties in general and administrative expense. In our Combined Statements of Income, Dominion E&P recognized no material penalties and a reduction of interest expense of $0.2 million and $1 million in 2009 and 2008, respectively, and interest expense of $2 million in 2007. Dominion E&P had accrued interest receivable of $2 million and no penalties payable at December 31, 2009, and interest receivable of $0.4 million and no penalties payable at December 31, 2008.

Asset Retirement Obligations

We recognize AROs at fair value as incurred, or when sufficient information becomes available to determine a reasonable estimate of the fair value of the retirement activities to be performed. The associated asset retirement costs are capitalized as costs of the related tangible long-lived assets. Since relevant market information is not available, we estimate fair value using discounted cash flow analyses. We report the accretion of the AROs due to the passage of time in production (lifting) expense.

Note 3. Newly Adopted Accounting Standards

2009

SEC Final Rule, Modernization of Oil and Gas Reporting

Effective December 31, 2009, we adopted the SEC Final Rule, Modernization of Oil and Gas Reporting, which revised the existing Regulation S-K and Regulation S-X accounting and reporting requirements. Under the new requirements, the ceiling test is calculated using an average price based on the prior twelve month period

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rather than period-end prices. As a result, going forward we will be less likely to experience a ceiling test impairment based solely on a sudden decrease in gas and oil prices.

2008

Fair Value Measurements

We adopted new Financial Accounting Standards Board (FASB) guidance effective January 1, 2008, which defines fair value, establishes a framework for measuring fair value and expands disclosures related to fair value measurements. The guidance applies broadly to financial and non-financial assets and liabilities that are measured at fair value under other authoritative accounting pronouncements, but does not expand the application of fair value accounting to any new circumstances. Generally, the provisions of this guidance were applied prospectively. In February 2008, the FASB amended the fair value measurements guidance to exclude leasing transactions. However, the exclusion does not apply to fair value measurements of assets and liabilities recorded as a result of a lease transaction but measured pursuant to other pronouncements within the scope of the fair value measurements guidance. See Note 7 for further information on fair value measurements.

2007

Accounting for Uncertainty in Income Taxes

Effective January 1, 2007, we adopted new FASB guidance for accounting for uncertainty in income taxes. As a result of the implementation of this guidance, we recorded a $0.2 million charge to beginning retained earnings, representing the cumulative effect of the change in accounting principle. At January 1, 2007, we had unrecognized tax benefits of $33 million. For the majority of these unrecognized tax benefits, the ultimate deductibility was highly certain, but there was uncertainty about the timing of such deductibility.

Note 4. Acquisitions and Dispositions

Acquisition of E&P Properties

In November 2007, we completed the acquisition of DCBM for approximately $6 million in cash. At the time of acquisition, DCBM included four coal bed methane leases covering approximately 43,667 acres of Pittsburgh Coal in Wetzel County, West Virginia including six horizontal coal bed methane wells.

Sale of E&P Properties

In 2007, we completed the sale to unrelated third parties of our non-Appalachian natural gas and oil E&P operations and assets for approximately $7 billion. We distributed most of the after-tax proceeds from these dispositions to our parent company, Dominion. The results of operations for our non-Appalachian E&P business were not reported as discontinued operations in the Combined Statements of Income since we did not sell our entire U.S. cost pool, which includes the retained Appalachian assets.

The sales of our non-Appalachian E&P operations resulted in the discontinuance of hedge accounting for certain cash flow hedges 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 recognized charges, recorded in operating revenue in the Combined Statement of Income, predominantly reflecting the reclassification of losses from AOCI to earnings of $410 million ($261 million after-tax) in 2007. We terminated these gas and oil derivatives subsequent to the disposal of the non-Appalachian E&P business.

During 2007, we also recorded a charge in operating revenue in the Combined Statement of Income of approximately $77 million ($49 million after-tax) for the recognition of certain VPP agreements to which we were a party, that previously qualified for the normal purchase and sales exemption. We paid approximately $250 million to terminate the agreements on behalf of the Companies as well as other Dominion affiliates, and another

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Dominion affiliate assumed the VPP royalty interests formerly associated with these agreements. We received approximately $230 million for this conveyance of mineral interests under the terms of a new VPP agreement with an affiliated company.

Additionally, we recognized expenses for employee severance, retention and other costs of $52 million ($33 million after-tax) in 2007, related to the sale of our non-Appalachian E&P business, which are reflected in general and administrative expenses in our Combined Statement of Income.

We recognized a gain of approximately $3.2 billion ($2.0 billion after-tax) from the disposition of our non-Appalachian E&P operations. This gain excludes severance and retention costs and costs associated with the discontinuance of hedge accounting and recognition of forward gas contracts.

Sale of Oil and Gas Leases

During 2009, we sold certain oil and gas leases to unrelated third parties. In March 2009, we sold leases covering 2,686 acres in Bradford County, Pennsylvania for $7 million in cash, and in October 2009 we sold leases covering 12,696 acres in Bradford, Susquehanna, and Tioga Counties in Pennsylvania and Chemung County, New York for approximately $15 million in cash.

Note 5. Operating Revenue

Our operating revenue consists of the following:

Year Ended December 31,	2009		2008		2007
(thousands)
Gas sales	$	325,013	$	335,013	$	576,622
NGL sales		9,852		17,966		43,074
Oil and condensate sales(1)		5,765		8,215		(4,668	)
Other		2,327		399		11,726
Total operating revenue	$	342,957	$	361,593	$	626,754

(1) The loss reflected in oil and condensate sales in 2007 was primarily due to the reclassification of losses from AOCI to earnings from the de-designation of cash flow hedges due to the sale of our Non-Appalachian E&P operations. See Note 4.

Note 6. Income Taxes

Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. The interpretation of tax laws involves uncertainty, since tax authorities may interpret the laws differently. The tax returns of Dominion E&P are subject to routine audits by tax authorities. Ultimate resolution of income tax matters may result in favorable or unfavorable impacts to net income and cash flows, and adjustments to tax-related assets and liabilities could be material.

The American Recovery and Reinvestment Act of 2009 includes provisions to stimulate economic growth, including incentives for increased capital investment by business and incentives to promote renewable energy. Under the act, Dominion E&P has claimed bonus tax depreciation in 2009 for qualifying expenditures which reduced their income taxes payable and increased deferred tax liabilities for the period.

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Details of Dominion E&P’s income tax expense were as follows:

Year Ended December 31,	2009			2008			2007
(thousands)
Current:
Federal	$	6,295		$	13,651		$	1,758,140
State		3,310			36,042			69,600
Total current		9,605			49,693			1,827,740
Deferred:
Federal		(59,823	)		30,032			(775,041	)
State		(11,176	)		(37,869	)		58,426
Total deferred		(70,999	)		(7,837	)		(716,615	)
Total income tax expense (benefit)	$	(61,394	)	$	41,856		$	1,111,125

Income taxes calculated on Dominion E&P’s income before taxes at the statutory U.S. federal income tax rate reconciles to its income tax provision as follows:

Year Ended December 31,	2009			2008			2007
(thousands)
Income (loss) before income taxes	$	(149,002	)	$	119,646		$	2,959,412
Total income tax expense (benefit) at U.S. statutory rate (35%)	$	(52,150	)	$	41,876		$	1,035,794
Increases (reductions) resulting from:
State taxes, net of federal benefit		(5,113	)		10,012			84,599
Legislative changes		—			(11,199	)		399
Domestic production activities		(3,951	)		—			(7,926	)
Other, net		(180	)		1,167			(1,741	)
Income tax expense (benefit)	$	(61,394	)	$	41,856		$	1,111,125

In 2007, Dominion E&P’s effective tax rate reflected the effects of the sale of its U.S. non-Appalachian E&P operations, including the reversal of $14 million of valuation allowances on deferred tax assets that related to state loss carryforwards utilized to partially offset taxes otherwise payable on the gain from the sale.

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amount of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Dominion E&P’s deferred income taxes consist of the following:

At December 31,	2009			2008
(thousands)
Deferred income taxes:
Total deferred income tax assets	$	(21,684	)	$	(32,799	)
Total deferred income tax liabilities		296,975			396,203
Total net deferred income tax liabilities	$	275,291		$	363,404
Gas and oil exploration and production differences	$	262,344		$	327,496
Deferred state income taxes		12,403			23,773
Employee benefits		(8,638	)		(11,983	)
Price risk management activities		15,549			32,132
Other		(6,367	)		(8,014	)
Total net deferred income tax liabilities	$	275,291		$	363,404

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At December 31, 2009, Dominion E&P had no loss or credit carryforwards.

Positions taken by an entity in its income tax returns that are recognized in the financial statements must satisfy a more-likely-than-not recognition threshold, assuming that the position will be examined by tax authorities with full knowledge of all relevant information. The amount of tax return positions that are not recognized in the financial statements is disclosed as unrecognized tax benefits. These unrecognized tax benefits may impact the financial statements by increasing taxes payable, reducing tax refunds receivable or changing deferred taxes. Also, when uncertainty about the deductibility of amounts is limited to the timing of such deductibility, any tax liabilities recognized for prior periods would be subject to offset with the availability of refundable amounts from later periods when such deductions could otherwise be taken. Pending resolution of these timing uncertainties, interest is being accrued until the period in which the amounts would become deductible.

A reconciliation of changes in Dominion E&P’s unrecognized tax benefits follows:

	2009			2008			2007
(thousands)
Balance at January 1	$	24,746		$	23,696		$	32,899
Increases—prior period positions		—			1,270			1,535
Decreases—prior period positions		(3,248	)		(288	)		(1,205	)
Current period positions		19			68			22,741
Prior period positions becoming otherwise deductible in current period		—			—			(23,111	)
Settlements with tax authorities		(1,171	)		—			(9,163	)
Balance at December 31	$	20,346		$	24,746		$	23,696

Certain unrecognized tax benefits, or portions thereof, if recognized, would affect the effective tax rate. For Dominion E&P, these unrecognized tax benefits totaled $15 million, $20 million and $19 million at December 31, 2009, 2008 and 2007, respectively, and $0.2 million at January 1, 2007. Changes in these unrecognized tax benefits decreased income tax expense by $3 million in 2009 and increased income tax expense by $0.7 million and $18 million in 2008 and 2007, respectively.

For Dominion, the U.S. federal statute of limitations has expired for years prior to 2002. The status of Dominion’s consolidated U.S. federal returns as of December 31, 2009 and related 2009 activities follows:

• The U.S. Congressional Joint Committee on Taxation completed its review of Dominion’s settlement with the Appellate Division of the Internal Revenue Service (IRS) for tax years 1999 through 2001.

• Dominion and the Appellate Division of the IRS were engaged in settlement negotiations regarding certain proposed adjustments for tax years 2002 and 2003.

• The IRS completed its audit of tax years 2004 and 2005, and Dominion and the IRS reached agreement on adjustments related to Dominion E&P.

With regard to tax years 2006 through 2009, Dominion E&P cannot estimate the range of reasonably possible changes to unrecognized tax benefits that may occur in 2010.

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For each of the major states in which Dominion E&P has operated or continues to operate, the earliest tax year remaining open for examination is as follows:

	Earliest Open Tax Year
Louisiana *	2002
Michigan	2005
Oklahoma	2006
Pennsylvania	2006
Utah *	2002
West Virginia	2006

* State statute of limitations suspended with extension of federal statute of limitations.

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

Note 7. Fair Value Measurements

As described in Note 3, we adopted new FASB guidance for fair value measurements effective January 1, 2008. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. However, the use of a mid-market pricing convention (the mid-point between bid and ask prices) is permitted. Fair value is based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. This includes not only the credit standing of counterparties involved and the impact of credit enhancements but also the impact of our own nonperformance risk on our liabilities. Fair value measurements assume that the transaction occurs in the principal market for the asset or liability (the market with the most volume and activity for the asset or liability from the perspective of the reporting entity), or in the absence of a principal market, the most advantageous market for the asset or liability (the market in which the reporting entity would be able to maximize the amount received or minimize the amount paid). We apply fair value measurements to commodity derivative instruments in accordance with the requirements described above. We apply credit adjustments to our derivative fair values in accordance with the requirements described above. These credit adjustments are currently not material to the derivative fair values.

We maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Fair value is based on actively-quoted market prices, if available. In the absence of actively-quoted market prices, we seek price information from external sources, including broker quotes and industry publications. When evaluating pricing information provided by brokers and other pricing services, we consider whether the broker is willing and able to trade at the quoted price, if the broker quotes are based on an active market or an inactive market and the extent to which brokers are utilizing a particular model if pricing is not readily available. If pricing information from external sources is not available, or if we believe that observable pricing is not indicative of fair value, judgment is required to develop the estimates of fair value. In those cases we must estimate prices based on available historical and near-term future price information and certain statistical methods, including regression analysis, that reflect our market assumptions. For contracts with unique characteristics, the Companies may estimate fair value using a discounted cash flow approach deemed appropriate in the circumstances and applied consistently from period to period. For individual contracts, the use of different valuation models or assumptions could have a significant effect on the contract’s estimated fair value.

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

• Level 1—Quoted prices (unadjusted) in active markets for identical assets and liabilities that we have the ability to access at the measurement date. Instruments categorized in Level 1 would consist of financial instruments such as the majority of exchange-traded derivatives.

• Level 2—Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 include non-exchange traded derivatives such as over-the-counter commodity forwards and swaps.

• Level 3—Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. Instruments categorized in Level 3 consist of long-dated commodity derivatives.

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability.

Fair value measurements are categorized as Level 3 when a significant amount of price or other inputs that are considered to be unobservable are used in their valuations. Long-dated commodity derivatives are based on unobservable inputs due to market illiquidity and are therefore categorized as Level 3.

As of December 31, 2009, we did not hold any derivatives or other instruments categorized as Level 3. As of December 31, 2008, our net balance of commodity derivatives categorized as Level 3 was a net asset of $1 million. A hypothetical 10% increase in commodity prices would have decreased the net asset by $0.6 million. A hypothetical 10% decrease in commodity prices would have increased the net asset by $0.6 million.

Nonrecurring Fair Value Measurements

FASB fair value measurement guidance became effective for non-financial assets and liabilities on January 1, 2009. As such, the guidance applies to new AROs incurred after January 1, 2009 and upward revisions of existing AROs after January 1, 2009. During 2009, we incurred AROs related to newly drilled wells, which were initially measured at a fair value totaling approximately $2 million. Fair value was estimated using a discounted cash flow model based upon expected costs to plug and abandon the wells at the end of their useful lives. Cost information was based on historical costs to abandon similar wells. This is considered a Level 3 fair value measurement due to the use of significant unobservable inputs related to the timing and amount of future costs to be incurred.

Recurring Fair Value Measurements

Fair value measurements are separately disclosed by level within the fair value hierarchy with a separate reconciliation of fair value measurements categorized as Level 3.

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

	Level 1	Level 2		Level 3		Total
(thousands)
At December 31, 2009
Assets:
Derivatives	—	$	48,786		—	$	48,786
Liabilities:
Derivatives	—	$	208		—	$	208
At December 31, 2008
Assets:
Derivatives	—	$	95,376	$	1,223	$	96,599
Liabilities:
Derivatives	—	$	1,812		—	$	1,812

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

	2009(1)			2008(1)
(thousands)
Balance at January 1,
Total realized and unrealized gains (losses):	$	1,223		$	—
Included in other comprehensive income (loss)		(310	)		3,420
Transfers out of Level 3		(913	)		(2,197	)
Balance at December 31,	$	—		$	1,223

(1) Represents derivative assets and liabilities presented on a net basis.

For the years ended December 31, 2009 and 2008, there were no gains or losses recorded in earnings related to derivatives categorized as Level 3.

Fair Value of Financial Instruments

Substantially all of our financial instruments are recorded at fair value, with the exception of the instruments described below that are reported at historical cost. Estimated fair values have been determined using available market information and valuation methodologies considered appropriate by management. At December 31, 2009 and 2008, the carrying amount of our customer and other receivables, and accounts payable are representative of fair value because of the short-term nature of these instruments. The financial instruments reported at historical cost along with their fair values are as follows:

At December 31,	2009				2008
	Carrying Amount		Estimated Fair Value(1)		Carrying Amount		Estimated Fair Value(1)
(thousands)
Notes payable to affiliates	$	528,530	$	560,661	$	530,460	$	484,743

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

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Note 8. Derivatives and Hedge Accounting Activities

We are exposed to the impact of market fluctuations in the price of natural gas and oil marketed as part of our business operations. We use derivative instruments to manage our exposure to these risks and designate certain derivative instruments as cash flow hedges for accounting purposes. See Note 7 for further information about fair value measurements and associated valuation methods for derivatives.

The following table presents the volume of our open derivative positions as of December 31, 2009. These volumes represent the combined absolute value of our long and short positions, except in the case of offsetting deals, for which we present the absolute value of the net volume of our long and short positions.

	Current	Noncurrent
Natural Gas (bcf)	26.4	6.3

Selected information about our hedge accounting activities follows:

Year Ended December 31,	2009		2008		2007
(thousands)
Portion of gains on hedging instruments determined to be ineffective and included in net income:
Cash Flow Hedges(1)(2)	$	50	$	393	$	48,257
Gains (losses) attributable to changes in the time value of options and excluded from the assessment of effectiveness
Cash Flow Hedges		—		—		(407	)
Total	$	50	$	393	$	47,850

(1) For 2007, primarily represents changes in the fair value differential between the delivery location and commodity specifications of derivatives and the delivery location and commodity specifications of forecasted gas and oil sales.

(2) For 2009, amounts were recorded in operating revenue.

See Note 4 for a discussion of the discontinuance of hedge accounting for non-Appalachian E&P gas and oil derivatives during 2007.

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

	AOCI After-tax		Amounts expected to be reclassified to earnings during the next 12 months After-tax		Maximum Term
(thousands)
Commodities
Gas	$	28,905	$	27,044	24 months

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.

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Fair Value and Gains and Losses on Derivative Instruments

The following table presents the fair values of our derivatives at December 31, 2009 and where they are presented on our Combined Balance Sheet:

	Fair Value- Derivatives under Hedge Accounting		Fair Value- Derivatives not under Hedge Accounting		Total Fair Value
(thousands)
Assets
Current Assets
Commodity	$	45,447	$	208	$	45,655
Noncurrent Assets
Commodity		3,131		—		3,131
Total Affiliated Derivative Assets		48,578		208		48,786
Liabilities
Current Liabilities
Commodity(1)	$	—	$	208	$	208

(1) Current derivative liabilities are presented in other current liabilities on our Combined Balance Sheet.

The following tables present the gains and losses on our derivatives, as well as where the associated activity is presented on our Combined Balance Sheet and Statement of Income at December 31, 2009:

Derivatives in cash flow hedging relationships	Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)(1)		Amount of Gain (Loss) Reclassified from AOCI into Income
(thousands)
Derivative Type and Location of Gains (Losses)
Commodity(2)	$	92,451	$	134,262

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

(2) Amounts recorded in our Combined Statement of Income are classified in operating revenue.

Derivatives not designated as hedging instruments	Amount of Gain (Loss) Recognized in Income on Derivatives
(thousands)
Derivative Type and Location of Gains (Losses)
Commodity(1)	$	1,316

(1) Amounts recorded in our Combined Statement of Income are classified in operating revenue.

Note 9. Property, Plant and Equipment

There were no significant properties under development, as defined by the SEC, excluded from amortization at December 31, 2009 and 2008. As gas and oil reserves are proved through drilling or as properties are deemed to be impaired, excluded costs and any related reserves are transferred on an ongoing, well-by-well basis into the amortization calculation.

Volumetric Production Payment Transactions

We previously entered into VPP transactions in which cash proceeds received were recorded as deferred revenue. We recognized revenue as natural gas was produced and delivered to the purchaser. During 2007, in

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conjunction with the sales of our non-Appalachian E&P operations, we paid approximately $250 million to terminate the agreements on behalf of the Companies as well as other Dominion affiliates, and another Dominion affiliate assumed the VPP royalty interests formerly associated with these agreements. We received approximately $230 million for this conveyance of mineral interests under the terms of a new VPP agreement with an affiliated company.

Assignment of Marcellus Acreage

In 2008, we completed a transaction with Antero to assign drilling rights to approximately 117,000 acres in the Marcellus Shale formation located in West Virginia and Pennsylvania. We received proceeds of approximately $347 million and recognized $4 million of associated closing costs. The net proceeds were credited to our full cost pool, reducing property, plant and equipment in the Combined Balance Sheet, as the transaction did not significantly alter the relationship between capitalized costs and proved reserves of natural gas and oil. Under the agreement, we receive a 7.5% overriding royalty interest on future natural gas production from the assigned acreage. We retained the drilling rights in traditional formations both above and below the Marcellus Shale interval and continue our conventional drilling program on the acreage.

Sale of E&P Properties

In 2007, we sold our non-Appalachian natural gas and oil E&P operations and assets for approximately $7 billion, which included the sale of a portion of our full cost pool. In 2009, we sold certain oil and gas leases to unrelated third parties for approximately $22 million. See Note 4 for additional information.

Note 10. Asset Retirement Obligations

Our AROs are primarily associated with plugging and abandonment of gas and oil wells. These obligations result from certain safety and environmental activities we are required to perform when any well is abandoned.

The changes to our AROs during 2009 were as follows:

	Amount
(thousands)
Asset retirement obligation at December 31, 2008(1)	$	114,839
Liabilities incurred		1,626
Obligations settled		(112	)
Revisions in estimated cash flows		—
Accretion expense		5,786
Other		448
Asset retirement obligation at December 31, 2009	$	122,587

(1) Includes approximately $1 million reported in other current liabilities at December 31, 2008. There were no amounts reported in other current liabilities at December 31, 2009.

Note 11. Short-Term Debt and Credit Agreements

We use affiliated current borrowings 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.

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Note 12. Long-Term Debt

At December 31,	2009 Weighted- average Coupon(1)		2009		2008
(thousands)
Notes payable to affiliates, 6.8% to 8.95%, due 2013 to 2017	7.20	%	$	3,530	$	5,460
Notes payable to affiliates, 6.45%, due 2017	6.45	%		525,000		525,000
Total long-term debt			$	528,530	$	530,460

(1) Represents weighted-average coupon rates for debt outstanding as of December 31, 2009.

Based on stated maturity dates, the scheduled principal payments of long-term debt at December 31, 2009 were as follows:

	2010		2011		2012		2013		2014		Thereafter		Total
(thousands)
	$	—	$	—	$	—	$	1,404	$	1,043	$	526,083	$	528,530

Note 13. Employee Benefit Plans

The Companies participate in defined benefit pension plans sponsored by Dominion and DTI. Benefits payable under the plans are based primarily on years of service, age and the employee’s compensation. As a participating employer, the Companies are subject to Dominion’s and DTI’s funding policy, which is to contribute annually an amount that is in accordance with the provisions of the Employment Retirement Income Security Act of 1974. The Companies’ net periodic benefit credit related to the plans was approximately $3 million, $4 million and $3 million in 2009, 2008, and 2007, respectively. Employee compensation is the basis for determining the Companies’ share of total pension costs. The Companies did not contribute to the pension plans in 2009, 2008, or 2007.

The Companies participate in Dominion and DTI plans that provide certain retiree health care and life insurance benefits. Annual employee premiums are based on several factors such as age, retirement date and years of service. The Companies’ net periodic benefit cost related to the plans was $2 million, $2 million and $13 million in 2009, 2008 and 2007, respectively. Employee headcount is the basis for determining the Companies’ share of total benefit costs.

The Companies also participate in Dominion-sponsored employee savings plans that cover substantially all employees. Employer matching contributions of $0.8 million, $0.7 million and $2 million were incurred in 2009, 2008 and 2007, respectively.

Note 14. Commitments and Contingencies

As the result of issues generated in the ordinary course of business, we are involved in legal and tax proceedings before various courts and governmental agencies, some of which involve substantial amounts of money. The ultimate outcome of these proceedings cannot be predicted at this time; however, we believe that the final disposition of these proceedings will not have a material effect on our financial position, liquidity or results of operations.

Lease Commitments

We lease various facilities, vehicles and equipment primarily under operating leases. Payments under certain leases are escalated based on an index such as the consumer price index. Future minimum lease payments

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under noncancelable operating and capital leases that have initial or remaining lease terms in excess of one year as of December 31, 2009 are as follows:

	2010		2011		2012		2013		2014		Thereafter		Total
(thousands)
	$	741	$	974	$	795	$	737	$	667	$	1,161	$	5,075

Rental expense totaled $3 million, $3 million, and $11 million in 2009, 2008, and 2007 respectively, all of which is reflected in general and administrative expense.

Environmental Matters

We are subject to costs resulting from a steadily increasing number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations and can result in increased capital, operating and other costs as a result of our compliance, remediation, containment and monitoring obligations.

In June 2009, the U.S. House of Representatives passed comprehensive legislation titled the “American Clean Energy and Security Act of 2009” to encourage the development of clean energy sources and reduce greenhouse gas (GHG) emissions. The legislation includes cap-and-trade provisions for the reduction of GHG emissions. Similar legislation has been introduced in the U.S. Senate. In addition, the Environmental Protection Agency (EPA) has proposed one rule and finalized another rule that together hold that GHGs are air pollutants subject to the provisions of the Clean Air Act. These are the EPA Final Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act and the Proposed Rulemaking To Establish Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards (proposed September 2009). Possible outcomes from these actions include regulation of GHG emissions from various sources, including gas operations facilities. We are unable to determine the impact from these actions on our gas facilities that emit GHGs at this time.

Surety Bonds

As of December 31, 2009, we had purchased $6 million of surety bonds to facilitate commercial transactions with third parties.

Indemnifications

As part of commercial contract negotiations in the normal course of business, we may sometimes agree to make payments to compensate or indemnify other parties for possible future unfavorable financial consequences resulting from specified events. The specified events may involve an adverse judgment in a lawsuit or the imposition of additional taxes due to a change in tax law or interpretation of the tax law. We are unable to develop an estimate of the maximum potential amount of future payments under these contracts because events that would obligate us have not yet occurred or, if any such event has occurred, we have not been notified of its occurrence. However, at December 31, 2009, we believe that future payments, if any, which could ultimately become payable under these contract provisions, would not have a material impact on our results of operations, cash flows or financial position.

Litigation

We have been involved in litigation since 2006 with certain royalty owners seeking to recover damages as a result of our allegedly underpaying royalties by improperly deducting post-production costs and not paying fair market value for the gas produced from their leases. The plaintiffs sought class action status on behalf of all West Virginia residents and others who are parties to, or beneficiaries of, oil and gas leases with us. In 2008, the Court

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preliminarily approved settlement of the class action and conditionally certified a temporary settlement class. Following preliminary approval by the Court, settlement notices were sent out to potential class members. In 2009, the Court entered a Memorandum Opinion and Final Order approving settlement and certifying the settlement class and the Final Judgment Order. In 2007, we established a litigation reserve representing our best estimate of the probable loss related to this matter. As of December 31, 2009, the remaining liability was $15 million, of which $2 million was reserved in escrow. We do not believe that final resolution of the matter will have a material adverse effect on our results of operations or financial condition.

We are currently involved in settlement negotiations for litigation alleging that oil and gas severance tax refunds have not been properly redistributed to royalty owners and non-operating working interest owners in Texas and New Mexico. We are also one of approximately 20 defendants and a member of a joint defense group that shares expert witness and other litigation costs concerning the calculation of royalty payments on gas produced from federal leases during 1995-1999. We have agreed to the terms of a settlement and are working on finalizing the details. As of December 31, 2009, reserves were established for these matters totaling approximately $6 million. We do not believe that final resolution of these matters will have a material adverse effect on our results of operations or financial condition.

Note 15. Credit Risk

Credit risk is the risk of financial loss if counterparties fail to perform their contractual obligations. We sell natural gas and oil produced from our reserves primarily to affiliated companies as well as third parties. These transactions principally occur in the Appalachian basin region of the United States. We do not believe that this geographic concentration contributes significantly to our overall exposure to credit risk.

Our exposure to potential concentrations of credit risk results primarily from sales to major companies in the energy industry. We are subject to the risk of delays in payment as well as losses resulting from nonpayment and/or nonperformance by our customers. At December 31, 2009, no single non-affiliated party represented more than 3% of the gross receivables balance. As a result, we believe 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.

Note 16. Related Party Transactions

We engage in related party transactions primarily with affiliates (Dominion subsidiaries). Our accounts receivable and payable balances with affiliates are settled based on contractual terms on a monthly basis, depending on the nature of the underlying transactions. We are included in Dominion’s consolidated federal income tax return and participate in certain Dominion and DTI benefit plans.

Transactions with Affiliates

We transact with affiliates for certain quantities of natural gas and other commodities at market prices in the ordinary course of business. We also enter into certain financial derivative commodity contracts with affiliates. We use these contracts, which are principally comprised of commodity swaps, to manage commodity price risks associated with the sale of natural gas. We designate the majority of these contracts as cash flow hedges for accounting purposes.

The following table presents derivative asset and liability positions with affiliates:

At December 31,	2009		2008
(thousands)
Derivative assets	$	48,786	76,987
Derivative liabilities		208	—

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Presented below are affiliated transactions, including net realized gains and losses recorded in operating revenue and operating expenses:

Year Ended December 31,	2009		2008			2007
(thousands)
Sales to affiliates	$	189,841	$	365,305		$	302,827
Settlements of commodity derivative contracts with affiliates		108,758		(3,398	)		112,808
Purchases from affiliates		—		—			39,664

Dominion Resources Services (Dominion Services) and other affiliates provide certain administrative and technical services to us. The cost of services provided to us by Dominion Services and other affiliates is as follows:

Year Ended December 31,	2009		2008		2007
(thousands)
Cost of services provided by Dominion Services	$	15,836	$	18,929	$	51,366
Cost of services provided by other affiliates		3,812		4,046		2,905

As disclosed in Note 12, Dominion E&P has long-term debt with affiliates. See Note 12 for information regarding Dominion E&P’s long-term debt, expected maturities, and related principal payments. Dominion E&P incurred interest charges related to affiliates of $35 million, $52 million, and $81 million in 2009, 2008 and 2007, respectively. Dominion E&P earned interest income related to affiliates of $15 million and $39 million in 2008 and 2007, respectively. We earned no interest income related to affiliates in 2009.

At December 31, 2009, Dominion E&P’s Combined Balance Sheet included a $3 million receivable from Dominion for refundable federal income taxes and a $10 million liability for state income taxes payable to Dominion. Dominion E&P’s Combined Balance Sheet at December 31, 2008, included a $29 million receivable from Dominion for refundable federal income taxes and a $26 million liability for state income taxes payable to Dominion.

Note 17. Subsequent Events

We have evaluated subsequent events through March 14, 2010, which is the date the financial statements were available to be issued.

In March 2010, the expected sale of our Appalachian E&P operations resulted in the discontinuance of hedge accounting for our cash flow hedges since it will become probable that the forecasted sales of gas will not occur. In connection with the discontinuance of hedge accounting for these contracts, we will recognize gains for a substantial portion of our derivative balance, reflecting the reclassification of gains from AOCI to earnings.

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Note 18. Gas & Oil Producing Activities (unaudited)

Capitalized Costs

The aggregate amounts of costs capitalized for gas and oil producing activities, and related aggregate amounts of accumulated depletion follow:

At December 31,	2009		2008
(thousands)
Capitalized costs:
Proved properties	$	1,668,586	$	1,515,633
Unproved properties		8,416		10,838
Total capitalized costs		1,677,002		1,526,471
Accumulated depletion:
Proved properties		674,129		327,169
Unproved properties		—		—
Total accumulated depletion		674,129		327,169
Net capitalized costs	$	1,002,873	$	1,199,302

Total Costs Incurred

The following costs were incurred in gas and oil producing activities:

Year Ended December 31,	2009		2008		2007
(thousands)
Property acquisition costs:
Proved properties	$	238	$	2,297	$	7,113
Unproved properties		1,711		3,738		32,456
Total property acquisition costs		1,949		6,035		39,569
Exploration costs		854		1,235		112,004
Development costs(1)		159,382		205,578		482,721
Total	$	162,185	$	212,848	$	634,294

(1) Development costs incurred for proved undeveloped reserves were $133 million, $80 million and $445 million for 2009, 2008 and 2007, respectively.

Company-Owned Reserves

The preparation of our gas reserve estimates is completed in accordance with the Companies’ prescribed internal control procedures, which include verification of input data into a reserve forecasting and economic evaluation software as well as management review. The technical employee responsible for overseeing the preparation of the reserve estimates is an oil and gas engineer. Our 2009 oil and gas reserve results were audited by Ryder Scott Company. The technical person primarily responsible for overseeing the audit of our reserves is a certified oil and gas engineer.

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Estimated net quantities of proved gas and oil (including condensate) reserves at December 31, 2009, 2008 and 2007, and changes in the reserves during those years, are shown in the schedules that follow:

	2009		2008		2007
Proved developed and undeveloped reserves—Gas
(bcf)
At January 1	1,097		999		1,895
Changes in reserves:
Extensions, discoveries and other additions	49		46		23
Revisions of previous estimates	69		93		90
Production	(45	)	(41	)	(92	)
Purchases of gas in place	—		—		10
Sales of gas in place	—		—		(927	)
At December 31	1,170		1,097		999
Proved developed and undeveloped reserves—Oil
(thousands of barrels)
At January 1	12,434		12,613		96,133
Changes in reserves:
Extensions, discoveries and other additions	892		484		29
Revisions of previous estimates	2,401		256		907
Production	(942	)	(919	)	(8,106	)
Purchases of oil in place	1		—		—
Sales of oil in place	—		—		(76,350	)
At December 31(1)	14,786		12,434		12,613

(1) Ending reserves for 2009, 2008 and 2007 included 1.2 million, 1.0 million and 0.3 million barrels of oil/condensate, respectively, and 13.6, 11.4 and 12.3 million barrels of natural gas liquids, respectively.

Proved developed reserves as of December 31,	Gas (bcf)	Oil (bbl)	Equivalent Total (bcf)
2009	748	14,571	835
2008	670	12,406	744
2007	616	12,613	692
2006	1,212	87,887	1,740

Proved undeveloped reserves as of December 31,	Gas (bcf)	Oil (bbl)	Equivalent Total (bcf)
2009	422	215	424
2008	427	28	427
2007	383	—	383
2006	683	8,246	733

Approximately $47 million of capital was spent in the year ended December 31, 2009 related to undeveloped reserves that were transferred to developed.

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Standardized Measure of Discounted Future Net Cash Flows and Changes Therein

The following tabulation has been prepared in accordance with the FASB’s rules for disclosure of a standardized measure of discounted future net cash flows relating to proved gas and oil reserve quantities that we own:

	2009		2008		2007
(thousands)
Future cash inflows(1)	$	4,949,811	$	7,359,788	$	8,128,335
Less:
Future development costs(2)		780,214		919,968		671,384
Future production costs		1,314,691		1,293,347		1,234,783
Future income tax expense		1,046,694		2,009,900		2,431,572
Future cash flows		1,808,212		3,136,573		3,790,596
Less annual discount (10% a year)		1,221,798		2,029,024		2,346,754
Standardized measure of discounted future net cash flows	$	586,414	$	1,107,549	$	1,443,842

(1) Amounts exclude the effect of derivative instruments designated as hedges of future sales of production at year-end.

(2) Estimated future development costs, excluding abandonment, for proved undeveloped reserves are estimated to be $126 million, $97 million and $68 million for 2010, 2011 and 2012, respectively.

In the foregoing determination of future cash inflows, sales prices for gas and oil were based on contractual arrangements or market prices at year-end. Future costs of developing and producing the proved gas and oil reserves reported at the end of each year shown were based on costs determined at each such year end, assuming the continuation of existing economic conditions. Future income taxes were computed by applying the appropriate year-end or future statutory tax rate to future pretax net cash flows, less the tax basis of the properties involved, and giving effect to tax deductions, permanent differences and tax credits.

It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of our proved reserves. We caution that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves.

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The following tabulation is a summary of changes between the total standardized measure of discounted future net cash flows at the beginning and end of each year:

	2009			2008			2007
(thousands)
Standardized measure of discounted future net cash flows at January 1	$	1,107,549		$	1,443,842		$	4,600,249
Changes in the year resulting from:
Sales and transfers of gas and oil produced during the year, less production costs		(191,974	)		(460,307	)		(732,213	)
Prices and production and development costs related to future production		(953,983	)		(720,764	)		288,780
Extensions, discoveries and other additions, less production and development costs		72,638			128,600			53,722
Previously estimated development costs incurred during the year		132,839			67,000			235,655
Revisions of previous quantity estimates		(36,748	)		170,733			249,049
Accretion of discount		185,178			236,117			180,670
Income taxes		273,181			119,329			1,111,950
Other purchases and sales of proved reserves in place		101			345			(4,530,255	)
Other (principally timing of production)		(2,367	)		122,654			(13,765	)
Standardized measure of discounted future net cash flows at December 31	$	586,414		$	1,107,549		$	1,443,842

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